20-F 1 tm1923634-1_20f.htm 20-F
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549​
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Form 20-F
(Mark One)
☐
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
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OR
☑
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
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OR
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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OR
☐
SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report
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Commission file number: 1-14090
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Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy
(Address of principal executive offices)
Massimo Mondazzi
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
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Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Ordinary shares3,634,185,330
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☑ No ☐
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes ☐ No ☑
Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of  “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Emerging growth company ☐
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP ☐ International Financial Reporting Standards as issued by the International Accounting Standards Board ☒ Other ☐
If  “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ☐ Item 18 ☐
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐ No ☑
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TABLE OF CONTENTS​
TABLE OF CONTENTS

​ | ​ | ​ | ​ | ​ | ​ | Page | ​ | ​
​ | Certain defined terms | ​ | ​ | ​ | ​ | ii | ​ | ​
​ | Presentation of financial and other information | ​ | ​ | ​ | ​ | ii | ​ | ​
​ | Statements regarding competitive position . | ​ | ​ | ​ | ​ | ii | ​ | ​
​ | Glossary . | ​ | ​ | ​ | ​ | iii | ​ | ​
​ | Abbreviations and conversion table | ​ | ​ | ​ | ​ | viii | ​ | ​
​ | PART I | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE . ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | Item 3. KEY INFORMATION ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | Selected Financial Information ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | Selected Operating Information ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​
​ | Risk factors. ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​
​ | Item 4. INFORMATION ON THE COMPANY ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​
​ | History and development of the Company ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​
​ | BUSINESS OVERVIEW ​ | ​ | ​ | ​ | ​ | 33 | ​ | ​
​ | Exploration & Production ​ | ​ | ​ | ​ | ​ | 33 | ​ | ​
​ | Gas & Power . ​ | ​ | ​ | ​ | ​ | 58 | ​ | ​
​ | Refining & Marketing and Chemicals . ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​
​ | Corporate and Other activities . ​ | ​ | ​ | ​ | ​ | 70 | ​ | ​
​ | Research and development . ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​
​ | Insurance . ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​
​ | Environmental matters . ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​
​ | Regulation of Eni’s businesses ​ | ​ | ​ | ​ | ​ | 82 | ​ | ​
​ | Property, plant and equipment . ​ | ​ | ​ | ​ | ​ | 89 | ​ | ​
​ | Organizational structure ​ | ​ | ​ | ​ | ​ | 89 | ​ | ​
​ | Item 4A. UNRESOLVED STAFF COMMENTS . ​ | ​ | ​ | ​ | ​ | 89 | ​ | ​
​ | Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS ​ | ​ | ​ | ​ | ​ | 90 | ​ | ​
​ | Executive summary ​ | ​ | ​ | ​ | ​ | 90 | ​ | ​
​ | Critical accounting estimates ​ | ​ | ​ | ​ | ​ | 95 | ​ | ​
​ | Group results of operations ​ | ​ | ​ | ​ | ​ | 97 | ​ | ​
​ | Liquidity and capital resources ​ | ​ | ​ | ​ | ​ | 105 | ​ | ​
​ | Recent developments ​ | ​ | ​ | ​ | ​ | 109 | ​ | ​
​ | Management’s expectations of operations . ​ | ​ | ​ | ​ | ​ | 110 | ​ | ​
​ | Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES ​ | ​ | ​ | ​ | ​ | 119 | ​ | ​
​ | Directors and Senior Management . ​ | ​ | ​ | ​ | ​ | 119 | ​ | ​
​ | Compensation ​ | ​ | ​ | ​ | ​ | 128 | ​ | ​
​ | Board practices. ​ | ​ | ​ | ​ | ​ | 128 | ​ | ​
​ | Employees ​ | ​ | ​ | ​ | ​ | 140 | ​ | ​
​ | Share ownership ​ | ​ | ​ | ​ | ​ | 141 | ​ | ​
​ | Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​
​ | Major Shareholders ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​
​ | Related party transactions ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​
​ | Item 8. FINANCIAL INFORMATION ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​
​ | Consolidated Statements and other financial information . ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​
​ | Significant changes ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​
​ | Item 9. THE OFFER AND THE LISTING ​ | ​ | ​ | ​ | ​ | 144 | ​ | ​
​ | Offer and listing details ​ | ​ | ​ | ​ | ​ | 144 | ​ | ​
​ | Markets . ​ | ​ | ​ | ​ | ​ | 144 | ​ | ​
​ | Item 10. ADDITIONAL INFORMATION ​ | ​ | ​ | ​ | ​ | 146 | ​ | ​
​ | Memorandum and Articles of Association ​ | ​ | ​ | ​ | ​ | 146 | ​ | ​
​ | Material contracts ​ | ​ | ​ | ​ | ​ | 153 | ​ | ​
​ | Exchange controls ​ | ​ | ​ | ​ | ​ | 153 | ​ | ​
​ | Taxation ​ | ​ | ​ | ​ | ​ | 153 | ​ | ​
​ | Documents on display ​ | ​ | ​ | ​ | ​ | 158 | ​ | ​
​ | Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . ​ | ​ | ​ | ​ | ​ | 159 | ​ | ​
​ | Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​
​ | Item 12A. Debt securities ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​
​ | Item 12B. Warrants and rights ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​
​ | Item 12C. Other securities. ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​
​ | Item 12D. American Depositary Shares . ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​
​ | PART II | ​ | ​
​ | Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES ​ | ​ | ​ | ​ | ​ | 164 | ​ | ​
​ | Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS ​ | ​ | ​ | ​ | ​ | 164 | ​ | ​
​ | Item 15. CONTROLS AND PROCEDURES. ​ | ​ | ​ | ​ | ​ | 164 | ​ | ​
​ | Item 16. [RESERVED] ​ | ​ | ​ | ​ | ​ | 165 | ​ | ​
​ | Item 16A. Board of Statutory Auditors financial expert. ​ | ​ | ​ | ​ | ​ | 165 | ​ | ​
​ | Item 16B. Code of Ethics ​ | ​ | ​ | ​ | ​ | 165 | ​ | ​
​ | Item 16C. Principal accountant fees and services . ​ | ​ | ​ | ​ | ​ | 165 | ​ | ​
​ | Item 16D. Exemptions from the Listing Standards for Audit Committees . ​ | ​ | ​ | ​ | ​ | 167 | ​ | ​
​ | Item 16E. Purchases of equity securities by the issuer and affiliated purchasers ​ | ​ | ​ | ​ | ​ | 167 | ​ | ​
​ | Item 16F. Change in Registrant’s Certifying Accountant ​ | ​ | ​ | ​ | ​ | 167 | ​ | ​
​ | Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual. ​ | ​ | ​ | ​ | ​ | 168 | ​ | ​
​ | Item 16H. Mine safety disclosure . ​ | ​ | ​ | ​ | ​ | 170 | ​ | ​
​ | PART III | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | Item 17. FINANCIAL STATEMENTS. ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​
​ | Item 18. FINANCIAL STATEMENTS. ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​
​ | Item 19. EXHIBITS ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​

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Certain disclosures contained herein including, without limitation, certain information appearing in “Item 4 – Information on the Company”, and in particular “Item 4 – Exploration & Production”, “Item 5 – Operating and Financial Review and Prospects” and “Item 11 – Quantitative and Qualitative Disclosures about Market Risk” contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the “SEC”). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled “Risk factors” and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.
CERTAIN DEFINED TERMS
In this Form 20-F, the terms “Eni”, the “Group”, or the “Company” refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to “Italy” or the “State” are references to the Republic of Italy, all references to the “Government” are references to the government of the Republic of Italy. For definitions of certain oil and gas terms used herein and certain conversions, see “Glossary” and “Conversion Table”.
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
The Consolidated Financial Statements of Eni, included in this Annual Report, have been prepared in accordance with International Financial Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
Unless otherwise indicated, any reference herein to “Consolidated Financial Statements” is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.
Unless otherwise specified or the context otherwise requires, references herein to “dollars”, “$”, “U.S. dollars”, “US$” and “USD” are to the currency of the United States, and references to “euro”, “EUR” and “€” are to the currency of the European Monetary Union.
Unless otherwise specified or the context otherwise requires, references herein to “Division” and “segment” are to any of the following Eni’s business activities: Exploration & Production, Gas & Power, Refining & Marketing and Chemicals, Corporate and Other activities.
References to Versalis or Chemical are to Eni’s chemical activities which are managed through its fully-owned subsidiary Versalis and Versalis’ controlled entities.
STATEMENTS REGARDING COMPETITIVE POSITION
Statements made in “Item 4 – Information on the Company” referring to Eni’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and Eni’s internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.
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GLOSSARY
Below is a selection of the most frequently used terms throughout this Annual Report on Form 20-F. Any reference herein to a non-GAAP measure and to its most directly comparable GAAP measure shall be intended as a reference to a non-IFRS measure and the comparable IFRS measure.

​ | Financial terms | ​ | ​
​ | Leverage | ​ | ​ | A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Ratio of total debt to total shareholders equity (including non-controlling interest)” see “Item 5 – Financial Condition”.​ | ​
​ | Net borrowings | ​ | ​ | Eni evaluates its financial condition by reference to “net borrowings”, which is a non-GAAP measure. Eni calculates net borrowings as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Total debt” see “Item 5 – Financial condition”. | ​
​ | TSR (Total Shareholder Return) | ​ | ​ | Management uses this measure to asses 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 for Electricity Gas and Water) | ​ | ​ | The Italian Regulatory Authority for Energy, Networks and Environment is, the Italian independent body which regulates, controls and monitors the electricity, gas and water sectors and markets in Italy. The Authority’s role and purpose is to protect the interests of users and consumers, promote competition and ensure efficient, cost-effective and profitable nationwide services with satisfactory quality levels. Furthermore, since December 2017 the Authority 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. | ​

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​ | Condensates | ​ | ​ | Condensates is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. | ​
​ | Consob | ​ | ​ | The Italian National Commission for listed companies and the stock exchange.​ | ​
​ | 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. | ​

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​ | 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. | ​
​ | Over/Under lifting | ​ | ​ | Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations. | ​
​ | Plasmix | ​ | ​ | Plasmix is the collective name for the different plastics that currently have no use in the market of recycling and can be used as a feedstock in the new circular economy businesses of Eni. | ​
​ | Possible reserves | ​ | ​ | Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. | ​
​ | Probable reserves | ​ | ​ | Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. | ​
​ | Primary balanced refining capacity | ​ | ​ | Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d. | ​
​ | Production Sharing Agreement (PSA) | ​ | ​ | Contract regulates relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. | ​

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​ | Proved reserves | ​ | ​ | Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.​ | ​
​ | 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. | ​
​ | Take-or-pay | ​ | ​ | Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years. | ​

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​ | 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). | ​

vii

TABLE OF CONTENTS​​
ABBREVIATIONS

​ | mmCF | ​ | ​ | = million cubic feet | ​
​ | BCF | ​ | ​ | = billion cubic feet | ​
​ | mmCM | ​ | ​ | = million cubic meters | ​
​ | BCM | ​ | ​ | = billion cubic meters | ​
​ | BOE | ​ | ​ | = barrel of oil equivalent | ​
​ | KBOE | ​ | ​ | = thousand barrel of oil equivalent | ​
​ | mmBOE | ​ | ​ | = million barrel of oil equivalent | ​
​ | BBOE | ​ | ​ | = billion barrel of oil equivalent | ​
​ | BBL | ​ | ​ | = barrels | ​
​ | KBBL | ​ | ​ | = thousand barrels | ​
​ | mmBBL | ​ | ​ | = million barrels | ​
​ | BBBL | ​ | ​ | = billion barrels | ​
​ | mmBTU | ​ | ​ | = million British thermal unit | ​
​ | ktonnes | ​ | ​ | = thousand tonnes | ​

​ | 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 | ​

​
CONVERSION TABLE

​ | 1 acre | ​ | ​ | = 0.405 hectares | ​ | ​ | ​ | ​
​ | 1 barrel | ​ | ​ | = 42 U.S. gallons | ​ | ​ | ​ | ​
​ | 1 BOE | ​ | ​ | = 1 barrel of crude oil | ​ | ​ | = 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 tonne 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) | ​

viii

TABLE OF CONTENTS​​​​
PART I
Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
NOT APPLICABLE
Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE
Item 3. KEY INFORMATION
Selected Financial Information​
The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB). The tables below present Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2015, 2016, 2017, 2018 and 2019. Effective January 1, 2019 Eni has adopted the new accounting standard “IFRS 16 – Leases”, which has replaced the previous standard IAS 17. 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 and covers a number of Group’s transactions where the Company hires third-party equipment for use in the ordinary course of the business. The new IFRS eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial statements and adopts an accounting model which provides for the recognition of an asset corresponding to the right-of-use and a finance liability of the same amount corresponding to the present value of future expected contractual payments. On initial application, Eni elected to adopt 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, 2019, without restating the comparative information. Information on the implementation of new accounting standards is included in the Financial statements – Note 3 Changes in accounting policies. For further information see also Item 5 – Management’s expectations of operations”.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​ | ​ | 2016 | ​ | ​ | 2015 | ​
​ | ​ | ​ | (€ million except data per share and per ADR)​ | ​
CONSOLIDATED PROFIT STATEMENT DATA | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from continuing operations | ​ | ​ | ​ | ​ | 69,881 | ​ | ​ | ​ | ​ | ​ | 75,822 | ​ | ​ | ​ | ​ | ​ | 66,919 | ​ | ​ | ​ | ​ | ​ | 55,762 | ​ | ​ | ​ | ​ | ​ | 72,286 | ​ | ​
Operating profit (loss) by segment from continuing operations | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exploration & Production | ​ | ​ | ​ | ​ | 7,417 | ​ | ​ | ​ | ​ | ​ | 10,214 | ​ | ​ | ​ | ​ | ​ | 7,651 | ​ | ​ | ​ | ​ | ​ | 2,567 | ​ | ​ | ​ | ​ | ​ | (959) | ​ | ​
Gas & Power | ​ | ​ | ​ | ​ | 699 | ​ | ​ | ​ | ​ | ​ | 629 | ​ | ​ | ​ | ​ | ​ | 75 | ​ | ​ | ​ | ​ | ​ | (391) | ​ | ​ | ​ | ​ | ​ | (1,258) | ​ | ​
Refining & Marketing and Chemicals | ​ | ​ | ​ | ​ | (854) | ​ | ​ | ​ | ​ | ​ | (380) | ​ | ​ | ​ | ​ | ​ | 981 | ​ | ​ | ​ | ​ | ​ | 723 | ​ | ​ | ​ | ​ | ​ | (1,567) | ​ | ​
Corporate and Other activities | ​ | ​ | ​ | ​ | (710) | ​ | ​ | ​ | ​ | ​ | (691) | ​ | ​ | ​ | ​ | ​ | (668) | ​ | ​ | ​ | ​ | ​ | (681) | ​ | ​ | ​ | ​ | ​ | (497) | ​ | ​
Unrealized intragroup profit elimination | ​ | ​ | ​ | ​ | (120) | ​ | ​ | ​ | ​ | ​ | 211 | ​ | ​ | ​ | ​ | ​ | (27) | ​ | ​ | ​ | ​ | ​ | (61) | ​ | ​ | ​ | ​ | ​ | 1,205 | ​ | ​
Operating profit (loss) from continuing operations | ​ | ​ | ​ | ​ | 6,432 | ​ | ​ | ​ | ​ | ​ | 9,983 | ​ | ​ | ​ | ​ | ​ | 8,012 | ​ | ​ | ​ | ​ | ​ | 2,157 | ​ | ​ | ​ | ​ | ​ | (3,076) | ​ | ​
Net profit (loss) attributable to Eni from continuing operations | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 4,126 | ​ | ​ | ​ | ​ | ​ | 3,374 | ​ | ​ | ​ | ​ | ​ | (1,051) | ​ | ​ | ​ | ​ | ​ | (7,952) | ​ | ​
Net profit (loss) attributable to Eni from discontinued operations | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (413) | ​ | ​ | ​ | ​ | ​ | (826) | ​ | ​
Net profit (loss) attributable to Eni | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 4,126 | ​ | ​ | ​ | ​ | ​ | 3,374 | ​ | ​ | ​ | ​ | ​ | (1,464) | ​ | ​ | ​ | ​ | ​ | (8,778) | ​ | ​
Data per ordinary share (euro)(1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net profit (loss) attributable to Eni basic and diluted from continuing operations | ​ | ​ | ​ | ​ | 0.04 | ​ | ​ | ​ | ​ | ​ | 1.15 | ​ | ​ | ​ | ​ | ​ | 0.94 | ​ | ​ | ​ | ​ | ​ | (0.29) | ​ | ​ | ​ | ​ | ​ | (2.21) | ​ | ​
Net profit (loss) attributable to Eni basic and diluted from discontinued operations | ​ | ​ | ​ | ​ | 0.00 | ​ | ​ | ​ | ​ | ​ | 0.00 | ​ | ​ | ​ | ​ | ​ | 0.00 | ​ | ​ | ​ | ​ | ​ | (0.12) | ​ | ​ | ​ | ​ | ​ | (0.23) | ​ | ​
Net profit (loss) attributable to Eni basic and diluted | ​ | ​ | ​ | ​ | 0.04 | ​ | ​ | ​ | ​ | ​ | 1.15 | ​ | ​ | ​ | ​ | ​ | 0.94 | ​ | ​ | ​ | ​ | ​ | (0.41) | ​ | ​ | ​ | ​ | ​ | (2.44) | ​ | ​
Data per ADR​ ($)(1) (2)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net profit (loss) attributable to Eni basic and diluted from continuing operations | ​ | ​ | ​ | ​ | 0.09 | ​ | ​ | ​ | ​ | ​ | 2.72 | ​ | ​ | ​ | ​ | ​ | 2.12 | ​ | ​ | ​ | ​ | ​ | (0.65) | ​ | ​ | ​ | ​ | ​ | (4.90) | ​ | ​
Net profit (loss) attributable to Eni basic and diluted from discontinued operations | ​ | ​ | ​ | ​ | 0.00 | ​ | ​ | ​ | ​ | ​ | 0.00 | ​ | ​ | ​ | ​ | ​ | 0.00 | ​ | ​ | ​ | ​ | ​ | (0.25) | ​ | ​ | ​ | ​ | ​ | (0.51) | ​ | ​
Net profit (loss) attributable to Eni basic and diluted | ​ | ​ | ​ | ​ | 0.09 | ​ | ​ | ​ | ​ | ​ | 2.72 | ​ | ​ | ​ | ​ | ​ | 2.12 | ​ | ​ | ​ | ​ | ​ | (0.90) | ​ | ​ | ​ | ​ | ​ | (5.41) | ​ | ​

​
(1)
Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2019 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2020.
​
(2)
Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented. Dividends per ADR for the years 2015 through 2018 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively. The dividend for 2019 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim
​
1

TABLE OF CONTENTS
dividend (€0.86 per ADR) at the Noon Buying Rate recorded on the payment date on September 25, 2019, while the balance of €0.86 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2019. The balance dividend for 2019 once the full-year dividend is approved by the Annual General Shareholders’Meeting is payable on May 20, 2020 to holders of Eni shares, being the ex-dividend date May 18, 2020 while ADRs holders will be paid on June 4, 2020.

​ | ​ | ​ | As of December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​ | ​ | 2016 | ​ | ​ | 2015 | ​
​ | ​ | ​ | (€ million except data per share and per ADR)​ | ​
CONSOLIDATED BALANCE SHEET DATA | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total assets | ​ | ​ | ​ | ​ | 123,440 | ​ | ​ | ​ | ​ | ​ | 118,373 | ​ | ​ | ​ | ​ | ​ | 114,928 | ​ | ​ | ​ | ​ | ​ | 124,545 | ​ | ​ | ​ | ​ | ​ | 139,001 | ​ | ​
Finance debt (short-term and long-term debt) and lease liabilities | ​ | ​ | ​ | ​ | 30,166 | ​ | ​ | ​ | ​ | ​ | 25,865 | ​ | ​ | ​ | ​ | ​ | 24,707 | ​ | ​ | ​ | ​ | ​ | 27,239 | ​ | ​ | ​ | ​ | ​ | 27,793 | ​ | ​
Capital stock issued | ​ | ​ | ​ | ​ | 4,005 | ​ | ​ | ​ | ​ | ​ | 4,005 | ​ | ​ | ​ | ​ | ​ | 4,005 | ​ | ​ | ​ | ​ | ​ | 4,005 | ​ | ​ | ​ | ​ | ​ | 4,005 | ​ | ​
Non-controlling interest | ​ | ​ | ​ | ​ | 61 | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 1,916 | ​ | ​
Shareholders’ equity – Eni share | ​ | ​ | ​ | ​ | 47,839 | ​ | ​ | ​ | ​ | ​ | 51,016 | ​ | ​ | ​ | ​ | ​ | 48,030 | ​ | ​ | ​ | ​ | ​ | 53,037 | ​ | ​ | ​ | ​ | ​ | 55,493 | ​ | ​
Capital expenditures from continuing operations | ​ | ​ | ​ | ​ | 8,376 | ​ | ​ | ​ | ​ | ​ | 9,119 | ​ | ​ | ​ | ​ | ​ | 8,681 | ​ | ​ | ​ | ​ | ​ | 9,180 | ​ | ​ | ​ | ​ | ​ | 10,741 | ​ | ​
Weighted average number of ordinary shares outstanding (fully diluted – shares million) | ​ | ​ | ​ | ​ | 3,592 | ​ | ​ | ​ | ​ | ​ | 3,601 | ​ | ​ | ​ | ​ | ​ | 3,601 | ​ | ​ | ​ | ​ | ​ | 3,601 | ​ | ​ | ​ | ​ | ​ | 3,601 | ​ | ​
Dividend per share (euro)(1) | ​ | ​ | ​ | ​ | 0.86 | ​ | ​ | ​ | ​ | ​ | 0.83 | ​ | ​ | ​ | ​ | ​ | 0.80 | ​ | ​ | ​ | ​ | ​ | 0.80 | ​ | ​ | ​ | ​ | ​ | 0.80 | ​ | ​
Dividend per ADR ($)(1) (2) | ​ | ​ | ​ | ​ | 1.93 | ​ | ​ | ​ | ​ | ​ | 1.96 | ​ | ​ | ​ | ​ | ​ | 1.81 | ​ | ​ | ​ | ​ | ​ | 1.77 | ​ | ​ | ​ | ​ | ​ | 1.77 | ​ | ​

​
(1)
Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2019 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2020.
​
(2)
Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented. Dividends per ADR for the years 2015 through 2018 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively. The dividend for 2019 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (€0.86 per ADR) at the Noon Buying Rate recorded on the payment date on September 25, 2019, while the balance of €0.86 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2019. The balance dividend for 2019 once the full-year dividend is approved by the Annual General Shareholders’Meeting is payable on May 20, 2020 to holders of Eni shares, being the ex-dividend date May 18, 2020 while ADRs holders will be paid on June 4, 2020.
​
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TABLE OF CONTENTS​
Selected Operating Information
The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2015, 2016, 2017, 2018 and 2019. In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. From January 1, 2019, as part of an ongoing review of the yields at the Company’s gas fields currently in production, Eni has updated the conversion rate of gas to 5,408 cubic feet of gas equals 1 barrel of oil (it was 5,458 cubic feet of gas per barrel in previous reporting periods). The effect of this update on production expressed in BOE was 9 kBOE/d for the full year 2019 and the change in the initial reserves balance as of January 1, 2019 amounted to 34 mmBOE. Prior-year converted amounts were left unchanged. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depreciation and depletion charges. Other oil companies may use different conversion rates.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​ | ​ | 2016 | ​ | ​ | 2015 | ​
Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL) | ​ | ​ | ​ | ​ | 3,124 | ​ | ​ | ​ | ​ | ​ | 3,183 | ​ | ​ | ​ | ​ | ​ | 3,262 | ​ | ​ | ​ | ​ | ​ | 3,230 | ​ | ​ | ​ | ​ | ​ | 3,372 | ​ | ​
of which developed | ​ | ​ | ​ | ​ | 2,219 | ​ | ​ | ​ | ​ | ​ | 2,208 | ​ | ​ | ​ | ​ | ​ | 2,220 | ​ | ​ | ​ | ​ | ​ | 2,190 | ​ | ​ | ​ | ​ | ​ | 2,100 | ​ | ​
Proved reserves of liquids of equity-accounted entities at period end (mmBBL) | ​ | ​ | ​ | ​ | 477 | ​ | ​ | ​ | ​ | ​ | 357 | ​ | ​ | ​ | ​ | ​ | 160 | ​ | ​ | ​ | ​ | ​ | 168 | ​ | ​ | ​ | ​ | ​ | 187 | ​ | ​
of which developed | ​ | ​ | ​ | ​ | 269 | ​ | ​ | ​ | ​ | ​ | 205 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | 48 | ​ | ​
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) | ​ | ​ | ​ | ​ | 17,111 | ​ | ​ | ​ | ​ | ​ | 17,324 | ​ | ​ | ​ | ​ | ​ | 17,290 | ​ | ​ | ​ | ​ | ​ | 18,462 | ​ | ​ | ​ | ​ | ​ | 14,302 | ​ | ​
of which developed | ​ | ​ | ​ | ​ | 12,070 | ​ | ​ | ​ | ​ | ​ | 11,203 | ​ | ​ | ​ | ​ | ​ | 9,535 | ​ | ​ | ​ | ​ | ​ | 9,244 | ​ | ​ | ​ | ​ | ​ | 8,899 | ​ | ​
Proved reserves of natural gas of equity-accounted entities at period end (BCF) | ​ | ​ | ​ | ​ | 2,721 | ​ | ​ | ​ | ​ | ​ | 2,400 | ​ | ​ | ​ | ​ | ​ | 2,182 | ​ | ​ | ​ | ​ | ​ | 3,871 | ​ | ​ | ​ | ​ | ​ | 3,993 | ​ | ​
of which developed | ​ | ​ | ​ | ​ | 2,347 | ​ | ​ | ​ | ​ | ​ | 2,063 | ​ | ​ | ​ | ​ | ​ | 1,916 | ​ | ​ | ​ | ​ | ​ | 1,905 | ​ | ​ | ​ | ​ | ​ | 1,402 | ​ | ​
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end | ​ | ​ | ​ | ​ | 6,287 | ​ | ​ | ​ | ​ | ​ | 6,356 | ​ | ​ | ​ | ​ | ​ | 6,430 | ​ | ​ | ​ | ​ | ​ | 6,613 | ​ | ​ | ​ | ​ | ​ | 5,975 | ​ | ​
of which developed | ​ | ​ | ​ | ​ | 4,450 | ​ | ​ | ​ | ​ | ​ | 4,261 | ​ | ​ | ​ | ​ | ​ | 3,967 | ​ | ​ | ​ | ​ | ​ | 3,884 | ​ | ​ | ​ | ​ | ​ | 3,720 | ​ | ​
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end | ​ | ​ | ​ | ​ | 981 | ​ | ​ | ​ | ​ | ​ | 797 | ​ | ​ | ​ | ​ | ​ | 560 | ​ | ​ | ​ | ​ | ​ | 877 | ​ | ​ | ​ | ​ | ​ | 915 | ​ | ​
of which developed | ​ | ​ | ​ | ​ | 704 | ​ | ​ | ​ | ​ | ​ | 583 | ​ | ​ | ​ | ​ | ​ | 394 | ​ | ​ | ​ | ​ | ​ | 391 | ​ | ​ | ​ | ​ | ​ | 303 | ​ | ​
Average daily production of liquids (KBBL/d) (1) | ​ | ​ | ​ | ​ | 890 | ​ | ​ | ​ | ​ | ​ | 884 | ​ | ​ | ​ | ​ | ​ | 852 | ​ | ​ | ​ | ​ | ​ | 878 | ​ | ​ | ​ | ​ | ​ | 908 | ​ | ​
Average daily production of natural gas available for sale (mmCF/d) ﻿(1) | ​ | ​ | ​ | ​ | 4,576 | ​ | ​ | ​ | ​ | ​ | 4,630 | ​ | ​ | ​ | ​ | ​ | 4,734 | ​ | ​ | ​ | ​ | ​ | 4,329 | ​ | ​ | ​ | ​ | ​ | 4,284 | ​ | ​
Average daily production of hydrocarbons available for sale (KBOE/d) ﻿(1) | ​ | ​ | ​ | ​ | 1,736 | ​ | ​ | ​ | ​ | ​ | 1,732 | ​ | ​ | ​ | ​ | ​ | 1,719 | ​ | ​ | ​ | ​ | ​ | 1,671 | ​ | ​ | ​ | ​ | ​ | 1,688 | ​ | ​
Hydrocarbon production sold (mmBOE) | ​ | ​ | ​ | ​ | 630.6 | ​ | ​ | ​ | ​ | ​ | 625.0 | ​ | ​ | ​ | ​ | ​ | 622.3 | ​ | ​ | ​ | ​ | ​ | 608.6 | ​ | ​ | ​ | ​ | ​ | 614.1 | ​ | ​
Oil and gas production costs per BOE(2) | ​ | ​ | ​ | ​ | 6.05 | ​ | ​ | ​ | ​ | ​ | 6.50 | ​ | ​ | ​ | ​ | ​ | 6.33 | ​ | ​ | ​ | ​ | ​ | 5.90 | ​ | ​ | ​ | ​ | ​ | 9.18 | ​ | ​
Profit per barrel of oil equivalent(3) | ​ | ​ | ​ | ​ | 5.06 | ​ | ​ | ​ | ​ | ​ | 9.27 | ​ | ​ | ​ | ​ | ​ | 8.72 | ​ | ​ | ​ | ​ | ​ | 1.98 | ​ | ​ | ​ | ​ | ​ | (3.83) | ​ | ​

​
(1)
Referred to Eni’s subsidiaries and its equity-accounted entities. It excludes production volumes of hydrocarbon consumed in operation (124, 119, 97, 88 and 73 KBOE/d in 2019, 2018, 2017, 2016 and 2015 respectively).
​
(2)
Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements”. Oil and gas production costs per BOE exclude transportation costs relating to the export of the saleable volumes of oil and gas produced, other than the costs incurred to deliver hydrocarbons to a main pipeline, a common carrier, a refinery or a maritime terminal, when unusual physical or operational circumstances exist. If calculated before IFRS 16 adoption, the average production cost for the year 2019 would be $6.60 per boe. Other per-BOE indicators were only marginally affected.
​
(3)
Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements” for a calculation of results of operations from oil and gas producing activities.
​
3

TABLE OF CONTENTS​
Selected Operating Information continued

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​ | ​ | 2016 | ​ | ​ | 2015 | ​
Worldwide natural gas sales(1) | ​ | ​ | ​ | ​ | 73.07 | ​ | ​ | ​ | ​ | ​ | 76.71 | ​ | ​ | ​ | ​ | ​ | 80.83 | ​ | ​ | ​ | ​ | ​ | 86.31 | ​ | ​ | ​ | ​ | ​ | 87.72 | ​ | ​
Electricity sold(2) | ​ | ​ | ​ | ​ | 39.49 | ​ | ​ | ​ | ​ | ​ | 37.07 | ​ | ​ | ​ | ​ | ​ | 35.33 | ​ | ​ | ​ | ​ | ​ | 37.05 | ​ | ​ | ​ | ​ | ​ | 34.88 | ​ | ​
Refinery throughputs(3) | ​ | ​ | ​ | ​ | 22.74 | ​ | ​ | ​ | ​ | ​ | 23.23 | ​ | ​ | ​ | ​ | ​ | 24.02 | ​ | ​ | ​ | ​ | ​ | 24.52 | ​ | ​ | ​ | ​ | ​ | 26.41 | ​ | ​
Balanced capacity of wholly-owned refineries(4) | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​
Retail sales (in Italy and rest of Europe)(3) | ​ | ​ | ​ | ​ | 8.25 | ​ | ​ | ​ | ​ | ​ | 8.39 | ​ | ​ | ​ | ​ | ​ | 8.54 | ​ | ​ | ​ | ​ | ​ | 8.59 | ​ | ​ | ​ | ​ | ​ | 8.89 | ​ | ​
Number of service stations at period end (in Italy and rest of Europe) | ​ | ​ | ​ | ​ | 5,411 | ​ | ​ | ​ | ​ | ​ | 5,448 | ​ | ​ | ​ | ​ | ​ | 5,544 | ​ | ​ | ​ | ​ | ​ | 5,622 | ​ | ​ | ​ | ​ | ​ | 5,846 | ​ | ​
Chemical production(3) | ​ | ​ | ​ | ​ | 8.07 | ​ | ​ | ​ | ​ | ​ | 9.48 | ​ | ​ | ​ | ​ | ​ | 8.96 | ​ | ​ | ​ | ​ | ​ | 8.81 | ​ | ​ | ​ | ​ | ​ | 8.67 | ​ | ​
Average throughput per service station (in Italy and rest of Europe)﻿(5) | ​ | ​ | ​ | ​ | 1,766 | ​ | ​ | ​ | ​ | ​ | 1,776 | ​ | ​ | ​ | ​ | ​ | 1,783 | ​ | ​ | ​ | ​ | ​ | 1,742 | ​ | ​ | ​ | ​ | ​ | 1,754 | ​ | ​
Employees at period end (number) | ​ | ​ | ​ | ​ | 32,053 | ​ | ​ | ​ | ​ | ​ | 31,701 | ​ | ​ | ​ | ​ | ​ | 32,934 | ​ | ​ | ​ | ​ | ​ | 33,536 | ​ | ​ | ​ | ​ | ​ | 34,196 | ​ | ​

​
(1)
Expressed in BCM.
​
(2)
Expressed in TWh.
​
(3)
Expressed in mmtonnes.
​
(4)
Expressed in KBBL/d.
​
(5)
Expressed in thousand liters per day.
​
Risk factors
The Company’s performance is affected by volatile prices of crude oil and produced natural gas and by fluctuating margins on the marketing of natural gas and on the integrated production and marketing of refined products and chemical products
The price of crude oil is the single, largest variable that affects the Company’s performance. Because it is a commodity business, the price of crude oil has a history of volatility and is influenced by a number of macro-factors that are beyond management’s control. Crude oil prices are mainly driven by the balance between global oil supplies and demand and hence the global levels of inventories and spare capacity. Worldwide demand for crude oil is highly correlated to the macroeconomic cycle. A downturn in economic activity normally triggers lower global demand for crude oil and possibly a supply build-up. Whenever global supplies of crude oil outstrip demand, crude oil prices weaken. Other factors which influence demand for crude oil are demographic growth and improving living standards, prices and availability of alternative sources of energy (e.g., nuclear and renewables), technological advances affecting energy efficiency, measures which have been adopted or planned by governments all around the world to fight global warming, including stricter regulations and control on production and consumption of crude oil, or a shift in consumer preferences. The push to reduce worldwide greenhouse gas emissions and an ongoing energy transition towards a low carbon economy, which are widely considered to be irreversible trends, will represent in our view major trends in shaping global demand and supplies of crude oil over the long-term and may lead to lower crude oil demands and consumption; see the section dedicated to the discussion of climate-related risks below. Furthermore, oil demand is subject to several, unpredictable events. Geopolitical tensions, local conflicts, terrorism, attacks, social instability, widespread civil unrest, pandemic diseases could dent consumers’ confidence, economic growth and hence global demand for oil.
Historically, the OPEC cartel and lately the OPEC+ agreement, which includes OPEC members and other important oil producers like Russia, have exerted a big influence over global supplies of crude oil and crude oil prices. Saudi Arabia plays a crucial role within the cartel, because it is estimated to hold huge amounts of reserves and a vast majority of worldwide spare production capacity. This explains why geopolitical developments in the Middle East and particularly in the Gulf area, like regional conflicts, acts of war, strikes, attacks, sabotages and social and political tensions can have a big influence on crude oil prices. Also, sanctions imposed by the USA and the EU against certain producing countries may influence trends in crude oil prices. However, we believe that the resurgence of oil production in the USA due to the technology-driven shale oil revolution has somewhat reduced the ability of OPEC to control the global supply of oil. To a lesser extent, factors like adverse weather conditions and operational issues at key petroleum infrastructure can influence crude oil prices.
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The price of crude oil has been on a downtrend for the last six years, shedding more than two thirds of its value in this timeframe (from approximately 110 $/BBL in 2014 to the current level below 30 $/BBL as of end of March 2020). The development has been mainly driven by a supply glut fuelled by continued grow in the production of tight oil in the USA and the need of US independent producers to recover their investments, at a time when the pace of increase in crude oil demand has moderated. These trends have been exacerbated by the adverse developments recorded in the first quarter 2020 (see below). At the beginning of 2019, crude oil prices rebounded somewhat from another stage of the down cycle recorded in the final part of 2018, when the price of the Brent crude oil benchmark fell to around 50 $/barrel (Source: Platt’s Oilgram), supported by the production cuts implemented by the OPEC+ agreement and by production losses for Venezuela and Iran due to geopolitical factors. Brent prices peaked at 75 $/barrel in April 2019. Then, a new downward trend commenced pushing crude oil price down to the mid-$50 range during the summer months of 2019. The correction was driven by a global economic slowdown impacting fuel demand, uncertainties relating to the developments of the United States-China trade dispute and Brexit, and building oversupplies due to rising production levels in the United States and elsewhere. Against this backdrop, the September 2019 air attacks against strategic oil facilities in Saudi Arabia, which were of unprecedented reach and scale and caused a massive albeit temporary production loss, had little effects on crude oil prices because due to large worldwide supplies, no significant disruptions occurred in the marketplace and after a brief spike, crude oil prices reverted to then ongoing downtrend.
In the last part of 2019 and the beginning of 2020, crude oil prices tried to rebound, supported by the renewal of the OPEC+ agreement through the end of March 2020, which provided an increase of 500 KBBL/d in the production cuts to the target of 1.7 million BBL/d, with Saudi Arabia committing itself to cut its production quota by a further 400 KBBL/d. Other factors supportive of crude oil prices were the resurgence of geopolitical tensions in the Gulf area, a de-escalation in the trade dispute between the USA and China and early signs of a strengthening global economy. As a result of these trends, in 2019 the price for the Brent crude oil benchmark averaged 64 $/barrel, 9% lower than in 2018.
After a solid start in 2020 with Brent prices rising up to 65 $/​barrel, crude oil prices took a hit due to a sudden drop in demand triggered by the outbreak of a pandemic disease known as COVID-19 spreading from China to other countries around the world. The sell-off intensified through February and early March 2020 as governments across the globe stepped up efforts to contain the virus, impacting economic activity and travel. In early March 2020, members of the OPEC+ agreement failed to reach a deal for additional production cuts claimed by some members to counteract the COVID-19 effects. These developments triggered a collapse in crude oil prices. The price of the Brent crude benchmark has fallen by more 50% from the value recorded before the onset of the disease at more than 65 $/bbl in early January 2020. Depending on how the current COVID-19 crisis unfolds, on how long it takes to contain the virus and on the severity of an ensuing economic downturn, as well as on future developments regarding the willingness of the OPEC+ agreement to support crude oil prices, the ongoing developments could materially and negatively affect the outlook for the Company, its results of operations, cash flow and business prospects including shareholders' returns and the price of Eni's share. More information is disclosed in Item 5 – Management expectations of operations.
Management expects oil demand growth to remain subdued in 2020 and possibly to decline due to the effects of COVID-19 on global economic activity and travel. For the medium term, management expects global oil demand to resume growing at a rate in line with historical averages. Global crude oil supplies are expected to grow at a moderate pace. International oil companies are expected to retain a selective approach to investment decisions due to cash flow considerations and also the growth rate in the production of tight oil in the USA is expected to slow down due to greater focus on capital discipline by US independent upstreamers. The cohesion of OPEC+ alliance is a factor of uncertainty to the global balance between supplies and demand.
Lower prices from one year to another negatively affect the Group’s consolidated results of operations and cash flow. This is because lower oil prices translate into lower revenues recognised in the Company’s Exploration & Production segment at the time of the price change, whereas expenses in this segment are either fixed or less sensitive to changes in crude oil prices than revenues. Based on the current portfolio of oil and gas assets, Eni’s management estimates that the Company’s consolidated net cash provided by operating activities would vary by approximately €0.15 billion 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.
The price of natural gas generally follows a trend similar to that of crude oil, but it can also exhibit greater movements either upward or downward. In 2019, due to a combination of factors including lower gas demand in Asia due to the downturn and a recovery in Japan’s nuclear power production, larger global
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supplies of LNG, mild global temperatures and increased US production, gas prices at the main worldwide markets fell by a far bigger amount than crude oil prices. For example, the price of gas at the Italian spot market against which the realized price of our equity gas production in Europe is benchmarked, declined by 34% compared to 9% for the price of crude oil.
In 2019, the Company estimated that lower hydrocarbon prices negatively affected the Exploration & Production operating profit for approximately €2.23 billion, with the large majority of this loss deriving from lower gas prices.
Lower oil and gas prices over prolonged periods of time or, in the worst of the scenarios, a structural decline in oil and gas prices may have material adverse effects on Eni’s performance and business outlook, because such a scenario may limit the Group’s funds available to finance expansion projects, further reducing the Company’s ability to grow future production and revenues, and to discharge contractual obligations. The Company may also need to review investment decisions and the viability of development projects and capex plans and, as a result of this review, the Company could reschedule, postpone or curtail development projects. A structural decline in hydrocarbon prices could trigger a review of the carrying amounts of oil and gas properties and this could result in recording material asset impairments and also could result in the de-booking of proved reserves, if they become uneconomic in this type of environment. Finally, in response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions, lower commodity prices may also reduce the Group’s access to capital and lead to a downgrade or other negative rating action with respect to the Group’s credit rating by rating agencies. These downgrades may negatively affect the Group’s cost of capital, increase the Group’s financial expenses, and may limit the Group’s ability to access capital markets and execute aspects of the Group’s business plans. All of these risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Eni estimates that approximately 50% of its current production is exposed to fluctuations in hydrocarbons prices. Exposure to this strategic risk is not subject to economic hedging, except for some specific market conditions or transactions. The remaining portion of Eni’s current production is largely unaffected by crude oil price movements considering that the Company’s property portfolio is characterised by a sizeable presence of production sharing contracts, whereby the Company is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditure and hence production, and vice versa. If oil prices differ significantly from Eni’s own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.
Margins on the production and sale of fuels and other refined products, chemical commodities, other energy commodities and in the wholesale marketing of natural gas are driven by economic growth, global and regional dynamics in supplies and demands and other competitive factors. Generally speaking, the prices of products mirror that of oil-based feedstock, but they can also move independently. Margins for refined and chemical products depend upon the speed at which products’ prices adjust to reflect movements in oil prices. Margins at our business of wholesale marketing of natural gas are driven by the spreads between spot prices at continental hubs to which our procurement costs are indexed and the spot prices at the Italian hub where a large part of our gas sales occur. These spreads can be very volatile.
There is strong competition worldwide, both within the oil industry and with other industries, to supply energy and petroleum products to the industrial, commercial and residential energy markets
Eni faces strong competition in each of its business segments.
The current competitive environment in which Eni operates is characterised by volatile prices and margins of energy commodities, limited product differentiation and complex relationships with state-owned companies and national agencies of the countries where hydrocarbons reserves are located to obtain mineral rights. As commodity prices are beyond the Company’s control, Eni’s ability to remain competitive and profitable in this environment requires continuous focus on technological innovation, the achievement of efficiencies in operating costs, effective management of capital resources and the ability to provide valuable services to energy buyers. It also depends on Eni’s ability to gain access to new investment opportunities, both in Europe and worldwide.
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In the Exploration & Production segment, Eni is facing competition from both international and state-owned oil companies for obtaining exploration and development rights, and developing and
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applying new technologies to maximise hydrocarbon recovery. Because of its smaller size relative to other international oil companies, Eni may face a competitive disadvantage when bidding for large scale or capital intensive projects and it may be exposed to the risk of obtaining lower cost savings in a deflationary environment compared to its larger competitors given its potentially smaller market power with respect to suppliers. Due to those competitive pressures, Eni may fail to obtain new exploration and development acreage, to apply and develop new technologies and to control costs.
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In the Gas & Power segment, Eni is facing strong competition in the European wholesale gas markets to sell gas to industrial customers, the thermoelectric sector and retailer companies from other gas wholesalers, upstream companies, traders and other players both in the Italian market and in markets across Europe. In recent years, competition has been fuelled by muted demand growth, oversupplies and the development of very liquid European spot markets where large volumes of gas are traded daily. Players are competing mainly in terms of pricing and, to a lesser extent, on the ability to offer additional services to the buyers of the commodity, like volume flexibilities, different pricing options, the possibility to change the delivery point and other optionality. Eni’s Gas & Power segment also engages in the supply of gas and electricity to customers in the retail markets mainly in Italy, France and other countries in Europe. Customers include households, large residential accounts (hospitals, schools, public administration buildings, offices) and small and medium-sized businesses located in urban areas. The retail market is characterised by strong competition among local selling companies which mainly compete in term of pricing and the ability to bundle valuable services to the supply of the energy commodity. In this segment, competition has intensified in recent years due to the progressive liberalisation of the market and the option on part of residential customers to switch smoothly from one supplier to another. Management believes that competition in the European wholesale and retail gas markets will continue to negatively affect the performance of Eni’s Gas & Power segment in future reporting periods.
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Eni is facing strong competitive pressure in its business of gas-fired electricity generation which is largely sold in wholesale markets in Italy. Margins on the sale of electricity have declined in recent years due to oversupplies, weak economic growth and inter-fuel competition. Management believes that these factors will continue to negatively affect crack-spread margins on electricity at Italian wholesale markets and the profitability of this business unit in the foreseeable future.
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In the Refining & Marketing segment, Eni is facing competition both in refining business and in the retail marketing activity. Refining business, in recent years has been negatively affected by a number of structural headwinds due to muted trends in the European demand for fuels and continued competitive pressure from players in the Middle East, the United States and Far East Asia. Those competitors can leverage on larger plant scale and cost economies, availability of cheaper feedstock and lower energy expenses. Eni believes that the competitive environment of the refining sector will remain challenging in the foreseeable future, also considering refining overcapacity in the European area and expectations of a new investment cycle driven by capacity expansion plans announced in Asia and the Middle East, potentially leading to a situation of global oversupplies of refinery products. Furthermore, Eni’s refining margins are exposed to the volatility in the spreads between crudes with high sulphur content or sour crudes and the Brent crude benchmark, which is a low-content sulphur crude. Eni complex refineries are able to process sour crudes which typically trade at a discount over the Brent crude. Historically, this discount has supported the profitability of complex refineries, like our plant at Sannazzaro in Italy. However, in the course of 2019, a shortfall in supplies of sour crudes due to the production cuts implemented by OPEC, lower exports from Venezuela and the United States’ sanctions against Iran, drove an appreciation of the relative prices of sour crudes as compared to the Brent, which negatively affected the results of our refining business by reducing the advantage of processing sour crudes. This development triggered a revision of the profitability outlook of our complex plants, resulting in the recording of an impairment loss of approximately €684 million at our high-conversion Sannazzaro refinery. Our business of marketing refined products to our service stations network and to large accounts customer (aviation airlines, public administrations, transport and industrial customers, bulk buyers and resellers) is facing competition from other oil companies and newcomers such as low-scale and local operators, un-branded networks with light cost structure. All these operators compete with each other primarily in terms of pricing and, to a lesser extent, service quality.
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In the Chemical business, Eni is facing strong competition from well-established international
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players and state-owned petrochemical companies, particularly in the most commoditised market segments such as the production of basic petrochemical products (like ethylene and polyethylene), whose demand is a function of macroeconomic growth. Many of these competitors based in the Far East and the Middle East are able to benefit from cost economies due to larger plant scale, wide geographic moat, availability of cheap feedstock and proximity to end-markets. Excess worldwide capacity of petrochemical commodities has also fuelled competition in this business. Furthermore, petrochemical producers based in the United States have regained market share, as their cost structure has become competitive due to the availability of cheap feedstock deriving from the production of domestic shale gas from which ethane is derived, which is a cheaper raw material for the production of ethylene than the oil-based feedstock utilised by Eni’s petrochemical subsidiaries. Finally, rising public concern about the climate change and the preservation of the environment has begun to negatively affect the consumption of single-use plastics. In 2019, the operating performance of the Eni’s Chemical business was negative due lower demand from end-user markets, particularly the automotive market, reflecting a global economic slowdown and lower demand for single-use plastics driven by stricter regulations and rising environmental sensitivity. The effects of those trends were exacerbated by the above mentioned competitive dynamics, resulting in a continued pressure on petrochemical products margins. The Company does not expect any meaningful improvement in the trading environment in the short to the medium-term due to competitive headwinds described above and expectations for moderate economic growth.
In case the Company is unable to effectively manage the above described risks deriving from the competition in its business segments, they may 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.
Safety, security, environmental and other operational risks
The Group engages in the exploration and production of oil and natural gas, processing, transportation and refining of crude oil, transport of natural gas, storage and distribution of petroleum products and the production of base chemicals, plastics and elastomers. By their nature, the Group’s operations expose Eni to a wide range of significant health, safety, security and environmental risks. Technical faults, malfunctioning of plants, equipment and facilities, control systems failure, human errors, acts of sabotage, attacks, loss of containment and adverse weather events can trigger damaging consequences such as explosions, blow-outs, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants and pollutants in the air, the ground and in the water, toxic emissions and other negative events. The magnitude of these risks is influenced by the geographic range, operational diversity and technical complexity of Eni’s activities. Eni’s future results of operations and liquidity depend on its ability to identify and address the risks and hazards inherent to operating in those industries.
In the Exploration & Production segment, Eni faces natural hazards and other operational risks including those relating to the physical and geological characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni’s personnel and risks of blowout, fire or explosion.
Eni’s activities in the Refining & Marketing and Chemical segment entail health, safety and environmental risks related to the handling, transformation and distribution of oil, oil products and certain petrochemical products. These risks can arise from the intrinsic characteristics and the overall life cycle of the products manufactured and the raw materials used in the manufacturing process, such as oil-based feedstock, catalysts, additives and monomer feedstock. These risks comprise flammability, toxicity, long-term environmental impact such as greenhouse gas emissions and risks of various forms of pollution and contamination of the soil and the groundwater, emissions and discharges resulting from their use and from recycling or disposing of materials and wastes at the end of their useful life.
All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend both on the hazardous nature of the products transported, and on the transportation methods used (mainly pipelines, shipping, river freight, rail, road and gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, could present a significant risk to people, the environment and the property.
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Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2019, approximately 60% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Angola, Norway, Congo, Indonesia, the United Arab Emirates, Italy, Ghana, Venezuela, the United Kingdom, Nigeria and the United States. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. Offshore accidents and spills could cause damage of catastrophic proportions to the ecosystem and health and security of people due to objective difficulties in handling hydrocarbons containment, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Furthermore, offshore operations are subject to marine risks, including storms and other adverse weather conditions and vessel collisions, as well as interruptions or termination by governmental authorities based on safety, environmental and other considerations.
The Company has invested and will continue to invest significant financial resources to continuously upgrade the methods and systems for safeguarding the reliability of its plants, production facilities, transport and storage infrastructures, the safety and the health of its employees, contractors, local communities and the environment; to prevent risks; to comply with applicable laws and policies and to respond to and learn from unforeseen incidents. Eni seeks to manage these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and other facilities, and managing its operations in a safe and reliable manner and in compliance with all applicable rules and regulations, as well as with best available techniques. However, these measures may not ultimately be completely successful in protecting against those risks. Failure to manage these risks could cause unforeseen incidents, including releases or oil spills, blowouts, fire, mechanical failures and other incidents, all of which could lead to loss of life, damage or destruction to properties, environmental damage, legal liabilities and/or damage claims and consequently a disruption in operations and potential economic losses that could have a material and adverse effect on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Eni’s operations are often conducted in difficult and/or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic. In such locations, the consequences of any incident could be greater than in other locations. Eni also faces risks once production is discontinued, because Eni’s activities require the decommissioning of productive infrastructures and environmental sites remediation and clean-up. Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks. Eni retains worldwide third-party liability insurance coverage, which is designed to hedge part of the liabilities associated with damage to third parties, loss of value to the Group’s assets related to unfavourable events and in connection with environmental clean-up and remediation. As of the date of this filing, maximum compensation allowed under such insurance coverage is equal to $1.2 billion in case of offshore incident and $1.4 billion in case of incident at onshore facilities (refineries). Additionally, the Company may also activate further insurance coverage in case of specific capital projects and other industrial initiatives. Management believes that its insurance coverage is in line with industry practice and is sufficient to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster, such as the incident which occurred at the Macondo well in the Gulf of Mexico several years ago, for example, Eni’s third-party liability insurance would not provide any material coverage and thus the Company’s liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in the event of such a disaster would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such a loss would not have a material adverse effect on the Company. The occurrence of the above mentioned risks could have a material and adverse impact on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share and could also damage the Group’s reputation.
Rising public concern related to climate change has led and could continue to lead to the adoption of national and international laws and regulations which are expected to result in a decrease of demand for hydrocarbons and increased compliance costs for the Company. Eni is also exposed to risks of technological breakthrough in the energy field and risks of unpredictable extreme meteorological events linked to the climate change.
Growing worldwide public concern over greenhouse gas (GHG) emissions and climate change, as well as increasingly stricter regulations in this area, could adversely affect the Group’s business. Those risks may
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emerge in the short and medium-term, as well as over the long term. The scientific community has established a link between climate change, global warming and increasing GHG concentration in the atmosphere. International efforts to limit global warming have led, and Eni expects them to continue to lead, to new laws and regulations designed to reduce GHG emissions that are expected to bring about a gradual reduction in the use of fossil fuels over the medium to long-term, notably through the diversification of the energy mix. This trend could accelerate as a number of governments throughout the world have formally pledged to reach net-zero emissions by 2050 or earlier, like in the case of EU, which may lead to a tightening of various measure to constrain use of fossil fuels and this trend could increase both in breadth and severity if more governments follow suit.
Governmental institutions have responded to the issue of climate change on two fronts: on one side, governments can both impose taxes on GHG emissions and incentivise a progressive shift in the energy mix away from fossil fuels, for example, by subsidising the power generation from renewable sources; on the other side they can promote worldwide agreements to reduce the consumption of hydrocarbons.
Some governments have already introduced carbon pricing schemes, which can be an effective measure to reduce GHG emissions at the lowest overall cost to society. Today, about half of the direct GHG emissions coming from Eni operated assets are included in national or supranational Carbon Pricing Mechanisms, such as the European Emission Trading Scheme. Eni expects that more governments will adopt similar schemes and that a growing share of the Group’s GHG emissions will be subject to carbon-pricing and other forms of climate regulation in the short to medium term.
Eni is already incurring operating costs related to its participation in the European Emission Trading Scheme, whereby Eni is required to purchase, on the open markets, emission allowances in case its GHG emissions exceed freely-assigned emission allowances. In 2019 to comply with this carbon emissions scheme, Eni purchased on the open market allowances corresponding to 11.6 million tonnes of CO2 emissions for a cash cost of approximately €290 million. For 2020, management expects to purchase allowances to cover approximately 16 million tonnes of CO2 due to stricter regulation on the allotment of free allowances. Due to the likelihood of new regulations in this area, Eni expects additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could result in increased investments and higher project costs for Eni. Eni also expects that governments will require companies to apply technical measures to reduce their GHG emissions.
Eni expects that the achievement of the Paris Agreement goal of holding the increase in global average temperature to less than 2° C above pre-industrial levels, or the more stringent goal advocated by the Intergovernmental Panel on Climate Change (IPCC) to limit global warming to 1.5° C, will strengthen the global response to the threat of climate change and spur governments to introduce further measures and policies targeting the reduction of GHG emissions, which will likely reduce local demand for fossil fuels in the long-term, thus negatively affecting global demand for oil and natural gas. Eni’s business depends on the global demand for oil and natural gas. If existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including incentives to conserve energy or use alternative energy sources, technological breakthrough in the field of renewable energies or mass-adoption of electric vehicles trigger a structural decline in the worldwide demand for oil and natural gas, our results of operations and business prospects may be significantly and adversely affected.
The scientific community has concluded that increasing global average temperatures produces significant physical effects, such as the increased frequency and severity of hurricanes, storms, droughts, floods or other extreme climatic events that could interfere with Eni’s operations and damage Eni’s facilities. Extreme and unpredictable weather phenomena can result in material disruption to Eni’s operations, and consequent loss of or damage to properties and facilities, as well as a loss of output, loss of revenues, increasing maintenance and repair expenses and cash flow shortfall.
Finally, there is a reputational risk linked to the fact that oil companies are increasingly perceived by institutions and the general public as entities primarily responsible of the global warming due to GHG emissions across the hydrocarbons value-chain, particularly related with the use of energy products. This could possibly make Eni’s shares less attractive to investment funds and individual investors who have been more and more assessing the risk profile of companies against their carbon footprint when making investment decisions. Furthermore, a growing number of financing institutions, including insurance companies, appear to be considering limiting their exposure to fossil fuel projects, as witnessed by a pledge from the World Bank to stop financing upstream oil and gas projects and a proposal from the EU finance minister to reduce the financing granted to oil&gas projects via the EIB. This trend could have a material adverse effect on the price of our securities and our ability to access equity or other capital markets.
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Accordingly, our ability to use financing for future projects may be adversely impacted. Further, in some countries, governments and regulators have filed lawsuits seeking to hold fossil fuel companies, including Eni, liable for costs associated with climate change. Losing any of these lawsuits could have a material adverse effect on our business prospects.
As a result of these trends, climate-related risks could have a material an adverse effect the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
The exploration and production of oil and natural gas is a high-risk business because it is subject to the mining risk, to natural hazards and to other uncertainties, including those relating to the physical characteristics of oil and gas fields. It is a capital-intensive business with significant up-front cash-outs and extended pay-back periods of investments. Finally, it is strictly regulated and subject to conditions imposed by governments throughout the world.
A description of the main risks facing the Company’s business in the exploration and production of oil and gas is provided below.
Exploring for finding hydrocarbons reserves may be unsuccessful
Exploration drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling and completing wells have margins of uncertainty, and drilling operations may be unsuccessful because of a large variety of factors, including geological failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents. A large part of the Company exploratory drilling operations is located offshore, including in deep and ultra-deep waters, in remote areas and in environmentally-sensitive locations (such as the Barents Sea, the Gulf of Mexico and the Caspian Sea). In these locations, the Company generally experiences higher operational risks and more challenging conditions and incurs higher exploration costs than onshore. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the operational and the financial risks associated with these activities. Because Eni plans to make significant investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas, which is highly dependent on the rate of success of exploration projects, and could have an adverse impact on Eni’s future performance.
Development projects bear significant operational risks which may adversely affect actual returns
Eni is executing or is planning to execute several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or in environmentally-sensitive locations. Eni’s future results of operations and business prospects depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include:
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the outcome of negotiations with joint venture partners, governments and state-owned companies, suppliers, customers or others to define project terms and conditions, including, for example, Eni’s ability to negotiate favourable long-term contracts to market gas reserves;
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commercial arrangements for pipelines and related equipment to transport and market hydrocarbons;
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timely issuance of permits and licenses by government agencies;
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the ability to carry out the front-end engineering design in order to prevent the occurrence of technical inconvenience during the execution phase; timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; delays in achievement of critical phases and project milestones;
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risks associated with the use of new technologies and the inability to develop advanced technologies to maximise the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
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performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) contractual scheme;
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changes in operating conditions and cost overruns;
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the actual performance of the reservoir and natural field decline; and
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the ability and time necessary to build suitable transport infrastructures to export production to final markets.
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The occurrence of any of such risks may negatively affect the time-to-market of the reserves and cause cost overruns and delayed pay-back period, therefore adversely affecting the economic returns of Eni’s development projects and the achievement of production growth targets.
Development projects are typically long lead time due to the complexity of the activities and tasks that need to be performed before a project final investment decision is made and commercial production can be achieved. Those activities include the appraisal of a discovery to evaluate the technical and economic feasibility of the development project, obtaining the necessary authorizations from governments, state agencies or national oil companies, signing agreement with the first party regulating a project’s contractual terms such as the production sharing, obtaining partners’ approval, environmental permits and other conditions, signing long-term gas contracts, carrying out the concept design and the front-end engineering and building and commissioning the related plants and facilities. All these activities normally can take years to perform. As a consequence, rates of return for such projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from those estimated when the investment decision was made, thereby leading to lower return rates. Moreover, projects executed with partners and joint venture partners reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations and performance of its partners. Furthermore, Eni may not have full operational control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operations and strategic objectives due to the nature of its relationships.
Finally, if the Company is unable to develop and operate major projects as planned, particularly if the Company fails to accomplish budgeted costs and time schedules, it could incur significant impairment losses of capitalised costs associated with reduced future cash flows of those projects.
Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition
Unless the Company is able to replace produced oil and natural gas, its reserves will decline. In addition to being a function of production, revisions and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its production sharing agreements (“PSAs”), whereby the Company is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditure, and vice versa. Based on the current portfolio of oil and gas assets, Eni’s management estimates that production entitlements vary on average by approximately 530 barrels/d for each $1 change in oil prices based on current Eni’s assumptions for oil prices. In 2019, production benefitted marginally of lower oil prices which translated into higher entitlements. In case oil prices differ significantly from Eni’s own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.
Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiations with national oil companies and other entities owners of known reserves and acquisitions.
An inability to replace produced reserves by discovering, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of production growth and reserve replacement, Eni’s future total proved reserves and production will decline.
Uncertainties in estimates of oil and natural gas reserves
The accuracy of proved reserve estimates and of projections of future rates of production and timing of development expenditures depends on a number of factors, assumptions and variables, including:
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the quality of available geological, technical and economic data and their interpretation and judgement;
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projections regarding future rates of production and costs and timing of development expenditures;
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changes in the prevailing tax rules, other government regulations and contractual conditions;
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results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and
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changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.
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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 prices used in calculating Eni’s estimated proved reserves are, in accordance with the U.S. Securities and Exchange Commission (the “U.S. SEC”) requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ending at December 31, 2019, average prices were based on 63 $/barrel for the Brent crude oil; it was 71 $/barrel in 2018. Also the reference price of natural gas was lower than in 2018. Those reductions resulted in us having to remove volumes of proved reserves because they have become uneconomical at the prices of 2019. Furthermore, compared to the 2019 reference price, Brent prices have declined materially in the first quarter of 2020. If such prices do not increase significantly in the coming months, Eni’s future calculations of estimated proved reserves will be based on lower commodity prices which would likely result in the Company having to remove non-economic reserves from its proved reserves in future periods.
Accordingly, the estimated reserves reported as of the end of 2019 could be significantly different from the quantities of oil and natural gas that will be ultimately recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes.
The development of the Group’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates or the Group’s proved undeveloped reserves may not ultimately be developed or produced
At December 31, 2019, approximately 29% of the Group’s total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The Group’s reserve estimates assume it can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. The Group’s reserve report at December 31, 2019 includes estimates of total future development and decommissioning costs associated with the Group’s proved total reserves of approximately €35.7 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities). It cannot be certain that estimated costs of the development of these reserves will prove correct, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company’s plans to develop those reserves, or if it is not otherwise able to successfully develop these reserves as a result of the Group’s inability to fund necessary capital expenditures or otherwise, it will be required to remove the associated volumes from the Group’s reported proved reserves.
Oil and gas activity may be subject to increasingly high levels of income taxes and royalties
Oil and gas operations are subject to the payment of royalties and income taxes, which tend to be higher than those payable in many other commercial activities. Furthermore, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. As a result of these trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the Italian statutory tax rate for corporate profit, which currently stands at 24%. In 2019 the effective tax rate was 97.3% due to a particularly unfavourable oil and gas price scenario.
Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices, which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices.
In the current uncertain financial and economic environment, governments are facing greater pressure on public finances, which may induce them to intervene in the fiscal framework for the oil and gas industry, including the risk of increased taxation, windfall taxes, and even nationalisations and expropriations.
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The present value of future net revenues from Eni’s proved reserves will not necessarily be the same as the current market value of Eni’s estimated crude oil and natural gas reserves
The present value of future net revenues from Eni’s proved reserves may differ from the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with the SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month un-weighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
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the actual prices Eni receives for sales of crude oil and natural gas;
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the actual cost and timing of development and production expenditures;
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the timing and amount of actual production; and
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changes in governmental regulations or taxation.
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The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. Additionally, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni’s reserves or the crude oil and natural gas industry in general. At December 31, 2019, the net present value of Eni’s proved reserves totalled approximately €50.9 billion. The average prices used to estimate Eni’s proved reserves and the net present value at December 31, 2019, as calculated in accordance with the SEC rules, were 63 $/barrel for the Brent crude oil. Actual future prices may materially differ from those used in our year-end estimates. Commodity prices have decreased materially in the first quarter of 2020 compared to the price used in the reserve calculations at 2019 year-end. Holding all other factors constant, if commodity prices used in Eni’s year-end reserve estimates at end of 2020 were in line with the pricing environment existing at the end of the first quarter of 2020, Eni’s PV-10 at December 31, 2020 would likely decrease significantly.
Oil and gas activity may be subject to increasingly high levels of regulations throughout the world, which may impact our extraction activities and the recoverability of reserves
The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. These risks can limit the Group access to hydrocarbons reserves or may have the Group to redesign, curtail or cease its oil&gas operation.
In Italy, the activities of hydrocarbon development and production are performed by oil companies in accordance to concessions granted by the Ministry of Economic Development in agreement with the relevant Region territorially involved in the case of onshore concessions. Concessions are granted for an initial twenty-year term; the concessionaire is entitled to a ten-year extension and then to one or more five-year extensions to fully recover a field’s reserves on condition that he has fulfilled all obligations related to the work program agreed in the initial concession award. In case of delay in the award of an extension, the original concession remains fully effective until the administrative procedure to grant an extension is finalized. These general rules are to be coordinated with a new law that was enacted on February 12, 2019. This law requires certain Italian administrative bodies to adopt within eighteen months (i.e. by August 2020) a plan intended to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, 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 and new exploration permits can be awarded; on the contrary, in unsuitable areas, exploration permits are repealed, applications for obtaining new exploration permits ongoing at the time of the law enactment are rejected and no new permit application can be filed. 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
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at their expiration and no further extensions can be granted, nor new concession applications can be filed or awarded. According to the statute, areas that are suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline.
The Group’s largest operated development concession in Italy is Val d’Agri, which has expired on October 26, 2019. Development activities at the concession have continued since then in accordance to the “prorogation regime” described above, within the limits of the work plan approved when the concession was firstly granted. The Company filed an application to obtain a ten-year extension of the concession in accordance to the terms set by the law and before the enactment of the new law on the national plan for hydrocarbons activity. In this application the Company confirmed the same work program as in the original concession award. Other 33 Italian concessions for hydrocarbons development and production have expired, where the Company operations are underway in accordance to the ongoing prorogation regime. The Company has filed requests for extensions within the terms of the law also for those concessions.
As far as proven reserves estimates are concerned, management believes the criteria laid out in the new law to be high-level principles, which make it difficult identifying in a reliable and objective manner areas that might be suitable or unsuitable to hydrocarbons activities before the plan is adopted by Italian authorities. Therefore, management is not currently in the position to make a reliable and fair estimation of future impacts of the new law provisions on the recoverability of the volumes of proved reserves booked in Italy and the associated future cash flows. However, based on the review of all facts and circumstances and on the current knowledge of the matter, management does not expect any material impact on the Group future performance.
Eni’s future performance depends on its ability to identify and mitigate the above mentioned risks and hazards which are inherent to its oil&gas business. Failure to properly manage those risks, Company’s underperformance at exploration, development and reserve replacement activities or the occurrence of unforeseen regulatory risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Risks related to political considerations – we are exposed to a range of political developments and consequent changes to the operating and regulatory environment
As of December 31, 2019, approximately 81% of Eni’s proved hydrocarbon reserves were located in non-OECD countries, mainly in Africa, Central-East Asia and central-southern America, where the socio-political framework, the financial system and the macroeconomic outlook are less stable than in the OECD countries. In those non-OECD countries, Eni is exposed to a wide range of political risks and uncertainties, which may impair Eni’s ability to continue operating in an economically viable way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. Particularly, Eni faces risks in connection with the following, possible issues:
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socio-political instability leading to internal conflicts, revolutions, establishment of non-democratic regimes, protests, attacks, strikes and other forms of civil disorder and unrest, such as strikes, riots, sabotage, acts of violence and similar events. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, the loss of assets and threat to the security of personnel. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographical areas in which Eni operates. Additionally, any possible reprisals because of military or other action, such as acts of terrorism in Europe, the United States or elsewhere, could have a material adverse effect on the world economy and hence on the global demand for hydrocarbons;
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lack of well-established and reliable legal systems and uncertainties surrounding the enforcement of contractual rights;
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unfavourable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalisation or forced divestiture of assets and unilateral cancellation or modification of contractual terms;
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sovereign default or financial instability due to the fact that those countries rely heavily on petroleum revenues to sustain public finance and petroleum revenues have dramatically contracted
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in recent years. Financial difficulties at country level often translate into failure on part of state-owned companies and agencies to fulfil their financial obligations towards Eni relating to funding capital commitments in projects operated by Eni or to timely paying supplies of equity oil and gas volumes;
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restrictions on exploration, production, imports and exports;
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tax or royalty increases (including retroactive claims);
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difficulties in finding qualified international or local suppliers in critical operating environments; and
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complex processes of granting authorisations or licences affecting time-to-market of certain development projects.
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Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Kazakhstan, Venezuela and Iraq.
In recent years, Eni’s operations in Libya were materially affected by the revolution of 2011 and a change of regime, which caused a prolonged period of political and social instability, still ongoing. In 2011 Eni’s operations in the country experienced an almost one-year long shutdown due to security issues amidst a civil war, causing a material impact on the Group results of operation and cash flow for the year. In subsequent years Eni has experienced frequent disruptions at its operations albeit of a smaller scale than in 2011 due to security threats to its installations and personnel. From the second half of 2018 a resurgence of socio-political instability and a lack of a well-established institutional framework have triggered the resumption of the civil war and armed clashes in the area of Tripoli since April 2019. The situation has continued to escalate and international negotiations aimed at establishing a ceasefire has proven elusive. The Company repatriated its personnel and strengthened security measures at its plants and facilities. Despite the complexity of the operating context, the Company’s activities in 2019 progressed smoothly and in accordance to management’s plans with achievement of full production plateau at the main ongoing projects of Wafa compression and Bahr Essalam ph. 2. Going forward, management believes that Libya’s geopolitical situation will continue to represent a source of risk and uncertainty to Eni’s operations in the Country. At the beginning of 2020 oil export terminals in the Southern part of Libya were blocked, forcing the Company to shut down operations at one of its production facilities (the Elephant oilfield). In 2019, Libya represented approximately 16% of the Group’s total production; this percentage is forecasted to decrease in the medium term in line with the expected implementation of the Group strategy intended to diversify the Group geographical presence to better balance the geopolitical risk of the portfolio. In the event of major adverse events, such as the escalation of the internal conflict into a full-blown civil war, attacks, sabotage, social unrest, clashes and other forms of civil disorder, Eni could be forced to reduce or to shut down completely its producing activities at its Libyan fields, which would significantly hit results of operations and cash flow.
Venezuela is currently experiencing a situation of financial stress amidst an economic downturn due to lack of resources to support the development of the country’s hydrocarbons reserves, which have negatively affected the Country production levels and hence petroleum revenues. The situation has been made worse by certain international sanctions targeting the country’s financial system and its ability to export crude oil to the United States’ market, which is the main outlet of Venezuelan production (see also “− Sanctions targets” below).
Due to a deteriorated operating environment, the Group was forced to de-book its proved undeveloped reserves at its two major petroleum projects in the Country in recent years: the 50%-participated Cardón IV joint venture which is currently operating a natural gas project and is supplying the product to the national oil company, PDVSA, and the PetroJunín oilfield project in joint venture with PDVSA. This latter project was almost entirely written off in 2018. Also the Group has incurred credit losses due to the continued difficulties on part of PDVSA to pay the receivables for the gas supplies of Cardón IV, resulting in a significant amount of overdue receivables. The joint-venture is systematically accounting a loss provision on the revenues accrued. The credit expected loss was based on management’s appreciation of the counterparty risk driven by the findings of a review of the past experience of sovereign defaults on which basis a deferral in the collection of the gas revenues has been estimated. In the course of 2019 the situation has stabilized, since the Group was able to collect a percentage of gas receipts which was in line with management’s estimates made in 2018 of the expected credit losses and no further credit allowances were recorded. As of December 31, 2019, Eni’s invested capital in Venezuela was approximately $1.3 billion. Eni expects the financial and political outlook of Venezuela to remain a risk factor to its operations in the Country for the foreseeable future.
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Nigeria is also undergoing a situation of financial stress, which has translated into continuing delays in collecting overdue trade receivables and credits for the carry of the expenditures of the Nigerian joint operators at projects operated by Eni, resulting in the incurrence of credit losses. Further, Eni’s activities in Nigeria have been impacted in recent years by continuing incidences of theft, acts of sabotage and other similar disruptions, which have jeopardised the Company’s ability to conduct operations in full security, particularly in the onshore area of the Niger Delta. Eni expects that those risks will continue to affect Eni’s operations in Nigeria.
Management expects Eni’s credit exposure to Egypt to continue increasing in the foreseeable future due to the planned production ramp-up at the Zohr offshore gas field and to development of existing gas reserves at other projects. Because the whole of the Group’s gas production is sold to local state-owned companies, Eni expects a significant increase in the credit risk exposure to Egypt, where we experienced some issues at collecting overdue trade receivables during the oil downturn. Eni will continue to monitor the counterparty risk in future years considering the significant volumes of gas expected to be supplied to Egypt’s national oil companies.
In addition to the above risks, the United Kingdom left the European Union (EU) at the end of January 2020. As a result of this decision, it is possible that we may experience delays in moving our products and employees between the UK and EU. Also, additional tariffs and taxes could impact the demand for some of our products and this, combined with the potential adverse changes in macroeconomic conditions in both the EU and UK, could have a material adverse effect on the energy demand.
Eni is closely monitoring political, social and economic risks of the countries in which it has invested or intends to invest, in order to evaluate the economic and financial return of capital projects and to selectively evaluate projects. While the occurrence of these events is unpredictable, the occurrence of any such risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Sanction targets
In response to the Russia-Ukraine crisis, the European Union and the United States have enacted sanctions targeting, inter alia, the financial and energy sectors in Russia by restricting the supply of certain oil and gas items and services to Russia and certain forms of financing. Eni has adapted its activities to the applicable sanctions and will adapt its business to any further restrictive measures that could be adopted by the relevant authorities. In 2017, the United States’ government tightened the sanction regime against Russia by enacting the “Countering America’s Adversaries Through Sanctions Act”. In response to these new measures, the Company could possibly refrain from pursuing business opportunities in Russia, while currently the Company is not engaged in any upstream projects in Russia. It is possible that wider sanctions targeting the Russian energy, banking and/or finance industries may be implemented. Further sanctions imposed on Russia, Russian citizens or Russian companies by the international community, such as restrictions on purchases of Russian gas by European companies or measures restricting dealings with Russian counterparties, could adversely impact Eni’s business, results of operations and cash flow. Furthermore, an escalation of the international crisis, resulting in a tightening of sanctions, could entail a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group’s business, financial conditions, results of operations and prospects. In 2017, the United States administration enacted certain financing sanctions against Venezuela, which prohibit any United States person to be involved in all transactions related to, provision of financing for, and other dealings in, among other things, any debt owed to the Government of Venezuela that is pledged as collateral after the effective date, including accounts receivable. Recently, the United States administration has resolved to impose an embargo on the import of crude oil from Venezuela state-owned oil company, PDVSA and has restricted the ability of United States dealers to trade bonds issued by the Government of Venezuela and its affiliates. Further increases of the prohibitions against the Government of Venezuela (and the entities owned or controlled by it) has been enacted during the course of 2019, with inclusion of our Venezuelan partner, PDVSA, in the “Specially Designated Nationals and Blocked Persons List and the introduction of measures intended to freeze the assets of the Venezuelan governments and of its affiliated persons. Even if the current US sanctions are “primary” and therefore substantially dedicated to US persons only, retaliatory measures and other adverse consequences may interest also foreign entities which operate with Venezuelan listed entities as it may occur in the case of transactions which show a US nexus, which may trigger the application of sanctions. Eni is carefully evaluating on a case by case basis the adoption of measures adequate to minimize its exposure to any sanction risk which may affect its business operation. In any case, the US sanction are expected to add further stress to the already complex financial, political and operating outlook of the country, which could limit the ability of Eni to recover its investments.
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Risks in the Company’s Gas & Power business
Risks associated with the trading environment and competition in the gas market
Our Gas & Power business comprises the results of the wholesale gas business which has a portfolio of long-term gas supply contracts and other related assets, the trading of LNG on a global scale, the production and marketing of electricity and the marketing of gas and power in the retail sector.
The results of our wholesale gas business are subject to global and regional dynamics of gas demand and supplies and to trends in the spreads between the procurement costs of gas, which are linked to spot prices at European hubs or to the price of crude oil, and the selling prices of gas which are mainly indexed to spot prices at the Italian hub. Those spreads can be very volatile. The results of the LNG business are mainly influenced by the global balance between demand and supplies.
Worldwide gas prices have been on a downward path since the second half of 2018 and this trend has deteriorated further throughout the course of 2019. This was driven by a global economic slowdown, which hit severely Asian large gas-consuming countries, like China, South Korea and Japan, also due to a recovery in nuclear production, a build-up in gas supplies due to the entry into service of new Liquefied Natural Gas (“LNG”) projects and rising US production, competition from renewables, mild global temperatures and inventory levels above historic averages. The fall of gas prices at our main European outlet markets was broadly in line with other geographies due to above mentioned dynamics and the growing role of LNG supplies which have enhanced the interconnection among regional markets and markets liquidity. In fact, during the course of 2019 a reduction in LNG imports from Asian markets forced operators to re-direct LNG supplies to Europe, thus making for any slowdown in the Continent’s internal production and pressuring gas prices which have levelled across the various geographies. These trends negatively affected the results of our LNG business due to lower traded volumes and margins. The trading environment for LNG has deteriorated further in the first months of 2020 due on ongoing global deceleration in energy demand.
Management believes that gas prices in Europe will remain weak due to the forecast of sluggish economic growth, a muted demand outlook and global oversupplies of gas. Furthermore, several final investment decisions have been made in 2019 relating to large LNG projects with an estimated capacity of 60 million tonnes per year, which are due to come on stream within five-six years adding to already oversupplied markets.
Against the backdrop of a difficult competitive environment, Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the four-year planning period, considering the Company’s operational constraints dictated by its long-term gas supply contracts with take-or-pay clauses, which expose Eni to a volume risk, as the Company is contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the corresponding price. Additionally, Eni has booked the transportation rights along the main gas backbones across Europe to deliver its contracted gas volumes to end-markets. Risks to the Gas & Power business include continuing oversupplies, pricing pressures, volatile margins and the risk of deteriorating spreads of Italian spot prices versus continental benchmarks. A reduction of the spreads between Italian and European spot prices for gas could negatively affect the profitability of our business by reducing the total addressable market and by reducing the margin to cover the business’s sunk costs and other fixed expenses. Eni’s management is planning to continue its strategy of renegotiating the Company’s long-term gas supply contracts in order to constantly align pricing terms to current market conditions as they evolve and to obtain greater operational flexibility (volumes, delivery points among others), considering the risk factors described above. The revision clauses provided by these contracts state the right of each counterparty to renegotiate the economic terms and other contractual conditions periodically, in relation to ongoing changes in the gas scenario. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately obtained and the timing of recognition of profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, both parties can start an arbitration procedure to obtain revised contractual conditions. All these possible developments within the renegotiation process could increase the level of risks and uncertainties relating the outcome of those renegotiations.
Trends in the LNG business are expected to remain weak in 2020 due to a global glut of LNG.
Current, negative trends in gas demands and supplies may impair the Company’s ability to fulfil its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts
Eni long-term gas supply contracts with national operators of certain key producing countries, from where most of the European gas supplies are sourced (Russia, Algeria, Libya, the Netherlands and
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Norway), include take-or-pay clauses whereby the Company has an obligation to lift minimum, pre-set volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to the minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations. Long-term gas supply contracts with take-or pay clauses expose the Company to a volume risk, as the Company is obligated to purchase an annual minimum volume of gas, or in case of failure, to pay the underlying price. Management believes that the current level of market liquidity, the outlook of the European gas sector which is featuring muted demand growth, strong competitive pressures and large supplies, as well as any possible change in sector-specific regulation represent risk factors to the Company’s ongoing ability to fulfil its minimum take obligations associated with its long-term supply contracts.
Risks associated with the regulatory powers entrusted to the Italian Regulatory Authority for Energy, Networks and Environment in the matter of pricing to residential customers
Eni’s Gas & Power segment is subject to regulatory risks mainly in its domestic market in Italy. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas pricing. Specifically, the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users until the market is fully opened. Developments in the regulatory framework intended to increase the level of market liquidity or of de-regulation, or intended to reduce operators’ ability to transfer to customers cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results and cash flow.
Risks related to environmental, health and safety regulations and legal risks
Eni has incurred in the past, and will continue incurring, material operating expenses and expenditures, and is exposed to business risk in relation to compliance with applicable environmental, health and safety regulations in future years, including compliance with any national or international regulation on GHG emissions
Eni is subject to numerous European Union, international, national, regional and local laws and regulations regarding the impact of its operations on the environment and on health and safety of employees, contractors, communities and on the value of properties. Generally, these laws and regulations require acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, including refinery and petrochemical plant operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace and the of plants and infrastructures, and health of employees, contractors and other Company’s collaborators and of communities involved by the Company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees’ or communities’ health and safety resulting from the Group’s operations. These laws and regulations control the emission of scrap substances and pollutants, discipline the handling of hazardous materials and set limits to the discharge in the environment of soil, water or ground water contaminants, polluting air emissions and noxious gases resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned or operated by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste. Breaches of environmental, health and safety laws and regulations as in the case of negligent or willful release of pollutants and contaminants into the atmosphere, the soil, water or groundwater or the overcome of concentration threshold of contaminants set by the law expose the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage and expenses for environmental remediation and clean-up. Furthermore, in the case of violation of certain rules regarding the safeguard of the environment and the health of employees, contractors and other collaborators of the Company, and of communities, the Company may incur liabilities in connection with the negligent or willful violation of laws by its employees as per Italian Law Decree No. 231/2001.
Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations and to safeguard the environment and the health and safety of employees, contractors and communities involved by the Company operations, including:
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costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change (see the specific section below on climate-related risks);
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remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below);
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damage compensation claimed by individuals and entities, including local, regional or state administrations, should Eni cause any kind of accident, oil spill, well blowouts, pollution, contamination, emission of GHG and other air pollutants above permitted levels or of any other hazardous gases, water, ground or air contaminants or pollutants, as a result of its operations or if the Company is found guilty of violating environmental laws and regulations; and
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costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging at the end of oil&gas field production.
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As a further result of any new laws and regulations or other factors, like the actual or alleged occurrence of environmental damage at Eni’s plants and facilities, the Company may be forced to curtail, modify or cease certain operations or implement temporary shutdowns of facilities. For example, in Italy we have experienced in recent years a number of plant shutdowns at our Val d’Agri profit centre due to environmental issues and oil spill overs, causing loss of output and of revenues. The Italian judicial authorities have started legal proceedings to verify alleged environmental crimes or crimes against the public safety and other criminal allegations as described in the notes to the Consolidated Financial Statements.
If any of the risks set out above materialise, they could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Eni is exposed to the risk of material environmental liabilities in addition to the provisions already accrued in the consolidated financial statement.
Eni has incurred in the past and may incur in the future material environmental liabilities in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. Furthermore, environmental regulations in Italy and elsewhere typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, environmental damage, and other damages as a result of Eni’s conduct of operations that was lawful at the time it occurred or of the conduct of prior operators or other third parties. In addition, plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found liable of violations of any environmental laws or regulations. In Italy, Eni is exposed to the risk of expenses and environmental liabilities in connection with the impact of its past activities at certain industrial hubs where the Group’s products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities, which were subsequently disposed of, liquidated, closed or shut down. At these industrial hubs, Eni has undertaken a number of initiatives to remediate and to clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. State or local public administrations have sued Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company, or which the Company has committed to perform. In some cases, Eni has been sued for alleged breach of criminal laws (for example for alleged environmental crimes such as failure to perform soil or groundwater reclamation, environmental disaster and contamination, discharge of toxic materials, amongst others). Although Eni believes that it may not be held liable for having exceeded in the past pollution thresholds that are unlawful according to current regulations but were allowed by laws then effective, nor because the Group took over operations from third parties, it cannot be excluded that Eni could potentially incur such environmental liabilities. Eni’s financial statements account for provisions relating to the costs to be incurred with respect to clean-ups and remediation of contaminated areas and groundwater for which a legal or constructive obligation exists and the associated costs can be reasonably estimated in a reliable manner, regardless of any previous liability attributable to other parties. The accrued amounts represent management’s best estimates of the Company’s existing liabilities. Management believes that it is possible that in the future Eni may incur significant or material environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of as yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavourable developments in ongoing litigation on the environmental status of certain of the
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Company’s sites where a number of public administrations and the Italian Ministry of the Environment act as plaintiffs; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites. As a result of these risks, environmental liabilities could be substantial and could have a material adverse effect the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Risks related to legal proceedings and compliance with anti-corruption legislation
Eni is the defendant in a number of civil and criminal actions and administrative proceedings. In future years Eni may incur significant losses in addition to the amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements or to judge a negative outcome only as possible or to conclude that a contingency loss could not be estimate reliably; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate. Certain legal proceedings and investigations in which Eni or its subsidiaries or its officers and employees are defendant involve the alleged breach of anti-bribery and anti-corruption laws and regulations and other ethical misconduct. Such proceedings are described in Note 27 to the Eni’s 2019 Annual Report on Form 20-F, under the heading “Legal Proceedings”. Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and anti-corruption laws, by Eni, its officers and employees, its partners, agents or others that act on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation and shareholder value.
Risks from acquisitions
Eni is constantly monitoring the oil and gas market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks related to acquisitions materialise, expected synergies from acquisition may fall short of management’s targets and Eni’s financial performance and shareholders’ returns may be adversely affected.
Risks deriving from Eni’s exposure to weather conditions
Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing business, as well as the comparability of results over different periods may be affected by such changes in weather conditions. Over recent years, this pattern could have been possibly affected by the rising frequency of weather trends like milder winter or extreme weather events like heatwaves or unusually cold snaps, which are possible consequences of climate change.
Eni’s crisis management systems may be ineffective
Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed period could prolong the impact of any disruption and could severely affect business, operations and financial results. Eni has crisis management plans and the capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, this could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
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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.
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.
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, this activity involves elements of forecasting and Eni is exposed to the risks of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.
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We are exposed to 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 results of operations and cash flows. Furthermore, prices of oil, natural gas and refined products generally are denominated in, or linked to, USD, while a significant portion of Eni’s expenses are incurred in euros. Accordingly, a depreciation of the 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 USD denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity.
Eni’s credit ratings are potentially exposed to risk from possible reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the debt instruments issued by the Company could be downgraded.
We are exposed to the liquidity risk in case the Group fails to access suitable sources of funding, 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. Global financial markets are volatile due to a number of macroeconomic risk factors, including the financial situation of certain hydrocarbons-exporting countries whose financial conditions have sharply deteriorated following the protracted downturn in 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 business prospects and 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 and production of oil and natural gas reserves. In 2020, Eni expects to make capital expenditures of approximately €4 billion at the planned exchange rate of 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 equipment, the availability of transportation capacity, and regulatory, technological and competitive developments. Eni’s cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to:
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the amount of Eni’s proved reserves;
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the volume of crude oil and natural gas Eni is able to produce and sell from existing wells; the prices at which crude oil and natural gas are sold;
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Eni’s ability to acquire, find and produce new reserves; and
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the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds.
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If revenues or Eni’s ability to borrow decrease significantly due to factors such as a prolonged decline in crude oil and natural gas prices, Eni might have limited ability to obtain the capital necessary to sustain its planned capital expenditures. If cash generated by operations, cash from asset disposals, or cash available under Eni’s liquidity reserves or its credit facilities is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of Eni’s reserves, which in turn could adversely affect its business prospects, results of operations and cash 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.
We are exposed to credit risk; our counterparties could fail or could be unable to pay the amounts owed to us and to meet their performance obligations under contractual arrangements. In the last few years, the Group has experienced a level of counterparty default higher than in previous years due to
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the severity of the economic and financial downturn that has negatively affected several Group counterparties, customers and partners and to the fact that Italy, which is still the largest market to Eni’s gas wholesale and retail businesses, has underperformed other OECD countries in terms of GDP growth. Management believes that the Gas & Power segment is particularly exposed to credit risk due to its large and diversified customer base, which includes a large number of medium and small-sized businesses and retail customers who have been particularly 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 the management of doubtful accounts represents an issue to the Company, which will require management focus and commitment going forward. Eni cannot exclude the recognition of significant provisions for doubtful accounts in the future. In particular, management is closely monitoring exposure to the counterpart risk in its Exploration & Production due to the magnitude of the exposure at risk and to the long-lasting effects of the oil price downturn on its industrial partners.
If any of the risks set out above 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.
See “Liquidity and capital resources” on page 105 and Note 27 – Financial Risk – to the “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. Eni has operations in 66 countries and 32,053 employees as of December 31, 2019.
Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders.
The name of the agent of Eni in the United States is Marco Margheri, Washington DC – USA 601, 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 41 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Australia, Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and United Arab Emirates. In 2019, Eni average daily production amounted to 1,736 KBOE/d on an available- for-sale basis. As of December 31, 2019, Eni’s total proved reserves amounted to 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 2019, Eni’s worldwide sales of natural gas amounted to 73.07 BCM, of which 37.85 BCM in Italy. Eni produces power at a number of operated gas- fired plants in Italy with a total installed capacity of 4.7 GW as of December 31, 2019. In 2019, electricity sold totalled 39.49 TWh. The LNG business includes the purchase and marketing of LNG worldwide, with a large incidence of equity LNG supplies. The Group serves the gas and power wholesale and retail markets in Italy and in a number of European markets. As at December 31, 2019 the Gas & Power segment had 9.4 million retail customers. The Gas & Power segment comprises results of the Group activities intended to manage commodity risk of asset-backed trading activities and proprietary trading. Furthermore, this activity includes the result of crude oil and products supply, trading and shipping.
Eni’s Refining & Marketing and Chemical segment includes 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, 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 2019, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to 23.05 mmtonnes (of which traditional refinery throughputs were 22.74 mmtonnes and bio refinery throughputs were 0.31 mmtonnes) and sales of refined products were 32.27 mmtonnes, of which 25.56 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 8.25 mmtonnes in Italy and in the rest of Europe. In 2019, Eni’s retail market shares in Italy through its “Eni” branded network of service stations was 23.7%.
In the Chemical business Eni, through its wholly-owned subsidiary Versalis, engages in the production and marketing of basic petrochemical products, plastics and elastomers. Versalis is developing the business of green chemicals. Activities are concentrated in Italy and in Europe. In 2019, production volumes of
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petrochemicals amounted to 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 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:
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San Donato Milanese (Milan), Via Emilia, 1; and
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San Donato Milanese (Milan), Piazza Ezio Vanoni, 1.
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Internet address: eni.com
A list of Eni’s subsidiaries is provided in “Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements”.
Strategy
The Company has taken steps to adapt to and thrive in a low-carbon world. We have designed a long-term strategy 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 fast changing energy market while delivering a deep reduction in GHG emissions from our operations and our products.
The principles that are the basis of our business strategy and will drive the evolution of our portfolio are:
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to actively contribute to the achievement of all 17 UN SDGs which are reflected in Eni’s mission;
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to maximize the integration of the portfolio along the entire value chain, from production to final sale of conventional, bio and renewable products;
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to focus on capital discipline to maintain a strong balance sheet and to sustain our cash flow generation; and
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to maintain a progressive shareholder remuneration policy.
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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 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 business units. The speed of evolution and the relative contribution of each business will depend on market trends, technological developments and legislation and the success of our implementation of the strategy in each business. Our goals for each businesses are follows:
In the E&P business:
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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;
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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 and development to enable the Company to capture market opportunities as they evolve. We expect to produce the vast majority of the value of our reserves by 2035 assuming a flat Brent price scenario of  $50/bbl. The gas share of production is expected to reach 60% by 2030 and around 85% in 2050;
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to invest significantly in exploration activities with a view of increasing the geographical diversification and optionality of the portfolio; and
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to grow the cash generation.
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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 business:
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to expand retail activities to reach a customer base of over 20 million by 2050, leveraging the expected growth in consumption of renewables and bio-methane;
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to achieve a complete transition to bio and renewable products by 2050;
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to enhance the offer to customers with the supply of new services;
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to capture synergies by centralizing in this business the activity of marketing and trading of all non-oil commodities;
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to focus on equity products marketing (gas, biomethane, blue energy, hydrogen) and the progressive reduction of non-equity gas sales; and
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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.
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In the Refining & Marketing:
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to continue the process of feedstock diversification in our running bio-refineries to become “palm oil free” by 2023, 7 years ahead of the EU ban on palm oil;
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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;
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in the long-term to retain just one traditional refinery in operation, the Ruwais refinery in the United Arab Emirates, leveraging its optimal geographic location and operational efficiency;
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to evolve the product mix marketed at our retail outlets, reaching 100% of de-carbonized products by 2050; and
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to increase the offer of additional services to improve margins and enhance customer loyalty.
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In the Chemical business:
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to enhance production of high-quality and high-performance polymers;
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to develop and integrate the new businesses of producing chemicals products from renewables and from chemical recycling and mechanical recycling of wasted plastics;
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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
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to establish an integrated platform to maximize synergies with refining in gasification processes involving all types of plasmix.
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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:
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scope 1, 2 and 3;
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from all the hydrocarbons produced or bought from third parties, in all businesses inside Eni’s energy portfolio; and
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measured both on an absolute basis and in terms of intensity per unit of energy product sold.
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We believe the implementation of our strategy and of our actions plans over the next thirty years to drive:
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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.
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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
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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.
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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 risks of lower hydrocarbons demand in response to stricter global environmental constraints and regulations and increasing public sensitivity to the issue of 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 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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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 plans. The majority of the projects have GHG intensity targets that allow them under current assumptions to compete in a more CO2 regulated future. These processes can lead to projects being stopped, designs being changed, and potential GHG mitigation investments being identified, in preparation for when the economic conditions imposed by new 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 IAS 36. The IEA SDS sets out an energy pathway consistent with the goal of achieving universal energy access by 2030 and of reducing energy-related CO2 emissions and air pollution in line with the goals of the Paris Agreement. 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 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 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.
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, which is one of the tools of the Company’s path to decarbonization. Those projects which have been started in 2019 envisage the purchase of carbon credits certified in accordance to generally accepted international standards. Management projects to build in future years a portfolio of forestry projects intended to allow the Company to offset the net residual “Scope 1 and 2” carbon emissions of the E&P business calculated on equity production for the achievement of the carbon neutrality of the business from 2030 onwards. Those costs are considered part of the operating expenses of the E&P business and their recoverability has been evaluated in relation to the CGU E&P segment as a whole. When including those costs extrapolated along the reserves residual life in the determination of the value-in-use of the E&P segment, a 2% reduction in the headroom (excess of fair value over carrying amounts) of the entire business segment is observed compared to the result of the impairment review performed by the Company in the preparation of its 2019 financial statements.
Ultimately, under management’s assumptions for a long-term Brent price at 70 $/bbl (real terms 2022), which has remained unchanged for the last few years, and at a reference price for the Italian spot gas benchmark of 7.8 $/​mmBTU, Eni’s oil&gas properties have exhibited a substantial resilience of their carrying amounts, as highlighted by the trend in the recognition of impairment losses in the last three years. In 2017 we recorded a net reversal of €158 million and in 2018 we recorded net impairment losses of €726 million; in 2019 we booked charges of €1.2 billion. Impairment losses in those three years have been driven mainly by asset-specific issues, which were acquired during a historic phase of suspected peak supply, and in relation to certain complex operating environments. However, considered the following trends 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
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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 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
•
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.
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January 2020 – Made a gas and condensate discovery with the Mahani-1 well in the concession Area B, in the Emirate of Sharjah (UAE).
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January 2020 – Awarded the operatorship with a 60% interest in the Block 28, offshore Angola.
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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 renewable energy projects in the United States to develop at least 1 GW of 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 (70%) and HitecVision (30%), finalized the acquisition of ExxonMobil’s upstream assets in Norway, with annual production of 150 kboe/d, for a total consideration of  $4.5 billion fully financed by the JV.
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•
December 2019 – Closed the disposal of a 20% interest to Neptune in the East Sepinggan block, offshore East Kalimantan in Indonesia, which includes the Merakes field and the East Merakes discovery. Eni will retain a 65% interest and the operatorship.
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•
December 2019 – Awarded a 50 MWp photovoltaic project in the southern Kazakhstan, as a result of an auction managed by the Kazakh Authorities.
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•
October 2019 – 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 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.
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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.
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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 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 Z5-D in Mozambique, located in the deep waters of Angoche and 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.
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May 2019 – Signed with Montello S.p.A., a company focused on post-consumer plastic recovery and recycling technologies, an agreement to develop a new range of plastic products made from recycled packaging.
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May 2019 – Made a gas and condensate discovery in CTP-Block 4 (Eni operator with a 42.47% interest) in the Akoma exploration prospect, offshore Ghana.
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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.
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For significant business and portfolio developments occurred from January 2019 to March 2019 see also the Annual Report on 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 41 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Australia, Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and the United Arab Emirates. In 2019, Eni average daily production amounted to 1,736 KBOE/d on an available-for-sale basis. As of December 31, 2019, Eni’s total proved reserves amounted to 7,268 mmBOE; proved reserves of subsidiaries totaled 6,287 mmBOE; Eni’s share of reserves of equity-accounted entities was 981 mmBOE.
“Eni’s strategy and short-to-medium term targets in its Exploration & Production segment are disclosed in Item 5 – Management’s expectations of operations.”
Disclosure of reserves
Overview
The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of- the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.
Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil&gas reserves can be designated as “proved”, the accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information.
Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s 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 service contracts.
Reserves governance
Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is in charge of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.
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Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which stated that those guidelines comply with the SEC rules1. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines.
The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department and the operations unit at the head office verify the production profiles of such properties where significant changes have occurred and operating expenses, respectively; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above-mentioned units and aggregates worldwide reserves data.
The head of the Reserves Department attended the “Università degli Studi di Milano” and received a Master of Science degree in Physics in 1988. He has more than 30 years of experience in the oil&gas industry and more than 20 years of experience in evaluating reserves.
Staff involved in the reserves evaluation process fulfils the professional qualifications requested by the role and complies with the required level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.
Reserves independent evaluation
Eni has its proved reserves audited on a rotational basis by independent oil engineering companies2. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report3. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.
In order to calculate the net present value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third-party evaluators. In 2019, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 31% of Eni’s total proved reserves at December 31, 20194, confirming, as in previous years, the reasonableness of Eni internal evaluation5.
In the 2017-2019 three-year period, 86% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2019, the Zohr field in Egypt was the main Eni property, which did not undergo an independent evaluation in the last three years. Management expects that the Zohr field will be subject to an independent evaluation in 2020.
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1
See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009.
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2
From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott. In 2018, the Societé Generale de Surveillance (SGS) company also provided an independent certification.
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3
See “Item 19 – Exhibits”.
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4
Includes Eni’s share of proved reserves of equity-accounted entities.
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5
See “Item 19 – Exhibits”
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Summary of proved oil and gas reserves
The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2019, 2018 and 2017.

HYDROCARBONS (mmBOE) | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | 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.
​
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LIQUIDS (mmBBL) | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub- Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | Americas | ​ | ​ | Australia and Oceania | ​ | ​ | Total reserves | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dec. 31, 2019 | ​ | ​ | 194​ | ​ | ​ | 41​ | ​ | ​ | 468​ | ​ | ​ | 264​ | ​ | ​ | 694​ | ​ | ​ | 746​ | ​ | ​ | 491​ | ​ | ​ | 225​ | ​ | ​ | 1​ | ​ | ​ | 3,124​ | ​
developed | ​ | ​ | 137​ | ​ | ​ | 37​ | ​ | ​ | 301​ | ​ | ​ | 149​ | ​ | ​ | 519​ | ​ | ​ | 682​ | ​ | ​ | 245​ | ​ | ​ | 148​ | ​ | ​ | 1​ | ​ | ​ | 2,219​ | ​
undeveloped | ​ | ​ | 57​ | ​ | ​ | 4​ | ​ | ​ | 167​ | ​ | ​ | 115​ | ​ | ​ | 175​ | ​ | ​ | 64​ | ​ | ​ | 246​ | ​ | ​ | 77​ | ​ | ​ | ​ | ​ | ​ | 905​ | ​
Dec. 31, 2018 | ​ | ​ | 208​ | ​ | ​ | 48​ | ​ | ​ | 493​ | ​ | ​ | 279​ | ​ | ​ | 718​ | ​ | ​ | 704​ | ​ | ​ | 476​ | ​ | ​ | 252​ | ​ | ​ | 5​ | ​ | ​ | 3,183​ | ​
developed | ​ | ​ | 156​ | ​ | ​ | 44​ | ​ | ​ | 317​ | ​ | ​ | 153​ | ​ | ​ | 551​ | ​ | ​ | 587​ | ​ | ​ | 252​ | ​ | ​ | 143​ | ​ | ​ | 5​ | ​ | ​ | 2,208​ | ​
undeveloped | ​ | ​ | 52​ | ​ | ​ | 4​ | ​ | ​ | 176​ | ​ | ​ | 126​ | ​ | ​ | 167​ | ​ | ​ | 117​ | ​ | ​ | 224​ | ​ | ​ | 109​ | ​ | ​ | ​ | ​ | ​ | 975​ | ​
Dec. 31, 2017 | ​ | ​ | 215​ | ​ | ​ | 360​ | ​ | ​ | 476​ | ​ | ​ | 280​ | ​ | ​ | 764​ | ​ | ​ | 766​ | ​ | ​ | 232​ | ​ | ​ | 162​ | ​ | ​ | 7​ | ​ | ​ | 3,262​ | ​
developed | ​ | ​ | 169​ | ​ | ​ | 219​ | ​ | ​ | 306​ | ​ | ​ | 203​ | ​ | ​ | 546​ | ​ | ​ | 547​ | ​ | ​ | 81​ | ​ | ​ | 144​ | ​ | ​ | 5​ | ​ | ​ | 2,220​ | ​
undeveloped | ​ | ​ | 46​ | ​ | ​ | 141​ | ​ | ​ | 170​ | ​ | ​ | 77​ | ​ | ​ | 218​ | ​ | ​ | 219​ | ​ | ​ | 151​ | ​ | ​ | 18​ | ​ | ​ | 2​ | ​ | ​ | 1,042​ | ​
Equity-accounted entities1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dec. 31, 2019 | ​ | ​ | ​ | ​ | ​ | 424​ | ​ | ​ | 12​ | ​ | ​ | ​ | ​ | ​ | 10​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 31​ | ​ | ​ | ​ | ​ | ​ | 477​ | ​
developed | ​ | ​ | ​ | ​ | ​ | 219​ | ​ | ​ | 12​ | ​ | ​ | ​ | ​ | ​ | 7​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 31​ | ​ | ​ | ​ | ​ | ​ | 269​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | 205​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 208​ | ​
Dec. 31, 2018 | ​ | ​ | ​ | ​ | ​ | 297​ | ​ | ​ | 11​ | ​ | ​ | ​ | ​ | ​ | 12​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37​ | ​ | ​ | ​ | ​ | ​ | 357​ | ​
developed | ​ | ​ | ​ | ​ | ​ | 154​ | ​ | ​ | 11​ | ​ | ​ | ​ | ​ | ​ | 8​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32​ | ​ | ​ | ​ | ​ | ​ | 205​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | 143​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5​ | ​ | ​ | ​ | ​ | ​ | 152​ | ​
Dec. 31, 2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12​ | ​ | ​ | ​ | ​ | ​ | 12​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 136​ | ​ | ​ | ​ | ​ | ​ | 160​ | ​
developed | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12​ | ​ | ​ | ​ | ​ | ​ | 6​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25​ | ​ | ​ | ​ | ​ | ​ | 43​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 111​ | ​ | ​ | ​ | ​ | ​ | 117​ | ​
Consolidated subsidiaries and equity accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dec. 31, 2019 | ​ | ​ | 194​ | ​ | ​ | 465​ | ​ | ​ | 480​ | ​ | ​ | 264​ | ​ | ​ | 704​ | ​ | ​ | 746​ | ​ | ​ | 491​ | ​ | ​ | 256​ | ​ | ​ | 1​ | ​ | ​ | 3,601​ | ​
developed | ​ | ​ | 137​ | ​ | ​ | 256​ | ​ | ​ | 313​ | ​ | ​ | 149​ | ​ | ​ | 526​ | ​ | ​ | 682​ | ​ | ​ | 245​ | ​ | ​ | 179​ | ​ | ​ | 1​ | ​ | ​ | 2,488​ | ​
undeveloped | ​ | ​ | 57​ | ​ | ​ | 209​ | ​ | ​ | 167​ | ​ | ​ | 115​ | ​ | ​ | 178​ | ​ | ​ | 64​ | ​ | ​ | 246​ | ​ | ​ | 77​ | ​ | ​ | ​ | ​ | ​ | 1,113​ | ​
Dec. 31, 2018 | ​ | ​ | 208​ | ​ | ​ | 345​ | ​ | ​ | 504​ | ​ | ​ | 279​ | ​ | ​ | 730​ | ​ | ​ | 704​ | ​ | ​ | 476​ | ​ | ​ | 289​ | ​ | ​ | 5​ | ​ | ​ | 3,540​ | ​
developed | ​ | ​ | 156​ | ​ | ​ | 198​ | ​ | ​ | 328​ | ​ | ​ | 153​ | ​ | ​ | 559​ | ​ | ​ | 587​ | ​ | ​ | 252​ | ​ | ​ | 175​ | ​ | ​ | 5​ | ​ | ​ | 2,413​ | ​
undeveloped | ​ | ​ | 52​ | ​ | ​ | 147​ | ​ | ​ | 176​ | ​ | ​ | 126​ | ​ | ​ | 171​ | ​ | ​ | 117​ | ​ | ​ | 224​ | ​ | ​ | 114​ | ​ | ​ | ​ | ​ | ​ | 1,127​ | ​
Dec. 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​ | ​
undeveloped | ​ | ​ | 46​ | ​ | ​ | 141​ | ​ | ​ | 170​ | ​ | ​ | 77​ | ​ | ​ | 224​ | ​ | ​ | 219​ | ​ | ​ | 151​ | ​ | ​ | 129​ | ​ | ​ | 2​ | ​ | ​ | 1,159​ | ​

​
(1)
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.
​
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TABLE OF CONTENTS

NATURAL GAS (BCF) | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub- Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | Americas | ​ | ​ | Australia and Oceania | ​ | ​ | Total reserves | ​
Consolidated subsidiaries1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dec. 31, 2019 | ​ | ​ | 752​ | ​ | ​ | 262​ | ​ | ​ | 2,738​ | ​ | ​ | 5,191​ | ​ | ​ | 4,103​ | ​ | ​ | 1,969​ | ​ | ​ | 1,349​ | ​ | ​ | 240​ | ​ | ​ | 507​ | ​ | ​ | 17,111​ | ​
developed | ​ | ​ | 657​ | ​ | ​ | 242​ | ​ | ​ | 1,374​ | ​ | ​ | 4,777​ | ​ | ​ | 1,858​ | ​ | ​ | 1,969​ | ​ | ​ | 685​ | ​ | ​ | 186​ | ​ | ​ | 322​ | ​ | ​ | 12,070​ | ​
undeveloped | ​ | ​ | 95​ | ​ | ​ | 20​ | ​ | ​ | 1,364​ | ​ | ​ | 414​ | ​ | ​ | 2,245​ | ​ | ​ | ​ | ​ | ​ | 664​ | ​ | ​ | 54​ | ​ | ​ | 185​ | ​ | ​ | 5,041​ | ​
Dec. 31, 2018 | ​ | ​ | 1,199​ | ​ | ​ | 320​ | ​ | ​ | 2,890​ | ​ | ​ | 5,275​ | ​ | ​ | 3,506​ | ​ | ​ | 1,989​ | ​ | ​ | 1,217​ | ​ | ​ | 277​ | ​ | ​ | 651​ | ​ | ​ | 17,324​ | ​
developed | ​ | ​ | 980​ | ​ | ​ | 300​ | ​ | ​ | 1,447​ | ​ | ​ | 3,331​ | ​ | ​ | 1,871​ | ​ | ​ | 1,846​ | ​ | ​ | 822​ | ​ | ​ | 154​ | ​ | ​ | 452​ | ​ | ​ | 11,203​ | ​
undeveloped | ​ | ​ | 219​ | ​ | ​ | 20​ | ​ | ​ | 1,443​ | ​ | ​ | 1,944​ | ​ | ​ | 1,635​ | ​ | ​ | 143​ | ​ | ​ | 395​ | ​ | ​ | 123​ | ​ | ​ | 199​ | ​ | ​ | 6,121​ | ​
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​ | ​ | ​ | 54​ | ​ | ​ | 190​ | ​ | ​ | 7,755​ | ​
Equity-accounted entities2 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dec. 31, 2019 | ​ | ​ | ​ | ​ | ​ | 772​ | ​ | ​ | 14​ | ​ | ​ | ​ | ​ | ​ | 287​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,648​ | ​ | ​ | ​ | ​ | ​ | 2,721​ | ​
developed | ​ | ​ | ​ | ​ | ​ | 597​ | ​ | ​ | 14​ | ​ | ​ | ​ | ​ | ​ | 88​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,648​ | ​ | ​ | ​ | ​ | ​ | 2,347​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | 175​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 199​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 374​ | ​
Dec. 31, 2018 | ​ | ​ | ​ | ​ | ​ | 360​ | ​ | ​ | 14​ | ​ | ​ | ​ | ​ | ​ | 310​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,716​ | ​ | ​ | ​ | ​ | ​ | 2,400​ | ​
developed | ​ | ​ | ​ | ​ | ​ | 276​ | ​ | ​ | 14​ | ​ | ​ | ​ | ​ | ​ | 57​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,716​ | ​ | ​ | ​ | ​ | ​ | 2,063​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | 84​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 253​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 337​ | ​
Dec. 31, 2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14​ | ​ | ​ | ​ | ​ | ​ | 349​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,819​ | ​ | ​ | ​ | ​ | ​ | 2,182​ | ​
developed | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14​ | ​ | ​ | ​ | ​ | ​ | 83​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,819​ | ​ | ​ | ​ | ​ | ​ | 1,916​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 266​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 266​ | ​
Consolidated subsidiaries and equity accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dec. 31, 2019 | ​ | ​ | 752​ | ​ | ​ | 1,034​ | ​ | ​ | 2,752​ | ​ | ​ | 5,191​ | ​ | ​ | 4,390​ | ​ | ​ | 1,969​ | ​ | ​ | 1,349​ | ​ | ​ | 1,888​ | ​ | ​ | 507​ | ​ | ​ | 19,832​ | ​
developed | ​ | ​ | 657​ | ​ | ​ | 839​ | ​ | ​ | 1,388​ | ​ | ​ | 4,777​ | ​ | ​ | 1,946​ | ​ | ​ | 1,969​ | ​ | ​ | 685​ | ​ | ​ | 1,834​ | ​ | ​ | 322​ | ​ | ​ | 14,417​ | ​
undeveloped | ​ | ​ | 95​ | ​ | ​ | 195​ | ​ | ​ | 1,364​ | ​ | ​ | 414​ | ​ | ​ | 2,444​ | ​ | ​ | ​ | ​ | ​ | 664​ | ​ | ​ | 54​ | ​ | ​ | 185​ | ​ | ​ | 5,415​ | ​
Dec. 31, 2018 | ​ | ​ | 1,199​ | ​ | ​ | 680​ | ​ | ​ | 2,904​ | ​ | ​ | 5,275​ | ​ | ​ | 3,816​ | ​ | ​ | 1,989​ | ​ | ​ | 1,217​ | ​ | ​ | 1,993​ | ​ | ​ | 651​ | ​ | ​ | 19,724​ | ​
developed | ​ | ​ | 980​ | ​ | ​ | 576​ | ​ | ​ | 1,461​ | ​ | ​ | 3,331​ | ​ | ​ | 1,928​ | ​ | ​ | 1,846​ | ​ | ​ | 822​ | ​ | ​ | 1,870​ | ​ | ​ | 452​ | ​ | ​ | 13,266​ | ​
undeveloped | ​ | ​ | 219​ | ​ | ​ | 104​ | ​ | ​ | 1,443​ | ​ | ​ | 1,944​ | ​ | ​ | 1,888​ | ​ | ​ | 143​ | ​ | ​ | 395​ | ​ | ​ | 123​ | ​ | ​ | 199​ | ​ | ​ | 6,458​ | ​
Dec. 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​ | ​
undeveloped | ​ | ​ | 144​ | ​ | ​ | 125​ | ​ | ​ | 1,912​ | ​ | ​ | 2,930​ | ​ | ​ | 2,233​ | ​ | ​ | 230​ | ​ | ​ | 203​ | ​ | ​ | 54​ | ​ | ​ | 190​ | ​ | ​ | 8,021​ | ​

​
(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.
​
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Proved reserves of natural gas liquids are immaterial to the Group operations.
Volumes of oil and natural gas applicable to long- term supply agreements with foreign governments in mineral assets where Eni is operator totaled 128 mmBOE as of December 31, 2019 (148 and 178 mmBOE as of December 31, 2018 and 2017, respectively). Said volumes are not included in reserves volumes shown in the table herein.

​ | ​ | ​ | Subsidiaries | ​ | ​ | Equity-accounted entities | ​
(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 | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 332 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 184 | ​ | ​ | ​ | ​ | ​ | 363 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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 compared to production sold of 630.6 mmBOE (622.3 mmboe in 2017 and 625.0 mmboe in 2018) reflected hydrocarbons volumes of 45.4 mmBOE consumed in operations (35.2 mmBOE in 2017 and 43.5 mmBOE in 2018), changes in inventories and other factors.
​

​ | ​ | ​ | 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, 2019 totaled 7,268 mmBOE (liquids 3,601 mmBBL; natural gas 19,832 BCF). Eni’s proved reserves reported an increase of 115 mmBOE, or 1.6%, from December 31, 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 2019 were 794 mmBOE; of which 548 mmBOE came from Eni’s subsidiaries, which include sales of reserves as part of a long-term supply agreement as discussed above, while 246 mmBOE from Eni’s equity-accounted entities.
Due to a decrease in oil and gas prices compared to the Brent reference price used in the reserve estimation process at $62.7 per barrel in 2019 ($71.4 per barrel in 2018), our all sources additions decreased by 58 mmBOE, due to 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 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 reported by Eni’s subsidiaries and equity-accounted entities was 117% in 2019 (124% in 2018 and 25% in 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 in estimates of oil and natural gas reserves”.
The average reserves life index of Eni’s proved reserves was 10.6 years as of December 31, 2019, which included reserves of both subsidiaries and equity-accounted entities.
Eni’s subsidiaries
Eni’s subsidiaries added 548 mmBOE of proved oil and gas reserves in 2019 net of sales and purchase of minerals- in- place. This comprised 236 mmBBL of liquids and 1,525 BCF of natural gas. The breakdown of total additions to proved reserves is the following: (i) extensions and discoveries were up by 101 mmBOE mainly due to the final investment decisions made for the projects of Dalma in the 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 up by 459 mmBOE and mainly derived from the upward revisions of certain gas fields in Nigeria to feed the expansion project of the Bonny liquefaction plant, owned by Nigeria LNG (Eni’s interest 10.4%), and progress in development activities at the Zohr project in Egypt, Kashagan project in Kazakhstan and Berkine North in Algeria; (iii) purchases of mineral-in-place referred to Oooguruk production field in Alaska, as described above; and (v) sales of minerals-in-place referred to the disposal of a 20% stake of the Merakes discovery in Indonesia and entire participation of Ecuador production assets. In addition, sales of minerals- in- place include approximately 4 million boe of volumes (mainly gas) as part of a long-term supply agreement to a state- owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause, as discussed above.
Eni’s share of equity-accounted entities
Eni’s share of equity-accounted entities added 246 mmBOE of proved oil and gas reserves in 2019 net of sale and purchase minerals-in-place. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates were up by 62 mmBOE mainly due to the progress in 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, 2019 totaled 2,114 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,113 mmBBL, mainly concentrated in Africa and Asia. Proved undeveloped reserves of natural gas amounted to 5,415 BCF, mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 905 mmBBL of liquids and 5,041 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves 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 195 mmBOE mainly due to progress made in maturing PUDs to proved developed (655 mmBOE). Additions to PUDs for the year included: (i) extensions and discoveries (up by 101 mmBOE) mainly due to the final investment decisions made for the Dalma project in the United Arab Emirates, the Assa North project in Nigeria and the Agogo field in Angola; (ii) revisions of previous estimates (up by 327 mmBOE) mainly reported in Nigeria due to the final investment decision made for an expansion project of the Bonny liquefaction plant and in Egypt due to the development activity of the Zohr project; (iii) purchases (up by 44 mmBOE) mainly related to the Vår Energi acquisition in Norway as discussed above; and (iv) sales of minerals-in-place (down by 12 mmBOE) related to minor assets in Norway and the Merakes discovery in Indonesia, as mentioned above.
During 2019, Eni matured 655 mmBOE of proved undeveloped reserves to proved developed reserves due to progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the following fields/projects: Zohr and Nidoco in North West Egypt, Kashagan in Kazakhstan, Litchendjili in Congo, Ngl Eleme in Nigeria and Area 1 in Mexico.
In 2019, capital expenditure amounted to approximately €6.8 billion to progress the development of PUDs.
Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complexity of development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 0.5 BBOE of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date and decreased 0.1 BBOE 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 remained undeveloped for five years or more at the balance sheet date mainly related to: (i) the Zubair field in Iraq (0.1 BBOE), where development of PUDs has been conditioned by the drilling of additional production and injection wells to be linked to the production facilities, which were already completed to achieve the full field production plateau of 700 KBBL/d; (ii) certain Libyan gas fields (0.3 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long- term gas supply agreement currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields, which are expected to be put in production over the next several years; and (iii) other fields in Italy and Egypt (0.1 BBOE) where development activities are in progress. (See also our discussion under the “Risk factors” section about risks associated with oil and gas development projects).
Eni remains strongly committed to put these projects into production in the coming years. The length of the development period depends on a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project.
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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 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 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 91% of delivery commitments.
Eni has met all contractual delivery commitments as of December 31, 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 uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni’s important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni’s production operations.
In 2019, oil and natural gas production available for sale averaged 1,736 KBOE/d (1,732 KBOE/d in 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 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 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 current situation in the Country, as well as mature fields decline, mainly in Italy and Angola. New field start-ups and ramp-ups of production added an estimated approximately 250 KBOE/d of new production.
Production for the year excluded gas volumes which were not lifted by a long-term buyer who nonetheless paid the underlying price as provided by the take-or-pay clause of the long-term supply contract.
Liquids production (890 KBBL/d) increased by 6 KBBL/d, or approximately 1% from the full year of 2018. Start- ups and ramp-ups of the period, mainly in Mexico, Libya and Ghana, and production growth in the United Arab Emirates and Nigeria were partly offset by facility shutdowns, mainly in Congo, lower production in Venezuela and mature fields decline.
Natural gas production (4,576 mmCF/d) decreased by 54 mmCF/d, or 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 Ghana, and the growth in Nigeria.
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Sales volumes of oil and gas production sold were 630.6 mmBOE. The 3.2 mmBOE difference over production on available -for-sale basis (633.8 mmBOE in 2019) reflected mainly changes in inventory and other factors. Approximately 66% of liquids production sold (325.4 mmBBL) was destined to Eni’s mid-downstream sectors. About 18% of natural gas production sold (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.
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 hydrocarbons consumed in operations. Said volumes were 124, 119 and 97 KBOE/d 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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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 hydrocarbons consumed in operations. Said volumes were 45.4, 43.5 and 35.2 mmBOE in 2019, 2018 and 2017, respectively.
​
(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.
​
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Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 71 KBOE/d, 54 KBOE/d and 55 KBOE/d in 2019, 2018 and 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. In addition, Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided.
Average sales prices and production cost per unit of production

($) | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub- Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | Americas | ​ | ​ | Australia and Oceania | ​ | ​ | Total | ​
2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil and condensates, per BBL | ​ | ​ | 46.51​ | ​ | ​ | 47.81​ | ​ | ​ | 52.68​ | ​ | ​ | 46.06​ | ​ | ​ | 53.66​ | ​ | ​ | 50.62​ | ​ | ​ | 48.94​ | ​ | ​ | 44.24​ | ​ | ​ | 49.36​ | ​ | ​ | 50.33​ | ​
Natural gas, per KCF | ​ | ​ | 6.45​ | ​ | ​ | 5.81​ | ​ | ​ | 2.96​ | ​ | ​ | 4.19​ | ​ | ​ | 1.87​ | ​ | ​ | 0.58​ | ​ | ​ | 3.75​ | ​ | ​ | 2.35​ | ​ | ​ | 4.05​ | ​ | ​ | 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 | ​ | ​ | 8.12​ | ​ | ​ | 8.85​ | ​ | ​ | 3.08​ | ​ | ​ | 4.35​ | ​ | ​ | 9.64​ | ​ | ​ | 6.68​ | ​ | ​ | 5.96​ | ​ | ​ | 8.36​ | ​ | ​ | 7.11​ | ​ | ​ | 6.33​ | ​
Equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil and condensates, per BBL | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17.95​ | ​ | ​ | ​ | ​ | ​ | 38.34​ | ​ | ​ | ​ | ​ | ​ | 44.43​ | ​ | ​ | 41.49​ | ​ | ​ | ​ | ​ | ​ | 38.65​ | ​
Natural gas, per KCF | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2.63​ | ​ | ​ | ​ | ​ | ​ | 7.34​ | ​ | ​ | ​ | ​ | ​ | 6.06​ | ​ | ​ | 4.19​ | ​ | ​ | ​ | ​ | ​ | 4.64​ | ​
Total hydrocarbons, per BOE | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17.35​ | ​ | ​ | ​ | ​ | ​ | 39.65​ | ​ | ​ | ​ | ​ | ​ | 36.76​ | ​ | ​ | 26.50​ | ​ | ​ | ​ | ​ | ​ | 28.30​ | ​
Average production cost, per BOE | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5.94​ | ​ | ​ | ​ | ​ | ​ | 3.45​ | ​ | ​ | ​ | ​ | ​ | 11.64​ | ​ | ​ | 1.99​ | ​ | ​ | ​ | ​ | ​ | 2.71​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil and condensates, per BBL | ​ | ​ | 61.58​ | ​ | ​ | 64.51​ | ​ | ​ | 65.95​ | ​ | ​ | 62.97​ | ​ | ​ | 68.76​ | ​ | ​ | 66.78​ | ​ | ​ | 68.35​ | ​ | ​ | 57.22​ | ​ | ​ | 68.72​ | ​ | ​ | 65.79​ | ​
Natural gas, per KCF | ​ | ​ | 8.37​ | ​ | ​ | 7.99​ | ​ | ​ | 4.97​ | ​ | ​ | 4.85​ | ​ | ​ | 2.38​ | ​ | ​ | 0.77​ | ​ | ​ | 6.11​ | ​ | ​ | 2.38​ | ​ | ​ | 4.80​ | ​ | ​ | 5.17​ | ​
Average production cost, per BOE | ​ | ​ | 9.97​ | ​ | ​ | 8.39​ | ​ | ​ | 3.16​ | ​ | ​ | 3.87​ | ​ | ​ | 10.25​ | ​ | ​ | 6.53​ | ​ | ​ | 4.68​ | ​ | ​ | 10.56​ | ​ | ​ | 7.09​ | ​ | ​ | 6.50​ | ​
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 well activity
In 2019, a total of 241 development wells were drilled (85.4 of which represented Eni’s share) as compared to 209 development wells drilled in 2018 (80.2 of which represented Eni’s share) and 178 development wells drilled in 2017 (90.7 of which represented Eni’s share).
The drilling of 84 development wells (21.0 of which represented Eni’s share) is currently underway.
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The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 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.

​ | ​ | ​ | Net wells completed | ​ | ​ | Wells in progress at 31 Dec. | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​ | ​ | 2019 | ​
(units) | ​ | ​ | Productive | ​ | ​ | Dry | ​ | ​ | Productive | ​ | ​ | Dry | ​ | ​ | Productive | ​ | ​ | Dry | ​ | ​ | Gross | ​ | ​ | Net | ​
Italy | ​ | ​ | 3.0​ | ​ | ​ | ​ | ​ | ​ | 3.0​ | ​ | ​ | ​ | ​ | ​ | 2.6​ | ​ | ​ | ​ | ​ | ​ | 2.0​ | ​ | ​ | 1.6​ | ​
Rest of Europe | ​ | ​ | 3.3​ | ​ | ​ | ​ | ​ | ​ | 2.8​ | ​ | ​ | 0.3​ | ​ | ​ | 2.7​ | ​ | ​ | 0.2​ | ​ | ​ | 25.0​ | ​ | ​ | 2.2​ | ​
North Africa | ​ | ​ | 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 | ​ | ​ | 7.0​ | ​ | ​ | ​ | ​ | ​ | 7.3​ | ​ | ​ | 0.1​ | ​ | ​ | 8.6​ | ​ | ​ | ​ | ​ | ​ | 19.0​ | ​ | ​ | 3.4​ | ​
Kazakhstan | ​ | ​ | 0.9​ | ​ | ​ | ​ | ​ | ​ | 0.9​ | ​ | ​ | ​ | ​ | ​ | 1.2​ | ​ | ​ | ​ | ​ | ​ | 1.0​ | ​ | ​ | 0.3​ | ​
Rest of Asia | ​ | ​ | 27.3​ | ​ | ​ | 2.2​ | ​ | ​ | 21.9​ | ​ | ​ | ​ | ​ | ​ | 15.0​ | ​ | ​ | 0.2​ | ​ | ​ | 25.0​ | ​ | ​ | 7.9​ | ​
Americas | ​ | ​ | 2.1​ | ​ | ​ | ​ | ​ | ​ | 2.3​ | ​ | ​ | ​ | ​ | ​ | 3.1​ | ​ | ​ | ​ | ​ | ​ | 1.0​ | ​ | ​ | 1.0​ | ​
Australia and Oceania | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.8​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total including equity-accounted entities | ​ | ​ | 82.1​ | ​ | ​ | 3.3​ | ​ | ​ | 79.3​ | ​ | ​ | 0.9​ | ​ | ​ | 88.0​ | ​ | ​ | 2.7​ | ​ | ​ | 84.0​ | ​ | ​ | 21.0​ | ​

Exploration well activity
In 2019, a total of 31 new exploratory wells were drilled (16.3 of which represented Eni’s share), as compared to 24 exploratory wells drilled in 2018 (15.6 of which represented Eni’s share) and 25 exploratory wells drilled in 2017 (15.9 of which represented Eni’s share).
The overall commercial success rate was 36% (47% net to Eni) as compared to 62% (66% net to Eni) and 60% (52% net to Eni) in 2018 and 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, 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.

​ | ​ | ​ | Net wells completed | ​ | ​ | Wells in progress at Dec. 31(1) | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​ | ​ | 2019 | ​
(units) | ​ | ​ | Productive | ​ | ​ | Dry | ​ | ​ | Productive | ​ | ​ | Dry | ​ | ​ | Productive | ​ | ​ | Dry | ​ | ​ | Gross | ​ | ​ | Net | ​
Italy | ​ | ​ | ​ | ​ | ​ | 0.5​ | ​ | ​ | 1.8​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Rest of Europe | ​ | ​ | 0.3​ | ​ | ​ | 1.4​ | ​ | ​ | ​ | ​ | ​ | 0.5​ | ​ | ​ | 1.2​ | ​ | ​ | 1.3​ | ​ | ​ | 14.0​ | ​ | ​ | 3.5​ | ​
North Africa | ​ | ​ | 0.5​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.5​ | ​ | ​ | 0.5​ | ​ | ​ | ​ | ​ | ​ | 12.0​ | ​ | ​ | 9.5​ | ​
Egypt | ​ | ​ | 4.5​ | ​ | ​ | 1.5​ | ​ | ​ | 1.7​ | ​ | ​ | 1.5​ | ​ | ​ | 2.5​ | ​ | ​ | 5.4​ | ​ | ​ | 13.0​ | ​ | ​ | 9.7​ | ​
Sub-Saharan Africa | ​ | ​ | 0.5​ | ​ | ​ | 0.9​ | ​ | ​ | 0.4​ | ​ | ​ | ​ | ​ | ​ | 2.9​ | ​ | ​ | 0.3​ | ​ | ​ | 38.0​ | ​ | ​ | 18.4​ | ​
Kazakhstan | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6.0​ | ​ | ​ | 1.1​ | ​
Rest of Asia | ​ | ​ | ​ | ​ | ​ | 1.7​ | ​ | ​ | 2.2​ | ​ | ​ | 2.6​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11.0​ | ​ | ​ | 3.8​ | ​
Americas | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.0​ | ​ | ​ | ​ | ​ | ​ | 0.5​ | ​ | ​ | ​ | ​ | ​ | 3.0​ | ​ | ​ | 1.4​ | ​
Australia and Oceania | ​ | ​ | ​ | ​ | ​ | 0.5​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.0​ | ​ | ​ | 0.3​ | ​
Total including equity-accounted entities | ​ | ​ | 5.8​ | ​ | ​ | 6.5​ | ​ | ​ | 10.1​ | ​ | ​ | 5.1​ | ​ | ​ | 7.6​ | ​ | ​ | 7.0​ | ​ | ​ | 98.0​ | ​ | ​ | 47.7​ | ​

​
(1)
Includes temporary suspended wells pending further evaluation.
​
Oil and gas properties, operations and acreage
In 2019, Eni performed its operations in 41 Countries located in five continents. As of December 31, 2019, Eni’s mineral right portfolio consisted of 873 exclusive or shared rights of exploration and development activities for a total acreage of 357,854 square kilometers net to Eni (406,505 square kilometers net to Eni as of December 31, 2018). Developed acreage was 29,283 square kilometers and undeveloped acreage was 328,571 square kilometers net to Eni.
In 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 Myanmar, Indonesia and the United States for a total acreage of approximately 970 square
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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, 2019. A gross acreage is one in which Eni owns a working interest.

​ | ​ | ​ | December 31, 2018 | ​ | ​ | December 31, 2019 | ​
​ | ​ | ​ | Total net acreage (a) | ​ | ​ | Number of interests | ​ | ​ | Gross developed acreage (a) (b) | ​ | ​ | Gross undeveloped acreage (a) | ​ | ​ | Total gross acreage (a) | ​ | ​ | Net developed acreage (a) (b) | ​ | ​ | Net undeveloped acreage(a) | ​ | ​ | Total net acreage(a) | ​
EUROPE | ​ | ​ | 46,332​ | ​ | ​ | 309​ | ​ | ​ | 15,282​ | ​ | ​ | 58,616​ | ​ | ​ | 73,898​ | ​ | ​ | 9,278​ | ​ | ​ | 28,750​ | ​ | ​ | 38,028​ | ​
Italy | ​ | ​ | 14,987​ | ​ | ​ | 128​ | ​ | ​ | 9,545​ | ​ | ​ | 7,595​ | ​ | ​ | 17,140​ | ​ | ​ | 7,887​ | ​ | ​ | 5,845​ | ​ | ​ | 13,732​ | ​
Rest of Europe | ​ | ​ | 31,345​ | ​ | ​ | 181​ | ​ | ​ | 5,737​ | ​ | ​ | 51,021​ | ​ | ​ | 56,758​ | ​ | ​ | 1,391​ | ​ | ​ | 22,905​ | ​ | ​ | 24,296​ | ​
Cyprus | ​ | ​ | 17,111​ | ​ | ​ | 7​ | ​ | ​ | ​ | ​ | ​ | 26,614​ | ​ | ​ | 26,614​ | ​ | ​ | ​ | ​ | ​ | 14,557​ | ​ | ​ | 14,557​ | ​
Greenland | ​ | ​ | 1,909​ | ​ | ​ | 2​ | ​ | ​ | ​ | ​ | ​ | 4,890​ | ​ | ​ | 4,890​ | ​ | ​ | ​ | ​ | ​ | 1,909​ | ​ | ​ | 1,909​ | ​
Montenegro | ​ | ​ | 614​ | ​ | ​ | 1​ | ​ | ​ | ​ | ​ | ​ | 1,228​ | ​ | ​ | 1,228​ | ​ | ​ | ​ | ​ | ​ | 614​ | ​ | ​ | 614​ | ​
Norway | ​ | ​ | 2,628​ | ​ | ​ | 131​ | ​ | ​ | 4,828​ | ​ | ​ | 14,577​ | ​ | ​ | 19,405​ | ​ | ​ | 777​ | ​ | ​ | 3,436​ | ​ | ​ | 4,213​ | ​
Portugal | ​ | ​ | 3,182​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
United Kingdom | ​ | ​ | 4,018​ | ​ | ​ | 38​ | ​ | ​ | 909​ | ​ | ​ | 1,011​ | ​ | ​ | 1,920​ | ​ | ​ | 614​ | ​ | ​ | 506​ | ​ | ​ | 1,120​ | ​
Other Countries | ​ | ​ | 1,883​ | ​ | ​ | 2​ | ​ | ​ | ​ | ​ | ​ | 2,701​ | ​ | ​ | 2,701​ | ​ | ​ | ​ | ​ | ​ | 1,883​ | ​ | ​ | 1,883​ | ​
AFRICA | ​ | ​ | 165,699​ | ​ | ​ | 260​ | ​ | ​ | 54,351​ | ​ | ​ | 273,494​ | ​ | ​ | 327,845​ | ​ | ​ | 15,194​ | ​ | ​ | 148,431​ | ​ | ​ | 163,625​ | ​
North Africa | ​ | ​ | 33,932​ | ​ | ​ | 69​ | ​ | ​ | 17,628​ | ​ | ​ | 51,716​ | ​ | ​ | 69,344​ | ​ | ​ | 7,966​ | ​ | ​ | 23,907​ | ​ | ​ | 31,873​ | ​
Algeria | ​ | ​ | 1,155​ | ​ | ​ | 47​ | ​ | ​ | 12,157​ | ​ | ​ | 279​ | ​ | ​ | 12,436​ | ​ | ​ | 5,472​ | ​ | ​ | 100​ | ​ | ​ | 5,572​ | ​
Libya | ​ | ​ | 13,294​ | ​ | ​ | 11​ | ​ | ​ | 1,963​ | ​ | ​ | 24,673​ | ​ | ​ | 26,636​ | ​ | ​ | 958​ | ​ | ​ | 12,336​ | ​ | ​ | 13,294​ | ​
Morocco | ​ | ​ | 17,925​ | ​ | ​ | 1​ | ​ | ​ | ​ | ​ | ​ | 23,900​ | ​ | ​ | 23,900​ | ​ | ​ | ​ | ​ | ​ | 10,755​ | ​ | ​ | 10,755​ | ​
Tunisia | ​ | ​ | 1,558​ | ​ | ​ | 10​ | ​ | ​ | 3,508​ | ​ | ​ | 2,864​ | ​ | ​ | 6,372​ | ​ | ​ | 1,536​ | ​ | ​ | 716​ | ​ | ​ | 2,252​ | ​
Egypt | ​ | ​ | 5,248​ | ​ | ​ | 56​ | ​ | ​ | 5,659​ | ​ | ​ | 15,710​ | ​ | ​ | 21,369​ | ​ | ​ | 2,113​ | ​ | ​ | 5,500​ | ​ | ​ | 7,613​ | ​
Sub-Saharan Africa | ​ | ​ | 126,519​ | ​ | ​ | 135​ | ​ | ​ | 31,064​ | ​ | ​ | 206,068​ | ​ | ​ | 237,132​ | ​ | ​ | 5,115​ | ​ | ​ | 119,024​ | ​ | ​ | 124,139​ | ​
Angola | ​ | ​ | 5,303​ | ​ | ​ | 45​ | ​ | ​ | 8,349​ | ​ | ​ | 7,841​ | ​ | ​ | 16,190​ | ​ | ​ | 1,073​ | ​ | ​ | 2,671​ | ​ | ​ | 3,744​ | ​
Congo | ​ | ​ | 1,471​ | ​ | ​ | 25​ | ​ | ​ | 1,430​ | ​ | ​ | 1,320​ | ​ | ​ | 2,750​ | ​ | ​ | 843​ | ​ | ​ | 628​ | ​ | ​ | 1,471​ | ​
Gabon | ​ | ​ | 4,107​ | ​ | ​ | 4​ | ​ | ​ | ​ | ​ | ​ | 4,107​ | ​ | ​ | 4,107​ | ​ | ​ | ​ | ​ | ​ | 4,107​ | ​ | ​ | 4,107​ | ​
Ghana | ​ | ​ | 579​ | ​ | ​ | 3​ | ​ | ​ | 226​ | ​ | ​ | 1,127​ | ​ | ​ | 1,353​ | ​ | ​ | 100​ | ​ | ​ | 479​ | ​ | ​ | 579​ | ​
Ivory Coast | ​ | ​ | 2,905​ | ​ | ​ | 5​ | ​ | ​ | ​ | ​ | ​ | 4,921​ | ​ | ​ | 4,921​ | ​ | ​ | ​ | ​ | ​ | 3,724​ | ​ | ​ | 3,724​ | ​
Kenya | ​ | ​ | 43,948​ | ​ | ​ | 6​ | ​ | ​ | ​ | ​ | ​ | 50,677​ | ​ | ​ | 50,677​ | ​ | ​ | ​ | ​ | ​ | 43,948​ | ​ | ​ | 43,948​ | ​
Mozambique | ​ | ​ | 978​ | ​ | ​ | 10​ | ​ | ​ | ​ | ​ | ​ | 25,304​ | ​ | ​ | 25,304​ | ​ | ​ | ​ | ​ | ​ | 4,349​ | ​ | ​ | 4,349​ | ​
Nigeria | ​ | ​ | 7,722​ | ​ | ​ | 32​ | ​ | ​ | 21,059​ | ​ | ​ | 8,631​ | ​ | ​ | 29,690​ | ​ | ​ | 3,099​ | ​ | ​ | 3,543​ | ​ | ​ | 6,642​ | ​
South Africa | ​ | ​ | 26,202​ | ​ | ​ | 1​ | ​ | ​ | ​ | ​ | ​ | 55,677​ | ​ | ​ | 55,677​ | ​ | ​ | ​ | ​ | ​ | 22,271​ | ​ | ​ | 22,271​ | ​
Other Countries | ​ | ​ | 33,304​ | ​ | ​ | 4​ | ​ | ​ | ​ | ​ | ​ | 46,463​ | ​ | ​ | 46,463​ | ​ | ​ | ​ | ​ | ​ | 33,304​ | ​ | ​ | 33,304​ | ​
ASIA | ​ | ​ | 181,414​ | ​ | ​ | 69​ | ​ | ​ | 12,686​ | ​ | ​ | 267,851​ | ​ | ​ | 280,537​ | ​ | ​ | 3,199​ | ​ | ​ | 139,497​ | ​ | ​ | 142,696​ | ​
Kazakhstan | ​ | ​ | 1,543​ | ​ | ​ | 8​ | ​ | ​ | 2,391​ | ​ | ​ | 5,124​ | ​ | ​ | 7,515​ | ​ | ​ | 442​ | ​ | ​ | 1,718​ | ​ | ​ | 2,160​ | ​
Rest of Asia | ​ | ​ | 179,871​ | ​ | ​ | 61​ | ​ | ​ | 10,295​ | ​ | ​ | 262,727​ | ​ | ​ | 273,022​ | ​ | ​ | 2,757​ | ​ | ​ | 137,779​ | ​ | ​ | 140,536​ | ​
Bahrain | ​ | ​ | ​ | ​ | ​ | 1​ | ​ | ​ | ​ | ​ | ​ | 2,858​ | ​ | ​ | 2,858​ | ​ | ​ | ​ | ​ | ​ | 2,858​ | ​ | ​ | 2,858​ | ​
China | ​ | ​ | 5,228​ | ​ | ​ | 6​ | ​ | ​ | 77​ | ​ | ​ | ​ | ​ | ​ | 77​ | ​ | ​ | 13​ | ​ | ​ | ​ | ​ | ​ | 13​ | ​
India | ​ | ​ | 5,244​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Indonesia | ​ | ​ | 23,769​ | ​ | ​ | 13​ | ​ | ​ | 2,605​ | ​ | ​ | 20,898​ | ​ | ​ | 23,503​ | ​ | ​ | 1,029​ | ​ | ​ | 14,926​ | ​ | ​ | 15,955​ | ​
Iraq | ​ | ​ | 446​ | ​ | ​ | 1​ | ​ | ​ | 1,074​ | ​ | ​ | ​ | ​ | ​ | 1,074​ | ​ | ​ | 446​ | ​ | ​ | ​ | ​ | ​ | 446​ | ​
Lebanon | ​ | ​ | 1,461​ | ​ | ​ | 2​ | ​ | ​ | ​ | ​ | ​ | 3,653​ | ​ | ​ | 3,653​ | ​ | ​ | ​ | ​ | ​ | 1,461​ | ​ | ​ | 1,461​ | ​
Myanmar | ​ | ​ | 13,558​ | ​ | ​ | 4​ | ​ | ​ | ​ | ​ | ​ | 24,080​ | ​ | ​ | 24,080​ | ​ | ​ | ​ | ​ | ​ | 14,147​ | ​ | ​ | 14,147​ | ​
Oman | ​ | ​ | 77,146​ | ​ | ​ | 1​ | ​ | ​ | ​ | ​ | ​ | 90,760​ | ​ | ​ | 90,760​ | ​ | ​ | ​ | ​ | ​ | 49,918​ | ​ | ​ | 49,918​ | ​
Pakistan | ​ | ​ | 5,786​ | ​ | ​ | 12​ | ​ | ​ | 3,390​ | ​ | ​ | 8,370​ | ​ | ​ | 11,760​ | ​ | ​ | 872​ | ​ | ​ | 2,907​ | ​ | ​ | 3,779​ | ​
Russia | ​ | ​ | 17,975​ | ​ | ​ | 2​ | ​ | ​ | ​ | ​ | ​ | 53,930​ | ​ | ​ | 53,930​ | ​ | ​ | ​ | ​ | ​ | 17,975​ | ​ | ​ | 17,975​ | ​
Timor Leste | ​ | ​ | 1,230​ | ​ | ​ | 4​ | ​ | ​ | ​ | ​ | ​ | 2,612​ | ​ | ​ | 2,612​ | ​ | ​ | ​ | ​ | ​ | 1,620​ | ​ | ​ | 1,620​ | ​
Turkmenistan | ​ | ​ | 180​ | ​ | ​ | 1​ | ​ | ​ | 200​ | ​ | ​ | ​ | ​ | ​ | 200​ | ​ | ​ | 180​ | ​ | ​ | ​ | ​ | ​ | 180​ | ​
United Arab Emirates | ​ | ​ | 1,472​ | ​ | ​ | 9​ | ​ | ​ | 2,949​ | ​ | ​ | 17,058​ | ​ | ​ | 20,007​ | ​ | ​ | 217​ | ​ | ​ | 10,170​ | ​ | ​ | 10,387​ | ​
Vietnam | ​ | ​ | 23,132​ | ​ | ​ | 4​ | ​ | ​ | ​ | ​ | ​ | 23,908​ | ​ | ​ | 23,908​ | ​ | ​ | ​ | ​ | ​ | 18,553​ | ​ | ​ | 18,553​ | ​
Other Countries | ​ | ​ | 3,244​ | ​ | ​ | 1​ | ​ | ​ | ​ | ​ | ​ | 14,600​ | ​ | ​ | 14,600​ | ​ | ​ | ​ | ​ | ​ | 3,244​ | ​ | ​ | 3,244​ | ​
AMERICAS | ​ | ​ | 9,303​ | ​ | ​ | 229​ | ​ | ​ | 2,299​ | ​ | ​ | 17,763​ | ​ | ​ | 20,062​ | ​ | ​ | 1,024​ | ​ | ​ | 9,679​ | ​ | ​ | 10,703​ | ​
Ecuador | ​ | ​ | 1,985​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Mexico | ​ | ​ | 3,000​ | ​ | ​ | 10​ | ​ | ​ | 14​ | ​ | ​ | 5,455​ | ​ | ​ | 5,469​ | ​ | ​ | 14​ | ​ | ​ | 3,092​ | ​ | ​ | 3,106​ | ​
United States | ​ | ​ | 2,191​ | ​ | ​ | 205​ | ​ | ​ | 1,024​ | ​ | ​ | 1,683​ | ​ | ​ | 2,707​ | ​ | ​ | 513​ | ​ | ​ | 1,422​ | ​ | ​ | 1,935​ | ​
Venezuela | ​ | ​ | 1,066​ | ​ | ​ | 6​ | ​ | ​ | 1,261​ | ​ | ​ | 1,543​ | ​ | ​ | 2,804​ | ​ | ​ | 497​ | ​ | ​ | 569​ | ​ | ​ | 1,066​ | ​
Other Countries | ​ | ​ | 1,061​ | ​ | ​ | 8​ | ​ | ​ | ​ | ​ | ​ | 9,082​ | ​ | ​ | 9,082​ | ​ | ​ | ​ | ​ | ​ | 4,596​ | ​ | ​ | 4,596​ | ​
AUSTRALIA AND OCEANIA | ​ | ​ | 3,757​ | ​ | ​ | 6​ | ​ | ​ | 728​ | ​ | ​ | 2,860​ | ​ | ​ | 3,588​ | ​ | ​ | 588​ | ​ | ​ | 2,214​ | ​ | ​ | 2,802​ | ​
Australia | ​ | ​ | 3,757​ | ​ | ​ | 6​ | ​ | ​ | 728​ | ​ | ​ | 2,860​ | ​ | ​ | 3,588​ | ​ | ​ | 588​ | ​ | ​ | 2,214​ | ​ | ​ | 2,802​ | ​
Total | ​ | ​ | 406,505​ | ​ | ​ | 873​ | ​ | ​ | 85,346​ | ​ | ​ | 620,584​ | ​ | ​ | 705,930​ | ​ | ​ | 29,283​ | ​ | ​ | 328,571​ | ​ | ​ | 357,854​ | ​

​
(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, 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 8,292 (2,848.8 of which represent Eni’s share).
Productive oil and gas wells at Dec. 31, 2019(a)

(units) | ​ | ​ | Oil Wells | ​ | ​ | Natural gas Wells | ​
​ | ​ | ​ | Gross | ​ | ​ | Net | ​ | ​ | Gross | ​ | ​ | Net | ​
Italy | ​ | ​ | ​ | ​ | 204.0 | ​ | ​ | ​ | ​ | ​ | 158.2 | ​ | ​ | ​ | ​ | ​ | 441.0 | ​ | ​ | ​ | ​ | ​ | 383.0 | ​ | ​
Rest of Europe | ​ | ​ | ​ | ​ | 657.0 | ​ | ​ | ​ | ​ | ​ | 106.2 | ​ | ​ | ​ | ​ | ​ | 207.0 | ​ | ​ | ​ | ​ | ​ | 67.0 | ​ | ​
North Africa | ​ | ​ | ​ | ​ | 589.0 | ​ | ​ | ​ | ​ | ​ | 245.7 | ​ | ​ | ​ | ​ | ​ | 125.0 | ​ | ​ | ​ | ​ | ​ | 67.5 | ​ | ​
Egypt | ​ | ​ | ​ | ​ | 1,196.0 | ​ | ​ | ​ | ​ | ​ | 513.2 | ​ | ​ | ​ | ​ | ​ | 141.0 | ​ | ​ | ​ | ​ | ​ | 43.6 | ​ | ​
Sub-Saharan Africa | ​ | ​ | ​ | ​ | 2,620.0 | ​ | ​ | ​ | ​ | ​ | 538.0 | ​ | ​ | ​ | ​ | ​ | 201.0 | ​ | ​ | ​ | ​ | ​ | 27.0 | ​ | ​
Kazakhstan | ​ | ​ | ​ | ​ | 204.0 | ​ | ​ | ​ | ​ | ​ | 55.8 | ​ | ​ | ​ | ​ | ​ | 1.0 | ​ | ​ | ​ | ​ | ​ | 0.3 | ​ | ​
Rest of Asia | ​ | ​ | ​ | ​ | 990.0 | ​ | ​ | ​ | ​ | ​ | 367.7 | ​ | ​ | ​ | ​ | ​ | 180.0 | ​ | ​ | ​ | ​ | ​ | 63.6 | ​ | ​
Americas | ​ | ​ | ​ | ​ | 250.0 | ​ | ​ | ​ | ​ | ​ | 128.4 | ​ | ​ | ​ | ​ | ​ | 284.0 | ​ | ​ | ​ | ​ | ​ | 81.6 | ​ | ​
Australia and Oceania | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2.0 | ​ | ​ | ​ | ​ | ​ | 2.0 | ​ | ​
Total including equity-accounted entities | ​ | ​ | ​ | ​ | 6,710.0 | ​ | ​ | ​ | ​ | ​ | 2,113.2 | ​ | ​ | ​ | ​ | ​ | 1,582.0 | ​ | ​ | ​ | ​ | ​ | 735.6 | ​ | ​

​
(a)
Multiple completion wells included above: 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’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 operates 31 onshore and 63 offshore productive concessions as well as 13 onshore and 9 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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Pending the administrative resolution, the current law provides for the prorogation of the concessions in accordance to the development plans agreed with the initial award.
Rest of Europe
Eni’s operations in the Rest of Europe are mainly conducted in the United Kingdom and in Norway, 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 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 2019, the Rest of Europe accounted for 9% of Eni’s total worldwide production of oil and natural gas.
United Kingdom. Development activities mainly concerned the drilling of four wells, which were already started up in 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 2019, North Africa accounted for 21% of Eni’s total worldwide production of oil and natural gas.
Algeria. In February 2019, Eni completed the acquisition of the 49% interest in the Sif Fatima II, Zemlet El Arbi and Ourhoud II concessions in the Berkine Nord area, following the agreements signed in 2018. The ongoing activities concerned: (i) the fast-track development activity of 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 started up with the drilling of 2 wells and the connection of 2 additional wells to the existing facilities, following the completion of the pipeline from BRN to the MLE treatment plant in Block 405b (Eni operator with a 75% interest); and (ii) exploration and delineation activities in the area. In particular, in 2019 exploration activity yielded positive results with an oil and gas discovery in the Ourhoud II concession.
Development activities in other blocks included: (i) production optimization in the operated Blocks 403a/d and ROM Nord (Eni’s interest 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 Block 208 (Eni’s interest 12.25%) with the drilling of production and water injection wells.
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Libya. Currently, Libya represents approximately 16% of the Group’s total production. Notwithstanding, the complexity of the geopolitical environment, in 2019 Eni’s activities in the Country
progressed smoothly and achieving the planned production mainly from Wafa production optimization activities and new compression, upgrading of treatment plants in the Mellitah area and Sabratha platform, and completion of Bahr Essalam phase 2. The worsening of the situation in Libya remains an area of issue. For further information on this matter, see “Item 3 – Risk factors – Political considerations”.
The rights of Eni to produce at its assets in Libya will expire in 2038 for Contract Area C, in 2041 for Contract Area E, in 2042 for Contract Area A and B as well as in 2043 for Contract Area D production.
Tunisia. Development activities concerned production optimization at the producing concessions to mitigate mature fields declines.
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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 were completed: (i) at the Nooros field with the installation of a new gas pipeline to the El Gamil treatment plant to production optimization and reserves’ recovery maximization; (ii) at the Baltim South West offshore project (Eni operator with a 50% interest) 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), including the production start-up achieved at the recent discoveries as well as water injection optimization to support reservoir pressure; and (ii) the operated Meleiha (Eni’s interest 76%), Meleiha Deep (Eni’s interest 100%) and Ras Qattara (Eni’s interest 75%) concessions in the Western Desert.
Exploration activities yielded positive results with: (i) a gas discovery in the El Qar’a exploration license (Eni’s interest 75%), located in the Nile Delta; (ii) the Sidri oil discovery in the Abu Rudeis development lease (Eni’s interest 100%), in the Gulf of Suez. Drilling activity has been completed and
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production wells connected to the existing facilities; (iii) the 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 2019, Sub-Saharan Africa accounted for 20% of Eni’s total worldwide production of oil and natural gas.
Angola. In 2019, Angola accounted for 7% of Eni’s total worldwide production of oil and natural gas.
In January 2020 Eni was awarded a 60% interest in the Block 28 as operator.
In November 2019 Eni and the Country’s Authority signed a Memorandum of Understanding which provides for the acquisition of the offshore Block 1/14 (Eni operator with a 35% interest) and the onshore Cabinda Center block (Eni’s interest 42.5%).
In 2019 Eni finalized an extension of exploitation rights until 2032 of Block 15 (Eni’s interest 20%), the number of the Development Areas has been reduced, joining some of them together.
Development activities concerned: (i) the completion of the planned activities at the Vandumbu field in the West Hub project in the operated Block 15/06 (Eni’s interest 36.84%); and (ii) production optimization at the Mpungi and Sangos fields in the Block 15/06 and in some fields in the Block 0 (Eni’s interest 9.8%).
Eni owns a 13.6% interest of Angola LNG, which runs the plant, located in Soyo, with a treatment capacity of approximately 350 BCF/y of feed gas and a liquefaction capacity of 5.2 mmtonnes/y of LNG. In 2019 production net to Eni averaged approximately 22 KBOE/d. In October 2019 Eni, as operator of a new joint venture (Eni interest 25.6%), signed a commercial agreement with the partners of the Angola LNG for the development of the gas fields to support the liquefaction plant. The first development project is expected to be sanctioned in 2020.
Exploration activities progressed at Block 15/06 during the year, 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 capacity of the two FPSO units installed in the area. In 2020 the production start-up of the Agogo discovery was achieved.
Mozambique. Eni has been present in Mozambique since 2006, following the award of the exploration license relating to gas-rich Area 4 Offshore of the Rovuma Block.
In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by Total. In 2012, Eni made another large gas discovery at the Coral prospect, which falls entirely in Area 4.
During the exploration period, which expired in 2015, six Discovery Areas (DA) were identified. Mozambique Decree Law 02/2014 provides that individual plans of development can be submitted in respect of each DA. Under the Area 4 EPCC (Exploration and Production Concession Contract), each Plan of Development once approved by the Government of Mozambique entitles the Concessionaires to develop and to produce in a term of 30 years, with an extension option pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law.
Following two separate transactions occurred respectively in 2013 and in 2017, Eni divested to CNPC and ExxonMobil indirect interests of 20% and 25% respectively in the discoveries of Area 4, by diluting its participating interest in Mozambique Rovuma Venture SpA, the operator of Area 4 which is a joint
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operation for IFRS accounting purposes, proportionally-consolidated in the Company Consolidated Financial Statements. Post transactions, Eni retains a 25% indirect interest in the Area 4 concession. The other concessionaires of Area 4 are the state-owned oil company ENH, Galp and Kogas, each with a 10% working interest.
Development activities continued at the Coral South project during 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 3.4 mmtonnes/y, fed by 6 subsea wells. Production start-up is expected in 2022. The LNG produced will be sold by the Area 4 Concessionaires to BP under a long-term contract for a period of twenty years, with an option for an additional ten-year term.
Pre-Development activities progressed at the Mamba Complex discoveries where Eni is expected to coordinate the upstream development and production phase and ExxonMobil the construction and operation phase of natural gas liquefaction facilities onshore. In 2019, the Mozambique authorities approved the unitization agreement between the Area 1 and Area 4.
In this context, the Area 4 Concessionaire progressed activities towards a final investment decision (FID) and towards finalization of the project financing for the Rovuma LNG project, which provides the construction of two onshore LNG trains with a capacity of approximately 7.6 mmtonnes/y 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 a 34% interest.
Nigeria. Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant has treatment capacity of approximately 1,236 BCF/y of feed gas and a production capacity of 22 mmtonnes/y of LNG. Natural gas supplies to the plant are currently provided under a gas supply agreements from the SPDC JV (Eni’s interest 5%), TEPNG JV and the NAOC JV (Eni’s interest 20%). In 2019, the Bonny liquefaction plant processed approximately 1,165 BCF. LNG production is sold under long-term contracts and exported mainly to Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG. In December 2019 the final investment decision was sanctioned for the construction of an additional treatment unit which will increase production capacity until 30 mmtonnes/y of LNG. Development activity is expected to be completed in 2024 with production start-up.
Development activities of the operated OMLs 60, 61, 62 and 63 blocks (Eni’s interest 20%) concerned: (i) the completion of planned activities and production start-up of the Obiafu 41 gas and condensates discovery; and (ii) increasing generation capacity of the combined cycle power plant at Okpai to achieve about 1 GW from the actual a 480 MW. Natural gas production of the area will support the plant capacity.
Other development activities concerned: (i) infilling program and production optimization in the OML 118 block (Eni’s interest 12.5%); (ii) the completion of drilling activities of two additional oil wells at the Abo field in the operated OML 125 block (Eni’s interest 100%). Peak production of 26 KBBL/d has been achieved during the year; (iii) the completion of the associated gas project in the OML 43 block (Eni’s interest 5%) and the SSAGS project in the OML 28 block (Eni’s interest 5%). Associated gas production will be sold in the domestic market; and (iv) the flaring down Assa North project (Eni’s interest 5%) has been sanctioned to support the domestic market.
The acquisition of the OPL 245 property made by Eni in 2011 is the subject of certain judicial proceedings describe in “Item 18 – consolidated financial statement – Note 27”.
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Kazakhstan
Eni’s operations in Kazakhstan mainly regarded the Kashagan and the Karachaganak fields. In 2019, Kazakhstan accounted for 8% of Eni’s total worldwide production of oil and natural gas.
Kashagan. Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000 over an area extending for 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources, which are expected to be developed in phases. The NCSPSA expires at the end of 2041.
In addition to Eni, the partners of the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest of 16.81%, CNPC with 8.33%, and Inpex with 7.56%.
In 2019, production at the Kashagan field averaged 53 KBBL/d of liquids and 54 mmCF/d of natural gas net to Eni. The treated gas is delivered to the national gas marketing and transportation company (KazTransGas), and the remaining volumes is utilized as fuel gas. The remaining untreated gas volumes (approximately 43%) is re-injected in the reservoir. The liquid production is stabilized at the Bolashak facilities and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline.
Current development plans envisage for increasing the production capacity up to 450 KBBL/d by upgrading the existing gas compression capacity, the conversion of production wells into injection wells, the debottlenecking and the revamping of existing facilities with the construction of a new onshore gas treatment plant. A final investment decision has yet to be made.
Management believes that significant capital expenditure will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and subsequently to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures.
As of December 31, 2019, Eni’s proved reserves booked for the Kashagan field amounted to 661 mmBOE, increased from 614 mmBOE in 2018.
As of December 31, 2019, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $10 billion (€8.9 billion at the EUR/USD exchange rate of December 31, 2019). This capitalized amount included: (i) $7.4 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.6 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years. Cost incurred in the 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 2019, production of the Karachaganak field averaged 46 KBBL/d of liquids and 186 mmCF/d of natural gas net to Eni. This field is producing liquids from the deeper layers of the reservoir. The gas is marketed (about 50%) at the Russian gas plant of Orenburg, the remaining volumes are utilized for re-injection in the higher layers of the reservoir and as fuel gas. Almost the entire liquid production is stabilized at the Karachaganak Processing Complex (KPC) and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline.
Within the gas treatment expansion projects of the Karachaganak field, activities concerned: (i) the 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 facility.
As of December 31, 2019, Eni’s proved reserves booked for the Karachaganak field amounted to 448 mmBOE, slightly decreased from 452 mmBOE in 2018.
As of December 31, 2019, the aggregate costs incurred by Eni for the Karachaganak project capitalized in the financial statements amounted to $4.1 billion (€3.7 billion at the EUR/USD exchange rate of December 31, 2019). Cost incurred in the 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 2019, Eni’s operations in the Rest of Asia accounted for approximately 9% of its total worldwide production of oil and natural gas.
Iraq. Development activities concerned the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field, to achieve a production plateau of 700 KBBL/d. This phase also contemplates utilization of the associated gas for power generation. The production capacity and relevant facilities to treat the targeted production plateau have been already installed; the field reserves will be progressively put into production by drilling additional productive wells over the next few years.
Indonesia. Activities are concentrated in the offshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 13 blocks.
In 2019, Eni divested to Neptune a 20% interest in the East Sepinggan block, offshore East Kalimantan, which includes the Merakes field and the East Merakes discovery. Eni will retain a 65% interest and the operatorship.
In 2019 Eni was awarded the West Ganal exploration block (Eni operator with a 40% interest) located in the deep water Kutei Basin, effective since January 1, 2020.
Development activities concerned the offshore Merakes gas project in the operated East Sepinggan block.
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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 of two exploration wells and one appraisal well in the Block 2; (ii) three onshore exploration
concessions in the 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.
Development activities concerned: (i) the Dalma Gas Development project in the Gasha concession (Eni’s interest 25%). The final investment decision was sanctioned. Start-up is expected in 2022; and (ii) the Nasr Full Field Development project in the Umm Shaif/Nasr concession (Eni’s interest 10%). The program was completed and production ramp-up achieved in the year.
Americas
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 approximately 6% of its total worldwide production of oil and natural gas.
Ecuador. In 2019, Eni divested its activities in 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 65%).
United States. Eni holds interests in 41 exploration and production blocks in the Gulf of Mexico, of which 18 are operated by Eni. Eni also holds interests and operates 151 blocks in Alaska with 100% working interest.
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 2% of Eni’s total production. Eni’s production comes from the Perla gas field (Eni’s interest 50%), in the Gulf of Venezuela, the Corocoro field (Eni’s interest 26%), in the Gulf de Paria, and the Junín 5 oil field (Eni’s interest 40%), located in the Orinoco Oil Belt. Production activities have been negatively affected by the ongoing distressed financial and political situation of the Country. For further information on this matter, see “Item 3 – Risk factors – Political considerations”.
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Capital expenditures
See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”
Disclosure pursuant to Section 13(r) of the Exchange Act
The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate.
In 2017, Eni fully recovered the overdue trade receivable owed by Iranian state- owned companies relating to the cost recovery of past projects due to enactment of the agreements signed in 2016. There were no more outstanding receivables towards Iran’s national oil companies as of December 31, 2019. In 2019, Eni made payments in the region of  $0.04 million to the Iranian Social Security Organization in connection to health and social security insurance for which Eni retains at December 31, 2019 a residual payable amounting to approximately $5 million, which will be settled upon de-registration of our 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 2019, Eni’s worldwide sales of natural gas amounted to 73.07 BCM. Sales in Italy amounted to 37.85 BCM, while sales in European markets were 27.07 BCM that included 4.37 BCM of gas sold to certain importers to Italy.
The business results of operations in 2019 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations.”
Supply of natural gas
In 2019, Eni’s total supply of natural gas was 70.65 BCM, down by 3.50 BCM, or 4.7% from 2018. Gas volumes supplied outside Italy (65.21 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 92% of total supplies, down by 3.61 BCM, or 5.2% compared to the previous year, due to lower volumes purchased in Algeria (down by 5.36 BCM), in Russia (down 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 United States (up by 1.20 BCM). Supplies in Italy (5.44 BCM) increased by 2.1% from 2018.
In 2019, main gas volumes from equity production derived from: (i) Italian gas fields (3.4 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.3 bcm); (iii) Libyan fields (1.8 bcm); (iv) Indonesia (0.8 bcm) and (v) the United States (0.2 bcm). Supplied gas volumes from equity production were approximately 8.5 bcm representing 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 | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (BCM)​ | ​
Italy | ​ | ​ | ​ | ​ | 5.44 | ​ | ​ | ​ | ​ | ​ | 5.33 | ​ | ​ | ​ | ​ | ​ | 5.05 | ​ | ​
Outside Italy | ​ | ​ | ​ | ​ | 65.21 | ​ | ​ | ​ | ​ | ​ | 68.82 | ​ | ​ | ​ | ​ | ​ | 73.23 | ​ | ​
Russia | ​ | ​ | ​ | ​ | 24.71 | ​ | ​ | ​ | ​ | ​ | 26.24 | ​ | ​ | ​ | ​ | ​ | 28.09 | ​ | ​
Algeria (including LNG) | ​ | ​ | ​ | ​ | 6.66 | ​ | ​ | ​ | ​ | ​ | 12.02 | ​ | ​ | ​ | ​ | ​ | 13.18 | ​ | ​
Libya | ​ | ​ | ​ | ​ | 5.86 | ​ | ​ | ​ | ​ | ​ | 4.55 | ​ | ​ | ​ | ​ | ​ | 4.76 | ​ | ​
the Netherlands | ​ | ​ | ​ | ​ | 4.12 | ​ | ​ | ​ | ​ | ​ | 3.95 | ​ | ​ | ​ | ​ | ​ | 5.20 | ​ | ​
Norway | ​ | ​ | ​ | ​ | 6.43 | ​ | ​ | ​ | ​ | ​ | 6.75 | ​ | ​ | ​ | ​ | ​ | 7.48 | ​ | ​
the United Kingdom | ​ | ​ | ​ | ​ | 1.75 | ​ | ​ | ​ | ​ | ​ | 2.21 | ​ | ​ | ​ | ​ | ​ | 2.36 | ​ | ​
Indonesia (LNG) | ​ | ​ | ​ | ​ | 1.58 | ​ | ​ | ​ | ​ | ​ | 3.06 | ​ | ​ | ​ | ​ | ​ | 0.74 | ​ | ​
Qatar (LNG) | ​ | ​ | ​ | ​ | 2.79 | ​ | ​ | ​ | ​ | ​ | 2.56 | ​ | ​ | ​ | ​ | ​ | 2.36 | ​ | ​
Other supplies of natural gas | ​ | ​ | ​ | ​ | 7.91 | ​ | ​ | ​ | ​ | ​ | 5.52 | ​ | ​ | ​ | ​ | ​ | 6.75 | ​ | ​
Other supplies of LNG | ​ | ​ | ​ | ​ | 3.40 | ​ | ​ | ​ | ​ | ​ | 1.96 | ​ | ​ | ​ | ​ | ​ | 2.31 | ​ | ​
Total supplies of subsidiaries | ​ | ​ | ​ | ​ | 70.65 | ​ | ​ | ​ | ​ | ​ | 74.15 | ​ | ​ | ​ | ​ | ​ | 78.28 | ​ | ​
Withdrawals from (input to) storage | ​ | ​ | ​ | ​ | 0.08 | ​ | ​ | ​ | ​ | ​ | 0.08 | ​ | ​ | ​ | ​ | ​ | 0.31 | ​ | ​
Network losses, measurement differences and other changes | ​ | ​ | ​ | ​ | (0.22) | ​ | ​ | ​ | ​ | ​ | (0.18) | ​ | ​ | ​ | ​ | ​ | (0.45) | ​ | ​
Volumes available for sale of Eni’s subsidiaries | ​ | ​ | ​ | ​ | 70.51 | ​ | ​ | ​ | ​ | ​ | 74.05 | ​ | ​ | ​ | ​ | ​ | 78.14 | ​ | ​
Volumes available for sale of Eni’s affiliates | ​ | ​ | ​ | ​ | 2.56 | ​ | ​ | ​ | ​ | ​ | 2.66 | ​ | ​ | ​ | ​ | ​ | 2.69 | ​ | ​
Total volumes available for sale | ​ | ​ | ​ | ​ | 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 2019, natural gas sales amounted to 73.07 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities), representing a decrease of 3.64 BCM, or 4.7% from the previous year. Sales in Italy (37.85 BCM) decreased by 3% from 2018. Lower sales to wholesalers, spot market and residential segment were partly offset by higher sales to thermoelectrical and industrial segments. Sales in the European markets amounted to 22.70 BCM, a decrease of 12.7% or 3.30 BCM from 2018.
Sales to long-term buyers were 4.37 BCM; up by 27.8% compared to the previous year thanks to the higher availability of Libyan output.
Sales in the Extra European markets (8.15 BCM) decreased by 0.11 BCM or 1.3% due to lower LNG sales in the Far East markets, partly offset by higher volumes sold in the 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​ | ​ | ​ | 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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The LNG business
Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from, Qatar, Nigeria, Indonesia and Oman. In the plan period, Eni intends to develop its LNG business leveraging on the integration with the E&P segment and the valorization of the equity gas. Final markets of that gas include Europe, China, Pakistan and Japan. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities.

​ | ​ | ​ | ​ | ​
LNG sales​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (BCM)​ | ​
Europe | ​ | ​ | ​ | ​ | 5.5 | ​ | ​ | ​ | ​ | ​ | 4.7 | ​ | ​ | ​ | ​ | ​ | 5.2 | ​ | ​
Extra European markets | ​ | ​ | ​ | ​ | 4.6 | ​ | ​ | ​ | ​ | ​ | 5.6 | ​ | ​ | ​ | ​ | ​ | 3.1 | ​ | ​
​ | ​ | ​ | ​ | ​ | 10.1 | ​ | ​ | ​ | ​ | ​ | 10.3 | ​ | ​ | ​ | ​ | ​ | 8.3 | ​ | ​

Electricity sales and power generation
Electricity sales
As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, on the Italian Stock Exchange for electricity and at industrial sites. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value chain leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and small and middle business located in urban area, the Company has developed a commercial offer that provides the combined supply of gas and power to the retail market in Italy and in France.
In 2019, power sales (39.49 TWh) were directed to the free market (72%), the Italian Power Exchange (18%), industrial sites (9%) and others (1%). Compared to 2018, electricity sales in the free market were up by 2.40 TWh or by 9.3%, due to higher volumes sold to wholesalers, middle market and retail segments, partially offset by lower volumes sold to the large customers.

​ | ​ | ​ | ​ | ​
Power availability​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (TWh)​ | ​
Power generation sold | ​ | ​ | ​ | ​ | 21.66 | ​ | ​ | ​ | ​ | ​ | 21.62 | ​ | ​ | ​ | ​ | ​ | 22.42 | ​ | ​
Trading of electricity(a) | ​ | ​ | ​ | ​ | 17.83 | ​ | ​ | ​ | ​ | ​ | 15.45 | ​ | ​ | ​ | ​ | ​ | 12.91 | ​ | ​
​ | ​ | ​ | ​ | ​ | 39.49 | ​ | ​ | ​ | ​ | ​ | 37.07 | ​ | ​ | ​ | ​ | ​ | 35.33 | ​ | ​
Power sales by market | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Free market(a) | ​ | ​ | ​ | ​ | 28.31 | ​ | ​ | ​ | ​ | ​ | 25.91 | ​ | ​ | ​ | ​ | ​ | 26.53 | ​ | ​
Italian Exchange for electricity | ​ | ​ | ​ | ​ | 7.27 | ​ | ​ | ​ | ​ | ​ | 7.17 | ​ | ​ | ​ | ​ | ​ | 5.21 | ​ | ​
Industrial plants | ​ | ​ | ​ | ​ | 3.38 | ​ | ​ | ​ | ​ | ​ | 3.49 | ​ | ​ | ​ | ​ | ​ | 3.01 | ​ | ​
Other(a) | ​ | ​ | ​ | ​ | 0.53 | ​ | ​ | ​ | ​ | ​ | 0.50 | ​ | ​ | ​ | ​ | ​ | 0.58 | ​ | ​
​ | ​ | ​ | ​ | ​ | 39.49 | ​ | ​ | ​ | ​ | ​ | 37.07 | ​ | ​ | ​ | ​ | ​ | 35.33 | ​ | ​

​
(a)
Include positive and negative imbalances (differences between power introduced in the grid and the one planned).
​
Power generation
Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. In 2019, power generation was 21.66 TWh, substantially in line with 2018. As of December 31, 2019, installed operational capacity was 4.7 GW, unchanged compared to December 31, 2018.
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Electricity trading (17.83 TWh) reported an increase of 15.4% thanks to the optimization of inflows and outflows of power.

Site | ​ | ​ | Total installed capacity in 2019 (GW) | ​ | ​ | Technology | ​ | ​ | Fuel | ​
Brindisi | ​ | ​ | ​ | ​ | 1.3 | ​ | ​ | ​ | CCGT​ | ​ | ​ | gas​ | ​
Ferrera Erbognone | ​ | ​ | ​ | ​ | 1.0 | ​ | ​ | ​ | CCGT​ | ​ | ​ | gas/syngas​ | ​
Mantova | ​ | ​ | ​ | ​ | 0.9 | ​ | ​ | ​ | CCGT​ | ​ | ​ | gas​ | ​
Ravenna | ​ | ​ | ​ | ​ | 1.0 | ​ | ​ | ​ | CCGT​ | ​ | ​ | gas​ | ​
Ferrara(a) | ​ | ​ | ​ | ​ | 0.4 | ​ | ​ | ​ | CCGT​ | ​ | ​ | gas​ | ​
Bolgiano | ​ | ​ | ​ | ​ | 0.1 | ​ | ​ | ​ | Power station​ | ​ | ​ | gas​ | ​
​ | ​ | ​ | ​ | ​ | 4.7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

​
(a)
Eni’s share of capacity.
​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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 (Algeria, Libya and the North Sea) . Eni has contracted the transport capacity under ship-or-pay contracts, which are similar to take-or-pay contracts.
Eni also retains ownership interests in certain pipeline companies, which run and operate the facility by selling transportation capacity under long-term ship-or-pay contracts to both shareholders and third party shippers. The main assets of Eni’s transport activities are provided in the table below.
International Transport infrastructure Route

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

International transport activities
The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometers long with a transport capacity of 34.3 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.
The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometers long with a transport capacity of 33.5 BCM/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.
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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-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 to produce a large slate of fuels and other refined products and in the marketing of fuels primarily in Italy and in selected European markets. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company operations are fully integrated through refining, supply, logistics and marketing in order to maximize cost efficiencies and operational effectiveness.
The Company also engages in the production of bio-fuels at the Venice and Gela refineries, where certain renewable feedstock are processed (palm oil).
The business results depend heavily on trends in refining margins, i.e. the spread between the cost of the oil feedstock and the price of the refined products obtained from the crude processing.
In 2019 refining margins in the Mediterranean area increased by approximately 16% y-o-y to 4.3 $/BBL driven by the higher relative prices of products compared to the 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 short-to-medium term due to continuing competition. In the medium-term, spreads between products and crude may find a support as a consequence of the IMO 2020 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 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 2019 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations”.
Supply
In 2019, a total of 23.43 mmtonnes of crude were purchased (compared with 22.62 mmtonnes in 2018), of which 4.24 mmtonnes by equity crude oil. The breakdown by geographic area was the following: approximately 24% of purchased crude came from the Middle East, 23% from Russia, 17% from Central Asia, 13% from Italy, 13% from North Africa, 2% from West Africa, 2% from North Sea and 6% from other areas.
Refining
In 2019, Eni refinery capacity (balanced with conversion capacity) was approximately 36.6 mmtonnes (equal to 732 KBBL/d), with a conversion index of 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
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to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 KBBL/d), with a 55% conversion index. In 2019, Eni’s refineries throughputs in Italy and outside Italy were 22.74 mmtonnes. The refinery utilization rate, ratio between throughputs and refinery capacity, is 88%.
Refining system in 2019

​ | ​ | ​ | Ownership (%) | ​ | ​ | Balanced refining capacity (Eni’s share) (KBBL/d) | ​ | ​ | Utilization rate (Eni’s share)(1) (%) | ​ | ​ | Conversion index(2) (%) | ​
Wholly-owned refineries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 89 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​
Italy | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sannazzaro | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 200 | ​ | ​ | ​ | ​ | ​ | 85 | ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​
Taranto | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 104 | ​ | ​ | ​ | ​ | ​ | 89 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​
Livorno | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 84 | ​ | ​ | ​ | ​ | ​ | 98 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​
Partially owned refineries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 344 | ​ | ​ | ​ | ​ | ​ | 84 | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​
Italy | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Milazzo | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 94 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​
Germany | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Vohburg/Neustadt (Bayernoil) | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 41 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​ | ​ | ​ | ​ | 36 | ​ | ​
Schwedt | ​ | ​ | ​ | ​ | 8.33 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 87 | ​ | ​ | ​ | ​ | ​ | 42 | ​ | ​
UAE | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
ADNOC Refining | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 184 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​
Total | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 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).
​
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 74%. Located in the Po Valley, in the center of the Northern Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.
The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 56%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni 61%) through a pipeline. The main 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 de-aromatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and de-waxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.
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The Milazzo refinery (Eni 50%) has a balanced capacity of 200 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main 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.
In the UAE, Eni and ADNOC signed a Share Purchase Agreement to enable Eni to acquire from ADNOC a 20% equity interest in ADNOC Refining. ADNOC Refining operates two refineries in Ruwais (Ruwais East and Ruwais West) and another in Abu Dhabi (Abu Dhabi Refinery), with a total refining capacity of 922 KBBL/d.
Biorefineries

​ | ​ | ​ | Ownership share (%) | ​ | ​ | Capacity (2019)(a) (ktonnes/y) | ​ | ​ | Capacity (at regime) (ktonnes/y) | ​ | ​ | Throughput (2019) (ktonnes/y) | ​
Wholly-owned | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Venezia | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 360 | ​ | ​ | ​ | ​ | ​ | 560 | ​ | ​ | ​ | ​ | ​ | 217 | ​ | ​
Gela | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 300 | ​ | ​ | ​ | ​ | ​ | 750 | ​ | ​ | ​ | ​ | ​ | 94 | ​ | ​
Total biorefineries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 660 | ​ | ​ | ​ | ​ | ​ | 1,310 | ​ | ​ | ​ | ​ | ​ | 311 | ​ | ​

​
(a)
Includes the pro-rata of installed capacity of Gela’s biorefinery (720,000 tonnes/y) started in August 2019.
​
Biorefining
Eni fully owns two biorefineries in Italy, specifically in Venice and Gela.
The Venice biorefinery started production in June 2014, replacing the old oil-based refinery that was shut down. The refinery, with a production capacity of 360 ktonnes/y, leverages on the EcofiningTM proprietary technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At 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 CO2 emissions.
The Gela refinery is located in the Southern coast of Sicily. The refinery was shut-down in March 2014 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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The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.

​ | ​ | ​ | ​ | ​
Availability of refined products​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (mmtonnes)​ | ​
ITALY | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Refinery throughputs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At wholly-owned refineries | ​ | ​ | ​ | ​ | 17.26 | ​ | ​ | ​ | ​ | ​ | 16.78 | ​ | ​ | ​ | ​ | ​ | 16.03 | ​ | ​
Less input on account of third parties | ​ | ​ | ​ | ​ | (1.25) | ​ | ​ | ​ | ​ | ​ | (1.03) | ​ | ​ | ​ | ​ | ​ | (0.34) | ​ | ​
At affiliated refineries | ​ | ​ | ​ | ​ | 4.69 | ​ | ​ | ​ | ​ | ​ | 4.93 | ​ | ​ | ​ | ​ | ​ | 5.46 | ​ | ​
Refinery throughputs on own account | ​ | ​ | ​ | ​ | 20.70 | ​ | ​ | ​ | ​ | ​ | 20.68 | ​ | ​ | ​ | ​ | ​ | 21.15 | ​ | ​
Consumption and losses | ​ | ​ | ​ | ​ | (1.38) | ​ | ​ | ​ | ​ | ​ | (1.38) | ​ | ​ | ​ | ​ | ​ | (1.36) | ​ | ​
Products available for sale | ​ | ​ | ​ | ​ | 19.32 | ​ | ​ | ​ | ​ | ​ | 19.30 | ​ | ​ | ​ | ​ | ​ | 19.79 | ​ | ​
Purchases of refined products and change in inventories | ​ | ​ | ​ | ​ | 7.27 | ​ | ​ | ​ | ​ | ​ | 7.50 | ​ | ​ | ​ | ​ | ​ | 6.74 | ​ | ​
Products transferred to operations outside Italy | ​ | ​ | ​ | ​ | (0.68) | ​ | ​ | ​ | ​ | ​ | (0.54) | ​ | ​ | ​ | ​ | ​ | (0.46) | ​ | ​
Consumption for power generation | ​ | ​ | ​ | ​ | (0.35) | ​ | ​ | ​ | ​ | ​ | (0.35) | ​ | ​ | ​ | ​ | ​ | (0.34) | ​ | ​
Sales of products | ​ | ​ | ​ | ​ | 25.56 | ​ | ​ | ​ | ​ | ​ | 25.91 | ​ | ​ | ​ | ​ | ​ | 25.73 | ​ | ​
Biorefinery throughputs | ​ | ​ | ​ | ​ | 0.31 | ​ | ​ | ​ | ​ | ​ | 0.25 | ​ | ​ | ​ | ​ | ​ | 0.24 | ​ | ​
OUTSIDE ITALY | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Refinery throughputs on own account | ​ | ​ | ​ | ​ | 2.04 | ​ | ​ | ​ | ​ | ​ | 2.55 | ​ | ​ | ​ | ​ | ​ | 2.87 | ​ | ​
Consumption and losses | ​ | ​ | ​ | ​ | (0.18) | ​ | ​ | ​ | ​ | ​ | (0.20) | ​ | ​ | ​ | ​ | ​ | (0.22) | ​ | ​
Products available for sale | ​ | ​ | ​ | ​ | 1.86 | ​ | ​ | ​ | ​ | ​ | 2.35 | ​ | ​ | ​ | ​ | ​ | 2.65 | ​ | ​
Purchases of finished products and change in inventories | ​ | ​ | ​ | ​ | 4.17 | ​ | ​ | ​ | ​ | ​ | 4.12 | ​ | ​ | ​ | ​ | ​ | 4.36 | ​ | ​
Products transferred from Italian operations | ​ | ​ | ​ | ​ | 0.68 | ​ | ​ | ​ | ​ | ​ | 0.54 | ​ | ​ | ​ | ​ | ​ | 0.46 | ​ | ​
Sales of products | ​ | ​ | ​ | ​ | 6.71 | ​ | ​ | ​ | ​ | ​ | 7.01 | ​ | ​ | ​ | ​ | ​ | 7.47 | ​ | ​
Refinery throughputs on own account | ​ | ​ | ​ | ​ | 22.74 | ​ | ​ | ​ | ​ | ​ | 23.23 | ​ | ​ | ​ | ​ | ​ | 24.02 | ​ | ​
of which: refinery throughputs of equity crude on own account | ​ | ​ | ​ | ​ | 4.24 | ​ | ​ | ​ | ​ | ​ | 4.14 | ​ | ​ | ​ | ​ | ​ | 3.51 | ​ | ​
Total sales of refined products | ​ | ​ | ​ | ​ | 32.27 | ​ | ​ | ​ | ​ | ​ | 32.92 | ​ | ​ | ​ | ​ | ​ | 33.20 | ​ | ​
Crude oil sales | ​ | ​ | ​ | ​ | 0.44 | ​ | ​ | ​ | ​ | ​ | 0.28 | ​ | ​ | ​ | ​ | ​ | 0.86 | ​ | ​
TOTAL SALES | ​ | ​ | ​ | ​ | 32.71 | ​ | ​ | ​ | ​ | ​ | 33.20 | ​ | ​ | ​ | ​ | ​ | 34.06 | ​ | ​

In 2019, Eni’s refining throughputs on own account in Europe were 22.74 mmtonnes, slightly decreased by 2.1% from 2018, due to: the lower throughputs at the Bayernoil refinery, as a result of the 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 Milazzo refinery, as well as 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 refineries affected by higher maintenance standstills, logistic issues due to adverse climatic events and the upset at the Milazzo refinery, as well as the lower throughputs at the Livorno refinery to counteract the scenario, were offset by higher volumes processed at the Taranto refinery leveraging on fewer shutdowns.
Outside Italy, Eni’s refining throughputs on own account were 2.04 mmtonnes, down by approximately 510 ktonnes or 20% due to the above mentioned downtime of the Bayernoil refinery. Total throughputs in wholly-owned refineries were 17.26 mmtonnes, up by 0.48 mmtonnes or 2.9% compared with 2018.
The refinery utilization rate, ratio between throughputs and refinery capacity, is 88%.
Approximately 18.9% of processed crude was supplied by Eni’s Exploration & Production segment, increasing by 18.3% from 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.
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Oil and refined products are transported: (i) by sea through spot and long-term contracts of tanker ships; and (ii) inland through a proprietary pipeline and depots network directly operated.
In particular, Eni owns and operates an integrated infrastructure consisting of 16 directly managed depots and a network of oil and refined products pipelines extending approximately 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 trucks, selected as market leaders.
Marketing
Eni markets a wide range of refined petroleum products, primarily in Italy, through a widespread operated network of service stations, franchises and other distribution systems.
The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.

​ | ​ | ​ | ​ | ​
Oil products sales in Italy and outside Italy | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (mmtonnes)​ | ​
Italy | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Retail | ​ | ​ | ​ | ​ | 5.81 | ​ | ​ | ​ | ​ | ​ | 5.91 | ​ | ​ | ​ | ​ | ​ | 6.01 | ​ | ​
Wholesale | ​ | ​ | ​ | ​ | 7.68 | ​ | ​ | ​ | ​ | ​ | 7.54 | ​ | ​ | ​ | ​ | ​ | 7.64 | ​ | ​
​ | ​ | ​ | ​ | ​ | 13.49 | ​ | ​ | ​ | ​ | ​ | 13.45 | ​ | ​ | ​ | ​ | ​ | 13.65 | ​ | ​
Petrochemicals | ​ | ​ | ​ | ​ | 0.83 | ​ | ​ | ​ | ​ | ​ | 0.96 | ​ | ​ | ​ | ​ | ​ | 0.86 | ​ | ​
Other sales | ​ | ​ | ​ | ​ | 11.24 | ​ | ​ | ​ | ​ | ​ | 11.5 | ​ | ​ | ​ | ​ | ​ | 11.22 | ​ | ​
Total | ​ | ​ | ​ | ​ | 25.56 | ​ | ​ | ​ | ​ | ​ | 25.91 | ​ | ​ | ​ | ​ | ​ | 25.73 | ​ | ​
Outside Italy | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Retail | ​ | ​ | ​ | ​ | 2.44 | ​ | ​ | ​ | ​ | ​ | 2.48 | ​ | ​ | ​ | ​ | ​ | 2.53 | ​ | ​
Wholesale | ​ | ​ | ​ | ​ | 3.11 | ​ | ​ | ​ | ​ | ​ | 3.29 | ​ | ​ | ​ | ​ | ​ | 3.48 | ​ | ​
​ | ​ | ​ | ​ | ​ | 5.55 | ​ | ​ | ​ | ​ | ​ | 5.77 | ​ | ​ | ​ | ​ | ​ | 6.01 | ​ | ​
Other sales | ​ | ​ | ​ | ​ | 1.16 | ​ | ​ | ​ | ​ | ​ | 1.24 | ​ | ​ | ​ | ​ | ​ | 1.46 | ​ | ​
Total | ​ | ​ | ​ | ​ | 6.71 | ​ | ​ | ​ | ​ | ​ | 7.01 | ​ | ​ | ​ | ​ | ​ | 7.47 | ​ | ​
TOTAL SALES | ​ | ​ | ​ | ​ | 32.27 | ​ | ​ | ​ | ​ | ​ | 32.92 | ​ | ​ | ​ | ​ | ​ | 33.20 | ​ | ​

In 2019, retail sales of refined products (32.27 mmtonnes) were down by 0.65 mmtonnes or by 2% from 2018, mainly due to the decrease of sales to oil companies and petrochemical industry in Italy and lower volumes marketed in the wholesalers segment in the rest of Europe.
Retail sales in Italy
In 2019, 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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At December 31, 2019, Eni’s retail network in the Rest of Europe consisted of 1,227 units, increasing by 2 units from December 31, 2018, mainly in Germany. Average throughput (2,356 kliters) decreased by 35 kliters compared to 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 are supported by a widespread commercial and logistical organization presence throughout Italy and is articulated in local marketing offices and a network of agents and concessionaires.
In 2019, sales volumes on wholesale markets in Italy (7.68 mmtonnes) increased by 1.9% from 2018, mainly due to higher volumes marketed of gasoil, bitumen and gasoline offset by lower sales of jet fuel and bunkers.
Wholesale sales in the Rest of Europe were 2.63 mmtonnes, down by 6.7% from 2018 due to lower sold volumes in Germany due to the unavailability of the Bayernoil refinery and France, partly offset by higher volumes in Switzerland, Spain and Austria.
Supplies of feedstock to the petrochemical industry (0.83 mmtonnes) decreased by 13.5%. Other sales in Italy and outside Italy (12.40 mmtonnes) decreased by 0.34 mmtonnes or down by 2.7%, mainly due to lower volumes sold to other oil companies.
LPG
The marketing of LPG in Italy is supported by the refining production and a logistic network made up of four 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 2019, Eni share of LPG market in Italy was 16.95%.
Outside Italy, the main market of Eni is Ecuador, with a market share of 37.3%.
Lubricants
Eni operates five (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, Africa and in the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of the art know how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, grease, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases, manufactured at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero.
In 2019, Eni’s share of lubricants market in Italy was 19.85%, in Europe 3% and on a worldwide base 1%. Eni operates in more than 80 countries by subsidiaries, licensees and distributors.
Oxygenates
Eni’s, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 0.9 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 70% of oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 30% 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 hubs are located in Italy and Western Europe.
The business results of operations in 2019 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations”.
In 2019 sales of chemical products amounted to 4,285 ktonnes, decreased from 2018 (down by 653 ktonnes, or 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 lower production of intermediates business (down by 18.4%), in particular aromatics and olefins; the polymers production of 2,250 ktonnes decreased by 4.4% with elastomers, polyethylene and styrenics down by 7.0%, 3.9% and 3.8%, respectively.
The main decreases in production were registered at the Priolo site (down by 23.3%), due to the event occurred at the beginning of 2019 with the ramp-up finalized between April and July, at the Porto Marghera (down by 21.9%) and Dunkerque (down by 17.1%) sites due to unplanned shutdowns.
Plants nominal capacity is in line with the 2018. The average plant utilization rate, calculated on nominal capacity was 66.8%, decreasing from 2018 (76.2%) following the aforementioned shutdowns.
The table below sets forth Eni’s main chemical products availability for the periods indicated.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (ktonnes) | ​
Intermediates | ​ | ​ | ​ | ​ | 5,818 | ​ | ​ | ​ | ​ | ​ | 7,130 | ​ | ​ | ​ | ​ | ​ | 6,595 | ​ | ​
Polymers | ​ | ​ | ​ | ​ | 2,250 | ​ | ​ | ​ | ​ | ​ | 2,353 | ​ | ​ | ​ | ​ | ​ | 2,360 | ​ | ​
Total production | ​ | ​ | ​ | ​ | 8,068 | ​ | ​ | ​ | ​ | ​ | 9,483 | ​ | ​ | ​ | ​ | ​ | 8,955 | ​ | ​
Consumption and losses | ​ | ​ | ​ | ​ | (4,307) | ​ | ​ | ​ | ​ | ​ | (5,085) | ​ | ​ | ​ | ​ | ​ | (4,566) | ​ | ​
Purchases and change in inventories | ​ | ​ | ​ | ​ | 524 | ​ | ​ | ​ | ​ | ​ | 540 | ​ | ​ | ​ | ​ | ​ | 257 | ​ | ​
​ | ​ | ​ | ​ | ​ | 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, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million) | ​
Intermediates | ​ | ​ | ​ | ​ | 1,791 | ​ | ​ | ​ | ​ | ​ | 2,401 | ​ | ​ | ​ | ​ | ​ | 1,988 | ​ | ​
Polymers | ​ | ​ | ​ | ​ | 2,201 | ​ | ​ | ​ | ​ | ​ | 2,589 | ​ | ​ | ​ | ​ | ​ | 2,730 | ​ | ​
Other revenues | ​ | ​ | ​ | ​ | 131 | ​ | ​ | ​ | ​ | ​ | 133 | ​ | ​ | ​ | ​ | ​ | 133 | ​ | ​
Total revenues | ​ | ​ | ​ | ​ | 4,123 | ​ | ​ | ​ | ​ | ​ | 5,123 | ​ | ​ | ​ | ​ | ​ | 4,851 | ​ | ​

Intermediates
Intermediates revenues (€1,791 million) decreased by €610 million from 2018 (down by 25.4%) reflecting both the lower commodity prices scenario influencing average intermediates prices of main products and the lower product availability due to plant standstills. Sales decreased by 18.4%, in particular for ethylene business (down by 38.0%), olefins (down by 21.9%) and derivatives (down by 13.4%) following the lower product availability.
Average prices decreased by 9.9%, in particular olefins (down by 10.2%), aromatics (down by 5.4%) and derivatives (down by 10.6%).
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Intermediates production (5,818 ktonnes) registered a decrease of 18.4% from 2018. Decreases were registered in aromatics (down by 19.6%), olefins (down by 18.9%) and derivatives (down by 11.3%).
Polymers
Polymers revenues (€2,201 million) decreased by € 388 million or 15.0% from 2018 due to lower volumes sold (down by 4.6%), as well as the decrease of the average prices (down by 10.8%).
The styrenics business registered the decrease of volumes sold (down by 4.3%) for lower product availability; decrease of sale prices (down by 14.7%).
Polyethylene volumes decreased (down by 5.0%) due to oversupply and mounting competitive pressure from cheaper products streams from the Middle-East and the USA; decreasing of average prices (down by 7.7%).
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 elastomers (down by 7.0%), polyethylene (down by 3.9%) and styrenics (down by 3.8%).
Capital expenditures
See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”.
Corporate and Other activities
These activities include the following businesses:
•
the “Other activities” segment comprises results of operations of Eni’s subsidiary Eni Rewind (former Syndial SpA) which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years, as well as Eni New Energy SpA which engages in developing the business of renewable energy; 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 comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residential space heating. In colder years, which are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa.
Research and development
Eni’s commitment and investment in Research and Development are divided into the following technology platforms, which reflect the strategic drivers of development of R&D projects:
-
Operational Excellence: reduction of costs and times of operations, developing key technologies for access and development of assets, ensuring the highest level of sustainability, safety and minimum environmental impact;
​
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Carbon Neutrality: reduce, capture, transform or store CO2, develop products with “energy saving” characteristics, promote natural gas as an energy source in 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 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.
Research and Development becomes, therefore, the lever to create value, with the aim of minimizing the time to market that from research leads to the development of technologies and their implementation on an industrial scale.
In 2019, Eni filed 34 patent applications (43 in 2018).
In 2019, Eni’s overall expenditure in R&D amounted to €194 million which were almost entirely expensed as incurred (€197 million in 2018 and €185 million in 2017).
Exploration & Production
Proprietary software for seismic signal processing, petroleum system modeling and flow assurance that confirms and strengthens Eni’s position at the top of the industry, both in terms of operating results and with significant savings on the cost of licenses and code maintenance.
Drilling automation. Two new tools addressing lost/non productive time and based on big data technology were developed since 2017 to support operations. The first tool is e.NPT (Eni Non Productive Time) which analyzes and integrates multiple data sources in real time in order to predict sticking events. The second tool is a new solution enabling a near real time performance analysis to identify Invisible Lost Times.
Drilling Safety Technologies: to reduce by a further order of magnitude the risk of blowout occurrence compared to the OGP reference. To achieve this goal, new technologies able to improve well integrity both during drilling and well productive life are being developed.
Eni Subsea Hub Technology Solutions: to develop, together with industry partners, technologies to significantly reduce subsea development CAPEX and OPEX by using full subsea architectures, very long step-outs and life-of-field robotics. The program starts from lessons learned from Eni’s most recent subsea
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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 has developed a Waste- to-Fuel process able to transform wet domestic waste into bio-oils with characteristics similar to 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 produce biofuels for automotive use. The 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 energy in the bio-oil from the total energy content of the feedstock. In 2018 a pilot plant treating wet domestic waste up to 700 kg/day was started at the Gela refinery.
Energy Transition
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 favoring the decarbonization of the whole value chain. In particular, the research deals with three areas of interest:
a)
Natural gas transportation, transformation and uses,
​
b)
H2S management,
​
c)
CO2 management.
​
On the forefront of Natural Gas transportation and conversion, important results have been obtained for the development of a process for the production of methanol from natural gas. The process is based on an Eni proprietary technology for the conversion of methane to syngas, which is cheaper and has a footprint and a weight much lower than the existing processes based on steam reformer.
In the area of H2S and CO2 capture, innovative highly effective solvents for the separation of H2S and CO2 from natural gas have been identified and tested at lab scale. Now the results is under scaling-up to a pilot unit with the 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. 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 LNG 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 to incur significant amounts of expenses in order to comply with pending environmental, health and safety protection and safeguard regulations, particularly in order to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere and cope with climate change and water quality of discharges, as well as availability.
International and European Union Environmental Laws Framework
On November 4, 2016, the Paris Agreement entered into force, exactly 30 days after the date on which the last of at least 55 Parties to the Convention accounting in total for at least an estimated 55% of the total
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global greenhouse gas emissions have deposited their instruments of ratification. To date, 189 Parties have ratified the Convention. This important step in the common international Climate Change strategy sets out a global action plan to keep a global temperature rise this century well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase even further to 1.5°C.
In 2019, the UN Climate Change Conference (COP 25) had taken place in Madrid under the Presidency of the Government of Chile. The COP 25 had an important role to play in moving forward with the Paris Agreement “rule- book” implementation and it laid the basis for more ambitious emission reduction commitments from Parties at the next conference (COP 26 to be held in Glasgow, UK). Main focus areas discussed during the COP 25 were adaptation to climate impacts, the support to loss and damage suffered by developing nations due to climate change, international climate finance and others. Regarding the rules for the international carbon market (article 6 of the Paris Agreement), the COP 25 did not reach any agreement. On this topic, negotiations could not go over the impasse due to a divergence between the Parties on a few crucial points and in the end, the issue was delayed until next year’s talks.
In 2020, other than agreeing upon a common framework for international carbon market, the Parties are required to submit new or updated national climate action plans, referred as Nationally Determined Contributions (NDCs) and, in this task, Parties are urged to consider the significant gap between the current emission pathways and the pathways consistent the Paris Agreement mitigation target.
During the COP 25, the European Union (EU) released the Green Deal Communication, in which it clearly announces its commitment on the environmental aspects. The document represents a package of measures that should enable European citizens and businesses to benefit from sustainable green transition. Measures accompanied with an initial roadmap of key policies range from ambitiously cutting emissions, to investing in cutting-edge research and innovation, to preserving Europe’s natural environment and achieving a climate neutral economy by 2050. The roadmap includes also a comprehensive plan to increase the EU’s GHG reduction target for 2030 to at least 50% and toward 55% vs 1990, compared to current target of 40%.
Once implemented in legislation, the new EU 2030 GHG reduction target will entail a revision of the main targets and provisions enforced by the current EU legislation. In particular, the existing Clean Energy for All Europeans (so called “Clean Energy Package”) developed between 2016 and early 2019, among the others commitments, set a binding target of 32% for renewable energy sources in the EU’s energy mix by 2030 and a binding target of at least 32.5% energy efficiency by 2030, relative to a ‘business as usual’ scenario.
The revised Renewable Energy Directive sets also the target for renewable energy in the transport sector. In particular, Member States must require fuel suppliers to supply a minimum of 14% of the energy consumed in road and rail transport by 2030 as renewable energy, of which at least 3.5% coming from advanced biofuels. In terms of environmental sustainability, high Indirect Land Use Change-risk feedstocks will be capped at 2019 levels until 2023 and then progressively phased-out up to zero by 2030.
A centerpiece of the EU’s 2030 energy and climate policy framework is the binding target to reduce overall GHG emissions by at least 40% below 1990 levels by 2030. To achieve this cost-effectively, the sectors covered by the EU Emission Trading System (EU ETS) will have to reduce their emissions by 43% compared with 2005, while non-ETS sectors will have to reduce theirs by 30%. The ETS is about to enter in its IV phase (2021-2030), in which the European cap will decline at an annual rate of 2.2%, compared to 1.74% of the previous phase. The carbon leakage sectors will still receive 100% of the free allowances calculated with the sectorial benchmark, for all the IV phase. All the Eni’s activity sectors are included in the new carbon leakage list, excluding the extraction and production of natural gas. Currently around 46% of Eni’s direct GHG emissions are included within the Carbon Pricing Scheme by its participation in the EU ETS.
In May 2018, the European institutions adopted the Effort Sharing Regulation (ESR) to ensure further emission reductions in sectors falling outside the scope of the EU ETS for the IV phase. The ESR maintains existing flexibilities (e.g. banking, borrowing and buying and selling between Member States) and provides two new flexibilities, allowing the use of some EU ETS emissions allowances and credits from land use sector to achieve the final target.
The Clean Energy Package includes also a new regulation on Governance of Energy Union, which asks all the Member States to draft their own National Energy and Climate Plans (NECPs), in order to plan, in an integrated manner, their climate and energy objectives, policies and measures, aligned with the broad EU targets. During 2019, most of the Member States presented their NECP for 2021-2030 period, to achieve their respective targets.
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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. In 2019 the European Commission has completed a fitness check of the two EU Ambient Air Quality (AAQ) Directives (Directives 2008/50/EC and 2004/107/EC). These Directives set air quality standards and requirements to ensure that Member States monitor and/or assess air quality in their territory, in a harmonized and comparable manner. The fitness check of the AAQ Directives was based on the analysis of the experience in all Member States, focusing on the period from 2008 to 2018 and evaluated the relevance, effectiveness, efficiency, coherence and EU added value of the AAQ Directives, in line with Better Regulation requirements.
In order to guarantee better quality standards and to shift toward a low carbon economy, in December 2017, the Commission has launched the Clean Mobility Package. This is a decisive step forward in implementing the EU’s commitments under the Paris Agreement for a binding domestic CO2 reduction of at least 40% till 2030. Its aim is to help accelerate the transition to low- and zero emissions vehicles, through a new target for the EU fleet wide average CO2 emissions of new passenger cars and vans of 30% by 2030 to provide stability and long-term direction. The Mobility Package has a 2025 intermediary target of 15% to ensure that investments kick-start already now. As the confirmation of Eni’s involvement in sustainable mobility in November Eni and FCA have signed a contract to carry out research and develop technological applications aimed at reducing CO2 emissions in road transport.
On December 31, 2016, the new National Emissions Ceilings (NEC) Directive entered into force to guarantee stricter limits on the five main pollutants in Europe: sulfur dioxide (SO2), nitrogen oxides (NOx), ammonia (NH3), volatile organic compounds (VOC) and primary particulate matter (PM). The Member States had time until June 30, 2018 to transpose the NEC Directive and had to submit the First National Air Pollution Control Programmes by April 1, 2019, setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments. The NEC directive aim is to improve not only human health but also the condition of ecosystems across the EU. In 2019 the Commission Guidance on the monitoring ecosystem impacts of air pollution was released. Moreover the first data on air pollution impacts on ecosystems was supposed to be submitted by Member States by 1 July 2019. in line with Directive 2016/2284 (National Emission Ceilings).
The Industrial Emission Directive (IED) 2010/75/EU is fundamental for European industries, it provides the framework for granting permits for about 50,000 industrial installations across the EU. It lays down rules on the integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are defined by the sector specific and cross-sector Best Available Technology (BAT) Conclusions.
In 2016, the Commission has published the Implementing Decision (EU) 2016/902 of May 30, 2016 establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU, for common wastewater and waste gas treatment/management systems in the chemical sector.
In February 2019, the Best Available Techniques Reference Document for the Management of Waste from Extractive Industries was published. In accordance with Directive 2006/21/EC, the reviewed document presents up -dated data and information on the management of waste from extractive industries, including information on BAT, associated monitoring, and developments in them. The new risk-based “BAT” approach considers the diversity of types of extractive waste, sites and operators and covers a wide range of potential risks that must be considered by operators responsible for waste management in the extractive industries.
In August 2017 the Commission Implementing decision 2017/1442 of July 31, 2017 entered in force. The decision establishes the best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for large combustion plants (LCP – combustion installations
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with a rated thermal input exceeding 50 MW). Plants with a thermal input lower than 50 MW are, however, discussed in the LCP BAT where technically relevant because smaller units can potentially be added to a plant to build one larger installation exceeding 50 MW. In December 2017, the Large Combustion Plant Best Available Technique reference document (LCP BREF) was published. The update of both documents was expected under the Emission Directive and will have a significant implication on the Eni’s technologies applied in the power plants. A Technical Working Group has been formed to implement a new Best Available Techniques Guidance Document on the upstream hydrocarbon exploration and production sector. Moreover, in November, Commission has published its implementing decision establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for the production of large volume organic chemicals (LVOC BAT). New emissions and efficiency standards will help national authorities to lower the environmental impact of the 3,200 installations that produce Large Volume Organic Chemicals (LVOC) and represent 63% of the EU’s entire chemical industry. The Member States must all the permits for LCPs in line with the LCP BAT conclusions by August 2021.
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 Regulation (No. 517/2014) which applies from January 1, 2015. The new regulation strengthens the previous measures and should cut by 2030 the EU’s F- gas emissions by two- thirds compared with 2014 levels. This represents a fair and cost-efficient contribution by the F-gas sector to the EU’s objective of cutting its overall GHG emissions by 80 – 95% of 1990 levels by 2050. In 2017, the EU continued to shape the F-gases strategy. In October 2017, the Commission Implementing Decision (EU) 2017/1984 was published in the Official Journal. The decision sets 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 24, 2017.
During the reporting year, the EU focused on improving the environmental management principles and rule. In December, the Commission published the decision, amending the user’s guide setting out the steps needed to participate in EMAS (decision 2017/2285). The guidelines offer an additional information and guidance about the steps needed to participate in EMAS, 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 specifies principles, requirements and guidelines for the quantification and communication of the carbon footprint of a product (CFP), based on International Standards on life cycle assessment.
In 2018 the European Parliament and Council approved the directives included in the Circular Economy Package, revising the EU legislation on waste, aiming to stimulate Europe’s transition towards a circular economy. The approved directives introduce new waste-management targets regarding reuse, recycling and landfilling, strengthens provisions on waste prevention and extended producer responsibility, and streamlines definitions, reporting obligations and calculation methods for targets. The 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 also asks the adoption of measures to strengthen separate collection of plastic waste, must be transposed in national legislations of the Member States by 3rd July 2021. According to the UE Green Deal the new circular economy action plan is attended in March 2020, as part of a broader EU 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 agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances
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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 communicate risk management measures to users. If the risks cannot be managed, Authorities can restrict the use of substances in different ways. Over time, hazardous substances should be substituted with less dangerous ones. The deadline of the REACH registration depends on the tonnage band of a substance and the classification of a 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 was replaced two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them.
European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction.
On June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The main elements of the EU Directive are the following:
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The Directive introduces licensing rules for the effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil&gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas.
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Independent national competent authorities, responsible for the safety of installations, are in charge of verifying the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards.
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Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities.
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Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation.
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Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents.
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Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities.
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Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore).
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Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.
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We believe that Eni operations are currently in compliance with all those regulations in each European country where they have been enacted.
Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will probably increase in future years.
Moreover, in order to achieve the highest safety standards of our operations in the Gulf of Mexico, Eni entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Fast Response System (HFRS) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.
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.
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As regards major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015).
The main changes in comparison to the previous Seveso Directive are:
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technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures;
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expanded public information about risks resulting from Company activities;
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modified rules in participation by the public in land-use planning projects related to Seveso plants; and
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stricter standards for inspections of Seveso establishments.
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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 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.
In 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 306, of which:
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92 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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23 certifications according to the ISO 50001 standard (certification for an energy management system);
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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).
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In 2019 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 95% for the OHSAS 18001/ISO 45001 standard and 94% for the ISO 14001 standard.
In 2019, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,323 million (+5% vs 2018).
Environment. In 2019, Eni incurred total expenditures of €963 million for the protection of the environment (with an increase of 5% with respect to 2018). Environmental expenditures are mainly related to remediation and reclamation activities (€367 million), waste management (€248 million), water management (€168 million), air protection (€54 million) and spill prevention (€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 2018, the new legislation didn’t impact significantly procedures already in place for safety in the workplace.
The dissemination of safety culture is a value for Eni. In 2019, in order to increase safety’s culture in the workforce, awareness-raising initiatives 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 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 deepening the knowledge of the European Norms on chemical substances, strengthening the awareness of the responsibilities and fulfilments of the organizational roles.
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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 are applied progressively in all operating activities. In 2019 Eni participated in a working group of EPSC (European Process Safety Center) on the definition of a set of shared operating rules on process safety which led, also through an internal technical team work attended by representatives and knowledge owners of Process Safety of the various Business Units and Operations representatives, to the definition of Eni’s Process Safety Fundamental.
In 2019, the Total Recordable Injury Rate for the workforce improved by 3% compared to 2018 (0.34 vs 0.35).
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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 set-up after the Macondo accident. The 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 oil spill preparedness and response.
Moreover in the same framework Eni participates at two Global Initiatives jointly led by the IMO and IPIECA: OSPRI (Black Sea, Caspian Sea and Central Eurasia) and WACAF (West, Central and Southern Africa).
Costs incurred in 2019 to support the safety levels of operations and to comply with applicable rules and regulations were €306 million.
Health. Eni’s activities for protecting health aim to continuously improve the psychophysical wellbeing of people in the workplace. Eni believes that it achieved a good performance in this area thanks to:
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plant and facility efficiency and reliability;
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promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment;
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certification programs of management systems for production sites and operating units;
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identified indicators in order to monitor exposure to chemical and physical agents;
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strong engagement in health protection for workers operating worldwide also with the support of international health providers capable of guaranteeing a prompt and adequate response to any emergency;
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identification of an effective and reliable health providers, in Italy and abroad;
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training programs for medics and paramedics.
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In order to protect the health and safety of its employees, Eni relies on a network of health care facilities located in its main operating areas. A set of international agreements with the best local and international health providers ensures efficient services and timely responses to emergencies.
Eni is engaged to the elaboration of HIA and relative standards to be applied to all new projects of evaluation of working exposure to environment, in Italy and abroad. The main aim of HIA is to avoid any negative impacts and maximize any positive impacts of the project on the host community and it is usually carried out as part of/or in conjunction with the Health, Environmental and a Social Impact Assessment process. Its results are used to develop appropriate mitigation measures and an improvement plan with the host community.
Information about Eni’s strategy and targets in a low-carbon scenario in accordance to standards set by the Task Force on climate-related Financial Disclosures (TCFD) of the Financial Stability Board and other non-financial information about sustainability is provided in the “Non -financial Information report” which is part of Eni’s 2019 Annual Report published in accordance with Italian law and practice. These reports are not incorporated by reference in this Form 20-F.
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Regulation of Eni’s businesses
Overview
The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments.
Regulation of exploration and production activities
Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements.
Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any production taxes or royalties, which may be in cash or in-kind. Concession contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production activity. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions realized. As a compensation for mineral concessions, pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with local tax legislation.
Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right.
Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in African, Middle Eastern and Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.
Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. Therefore, the Company recognizes at the same time an increase in the taxable profit, through the increase in revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme to PSA applies to Service contracts.
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In general, Eni is required to pay income tax on income generated from production activities (whether under a license or PSA). The taxes imposed upon oil&gas production profits and activities may be substantially higher than those imposed on other businesses.
Regulation of the Italian hydrocarbons industry
The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments.
Exploration & Production
The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”).
Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are 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).
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Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 – Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with exemptions only for on shore gas concessions with production lower than 10 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20,06%, with no exemptions).
Gas & Power
Wholesale gas market in Italy
In the last decade, and even more in the last years, a number of new rules have been introduced in order to improve liquidity and efficient functioning of the Italian wholesale gas market, fostering competition and at the same time improving the system security of supply. Among such new rules, it could be worth mentioning:
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Market based mechanisms for the allocation of storage capacities and of regasification capacities: moving away from the traditional allocation criteria based on tariffs, new auction mechanisms were implemented that enabled market players to express the market-value of storage and of regasification capacities, while at the same time ensuring the allowed revenues of storage operators and LNG terminal operators by means of specific parallel measures. Thanks to these reforms, much higher levels of capacity bookings have become structural for both types of infrastructures, and more LNG deliveries have been attracted recently to the country, to the benefit of security of supply and of market competition.
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An organized market platform (MGAS) for gas trading and gas balancing market, managed by the independent operator Gestore dei Mercati Energetici (GME) which also acts as a central counterparty, where different market participants (including TSO) can carry out spot and forward transactions at the “Punto di Scambio Virtuale” (PSV
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Virtual Trading Point). In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS: such activity is based on the service provided by some liquidity providers, in order to boost liquidity and trading activity on the same exchange, initially for the day-ahead market but with possible future extension to the within-day section and to the forward section of the MGAS.
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A new gas balancing regime, entered into force in October 2016 as an evolution of the one already in place and in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by the TSO about the daily gas consumption. The new gas balancing regime provides the incentive for shippers to balance their position via penalizing imbalance prices and at the same time it provides the possibility for shippers to modify intra-day their gas flow nominations and to trade on the market with other shippers and/or with the TSO itself  (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities).
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Management believes that these new regulation have already significantly increased and will continue increasing the level of liquidity and the competition in the wholesale natural gas market in Italy, leading to possible margin pressures.
Natural gas prices in the retail sector in Italy
Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the ARERA retains a power of surveillance on this matter as per Law No. 481/​1995 (establishing the ARERA) and Legislative Decree No. 164/2000. Furthermore, the ARERA is still
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entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by ARERA beside their own price proposals.
In 2013, a new tariff regime was fully enacted by ARERA targeting Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the ARERA are residential clients. With Resolution No. 196 effective from October 1, 2013, the ARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices at the TTF (Title Transfer Facility) hub in Northern Europe, replacing the then current regime that provided a mix between an oil-based indexation and spot prices.
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 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 could opt to be reimbursed for 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; 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. Those provisions explicated their effects in 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.
This new gas tariff indexation aiming at safeguarding the households was initially intended to remain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year (as per Law Decree 91/2018), and finally has been prorogated to January 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 variable), both complemented with contractual conditions regulated by the ARERA. Management believes that this development will increase competition in the Italian retail market for selling gas.
In the electricity market the regulated prices phase out will be effective: from January 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€).
Other regulatory developments in the gas and electric sector in Italy and Europe
Within the scope of access criteria to the main gas logistic infrastructures, and of the related access costs, the risk factors for the business are linked to the periodic processes by which each European country reviews the definition of economic conditions and access rules for transportation, LNG regasification and storage services. Concerning gas transportation tariffs, 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 on refining activity in Italy provides that Italian administrative bodies authorize plans filed by refining operators intended to set up new processing and storage plants and to upgrade capacity, while all other changes that do not affect capacity can be freely implemented. This regime was streamlined by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as “strategic installations” that need authorization from the State, in agreement with the local administrations. The Decree introduced a unitized process of authorization that must be finalized within 180 days, subject to compliance with applicable environmental regulations. the company has not experienced any material delays in obtaining relevant concessions for the upgrading of the Sannazzaro underway.
Marketing. Following the enactment of the above-mentioned Law Decree No. 1 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012, principals will be allowed to freely supply up to 50% of their requirements. In such case, the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Furthermore, the law 205/2017 provides some measures for preventing of tax evasion in the sale of oil products that in the past produced anticompetitive effects on the sector. The law requires the advance payment of Value Added Tax (VAT) on oil products before the extraction from deposits or the sale to consumer.
Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third -party access to unused storage capacity for petroleum products. Subsequently, various regulations have been enacted in Italy with the aim of improving network efficiency, modernizing service stations and opening up the market. Currently, all service stations are provided with self-service equipment and the sale of non-oil products has been broadly introduced by local administrative bodies.
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Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations, which might limit the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours.
The new regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/UE on alternative fuel infrastructures – has introduced minimum requirements for the construction of infrastructure for the development of alternative fuels to mitigate the environmental impacts of the transport sector. The legislation established, furthermore, an adequate number of charging stations accessible to the public to be created throughout the country by 2020.
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 these measures will favor competition in the Italian retail market and enhance the competitiveness of efficient players.
In order to support the achievement of the renewables target in the transport sector established by the EU and national laws, the Ministerial Decree of March 2, 2018, provides the legislative framework to incentivize the production of both biomethane and other advanced biofuels to be used in the transport sector.
The Decree provides incentives for plants starting operations between 2018 and 2022 and to plants that are converted to biomethane production.
The incentive consists in an allocation of a Certificate (CIC) for every 10 Gcal of biomethane produced. The certificate has a market value since fossil fuel marketers have to sell a minimum percentage of biofuels annually, for which they receive the same Certificates.
In order to access to incentives, producers must comply with legal and technical regulations governing the quality and certification of the produced biomethane, verified by the competent Authority (Gestore dei Servizi Energetici, GSE).
These measure aims to favor advanced biofuels production through the valorization of waste, notably of agricultural and farm/zoo technical waste.
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. Petroleum products’ prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Economic Development; such recommendations are considered by service station operators in establishing retail prices for petroleum products.
Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 (“Decree 22/2001”) enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil
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company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain.
As of December 31, 2019, Eni owned 5,6 mmtonnes of oil products inventories, of which 3,2 mmtonnes as “compulsory stocks”, 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 (34%), light and medium distillates (37%), refinery feedstock (20%), fuel oil (4%) and other products (5%) were located throughout the Italian territory both in refineries (85%) and in storage sites (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 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:
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requiring that an infringement be brought to an end;
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ordering interim measures;
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accepting commitments; and
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imposing fines, periodic penalty payments or any other penalty provided for in their national law.
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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 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, 2019, there were 225 subsidiaries and 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, 2019 is provided in 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

​ | ​ | ​ | ​ | ​ | ​ | 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 | ​ | ​

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(1)
For a discussion of the usefulness and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see – "Liquidity and capital resources – Financial Conditions" below.
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Reported earnings
In 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 decline in oil and gas realized prices, as well as in products margins in all of its business segments. Prices and margins reductions negatively affected the reported operating profit for an estimated €2.5 billion. The main negative factor were lower gas prices in all geographies with the worst declines recorded by the European benchmark gas spot price “PSV”, which was down by 34% and negatively affected the revenues of the E&P segment relating sales volumes of equity gas. Furthermore, the result of the E&P segment was significantly and negatively affected by lower re-selling prices of volumes of gas entitlements of a Libyan partner due to a different indexation between the procurement costs, which were oil-linked, and the reselling price which was benchmarked to spot prices in Europe. Due to different trends in the indexation, this resale activity resulted in a loss to Eni, which also negatively impacted the Group tax rate.
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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 of approximately €0.9 billion due to 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 time-to-market of its reserves as witnessed by new field start-ups in the year and fast ramp-up at core projects like the 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%.
Adjusted results
Adjusted operating profit and adjusted net profit are determined by excluding from the reported results inventory holding gains or losses and non-core gains and losses (pre and post-tax, respectively) that in our view do not reflect the ordinary results of our operations.
Adjusted operating profit (or loss) and adjusted net profit (or loss) provide management with an understanding of the results from our underlying operations and are used to evaluate our period-over-period operating performance, as management believes these provide more comparable measures as they adjust for disposals and special charges or gains not reflective of the underlying trends in our business. These Non-GAAP performance measures may also be useful to an investor in evaluating the underlying operating performance of our business and in comparing it with the performance of other oil&gas players, because the items excluded from the calculation of such measures can vary substantially from company to company depending upon accounting methods, management’s judgment, book value of assets, capital structure and the method by which assets were acquired, among other factors.
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, | ​
​ | ​ | ​ | 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 | ​ | ​

In 2019, the 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 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 €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 purchase of proved and unproved mineral interests in Algeria and Alaska for €0.4 billion, and were mainly directed to the development of hydrocarbons reserves and exploration
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projects. We divested some minor assets for a cash-in of €504 million. Cash returns to shareholders were €3,424 million and included the payment of the final dividend 2018, the interim 2019 dividend for an overall amount of  €3,018 million and the execution of a stock repurchase plan for €400 million.
Those inflows and outflows coupled with the initial recognition of the lease liabilities upon adoption of IFRS 16 effective since January 1, 2019 (see dedicated paragraph below) drove an increase of €4,301 million in the Group 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 finance debt including the lease liability to total equity.
Management evaluates the soundness of the Group balance sheet and its financial position by monitoring a non-GAAP measure of indebtedness, net borrowings, which is calculated by subtracting cash and cash equivalents and other very liquid financial assets from finance debt (see Glossary).
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 – leverage – ratio of net borrowings to total equity increased to 0.36 at year-end 2019 from 0.16 at year-end 2018. Excluding the impact of IFRS 16, leverage would have been 0.24. See paragraph “Financial condition” below, for a full reconciliation of net borrowings and leverage to the most comparable performance measures calculated in accordance with IFRS.
Trading environment

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Average price of Brent dated crude oil in U.S. dollars(1) | ​ | ​ | ​ | ​ | 64.30 | ​ | ​ | ​ | ​ | ​ | 71.04 | ​ | ​ | ​ | ​ | ​ | 54.27 | ​ | ​
Average price of Brent dated crude oil in euro(2) | ​ | ​ | ​ | ​ | 57.44 | ​ | ​ | ​ | ​ | ​ | 60.15 | ​ | ​ | ​ | ​ | ​ | 48.03 | ​ | ​
Average EUR/USD exchange rate(3) | ​ | ​ | ​ | ​ | 1.119 | ​ | ​ | ​ | ​ | ​ | 1.181 | ​ | ​ | ​ | ​ | ​ | 1.130 | ​ | ​
Standard Eni Refining Margin (SERM)(4) | ​ | ​ | ​ | ​ | 4.3 | ​ | ​ | ​ | ​ | ​ | 3.7 | ​ | ​ | ​ | ​ | ​ | 5.0 | ​ | ​
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 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 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 the first quarter 2020, crude oil prices have dropped materially, hitting a multi-year low below 30 $/bbl driven by the spread of a pandemic disease and a seemingly changed policy on part of OPEC+ from supporting prices to boost production. The impact of these trends is described in the section “Management expectations of operations” within this item 5.
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Critical accounting estimates
The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the carrying amounts of assets and liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience or other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas assets, specifically in the determination of proved and proved developed reserves and impairment of fixed assets. Other areas where management’s estimates and judgement 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 lease contracts. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A review of significant accounting estimates and judgemental areas is provided in “Item 18 – Note 1 to Consolidated Financial Statements”.
IFRS 16 adoption
Eni’s 2019 consolidated financial statements and the statements of profit and loss, cash flow and financial position commented in this Item 5 have been prepared incorporating the effects of the 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, 2019, without restating the comparative periods. Additional information about adoption of IFRS 16 with regard to assumptions and practical expedients used in the first application are provided in the notes to the consolidated financial statements under the heading “changes to accounting criteria”. A brief description of the new accounting for lease contracts under IFRS 16 and the main effects on 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 previous accounting standard, operating lease payments were recorded within operating expenses. The following table shows certain profit and 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 in 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 improvement in
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net cash provided by operating activities, which no longer includes the operating lease payments related to assets hired in connection with operating activities, but only includes the cash payments for the interest portion of the 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 interest portion of the 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 LL. The following table shows certain cash flow statement items as adjusted to exclude the effect of the application of IFRS 16 and a reconciliation to the 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 LL in the opening balance. However, the initial amount of Eni’s 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 partner billing process. As a result, the ROU of the asset utilized by a joint operation is recorded in its full amount in the balance sheet of the lead operator.
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Group results of 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, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million)​ | ​
Sales from operations | ​ | ​ | ​ | ​ | 69,881 | ​ | ​ | ​ | ​ | ​ | 75,822 | ​ | ​ | ​ | ​ | ​ | 66,919 | ​ | ​
Other income and revenues(1) | ​ | ​ | ​ | ​ | 1,160 | ​ | ​ | ​ | ​ | ​ | 1,116 | ​ | ​ | ​ | ​ | ​ | 4,058 | ​ | ​
Total revenues | ​ | ​ | ​ | ​ | 71,041 | ​ | ​ | ​ | ​ | ​ | 76,938 | ​ | ​ | ​ | ​ | ​ | 70,977 | ​ | ​
Operating expenses | ​ | ​ | ​ | ​ | (54,302) | ​ | ​ | ​ | ​ | ​ | (59,130) | ​ | ​ | ​ | ​ | ​ | (55,412) | ​ | ​
Other operating (expense) income | ​ | ​ | ​ | ​ | 287 | ​ | ​ | ​ | ​ | ​ | 129 | ​ | ​ | ​ | ​ | ​ | (32) | ​ | ​
Depreciation, depletion and amortization | ​ | ​ | ​ | ​ | (8,106) | ​ | ​ | ​ | ​ | ​ | (6,988) | ​ | ​ | ​ | ​ | ​ | (7,483) | ​ | ​
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) | ​ | ​ | ​ | ​ | 6,432 | ​ | ​ | ​ | ​ | ​ | 9,983 | ​ | ​ | ​ | ​ | ​ | 8,012 | ​ | ​
Finance income (expense) | ​ | ​ | ​ | ​ | (879) | ​ | ​ | ​ | ​ | ​ | (971) | ​ | ​ | ​ | ​ | ​ | (1,236) | ​ | ​
Income (expense) from investments | ​ | ​ | ​ | ​ | 193 | ​ | ​ | ​ | ​ | ​ | 1,095 | ​ | ​ | ​ | ​ | ​ | 68 | ​ | ​
PROFIT (LOSS) BEFORE INCOME TAXES | ​ | ​ | ​ | ​ | 5,746 | ​ | ​ | ​ | ​ | ​ | 10,107 | ​ | ​ | ​ | ​ | ​ | 6,844 | ​ | ​
Income taxes | ​ | ​ | ​ | ​ | (5,591) | ​ | ​ | ​ | ​ | ​ | (5,970) | ​ | ​ | ​ | ​ | ​ | (3,467) | ​ | ​
Net profit (loss) | ​ | ​ | ​ | ​ | 155 | ​ | ​ | ​ | ​ | ​ | 4,137 | ​ | ​ | ​ | ​ | ​ | 3,377 | ​ | ​
Attributable to: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- 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 sales from operations for the periods indicated.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (%)​ | ​
Operating expenses | ​ | ​ | ​ | ​ | 77.7 | ​ | ​ | ​ | ​ | ​ | 78.0 | ​ | ​ | ​ | ​ | ​ | 82.8 | ​ | ​
Depreciation, depletion, amortization,impairment reversals (impairment losses) of tangible and intangible and right of use assets, net | ​ | ​ | ​ | ​ | 15.2 | ​ | ​ | ​ | ​ | ​ | 10.5 | ​ | ​ | ​ | ​ | ​ | 11.2 | ​ | ​
OPERATING PROFIT | ​ | ​ | ​ | ​ | 9.2 | ​ | ​ | ​ | ​ | ​ | 13.2 | ​ | ​ | ​ | ​ | ​ | 12.0 | ​ | ​

Analysis of the line items of the profit and loss account
a) Total revenues
Eni’s revenues were €71,041 million and €76,938 million for the years ended December 31, 2019 and 2018, respectively. Total revenues consist of sales from operations and other income and revenues. Eni sales from operations amounted to €69,881 million and €75,822 million for the years ended December 31, 2019 and 2018, respectively, and its other income and revenues totaled €1,160 million and €1,116 million, respectively, in these periods.
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Sales from operations
The table below sets forth, for the periods indicated, sales from operations generated by each of Eni’s business segments including intragroup sales, together with consolidated sales from operations.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 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 | ​ | ​

2019 compared to 2018. Eni sales from operations (revenues) for 2019 (€69,881 million) decreased by €5,941 million from 2018 (or down by 7.8%) primarily reflecting a slowdown in commodity prices.
Revenues generated by the Exploration & Production segment (€23,572 million) decreased by €2,172 million (or down by 8.4%). This was due to lower average realizations on equity hydrocarbons (oil realizations down by 9.5%; gas realizations down by 5% on average in dollar terms) driven by lower prices for the marker Brent (down by 9.5%) and gas prices in Europe. Furthermore, lower benchmark gas prices negatively affected the revenues earned from reselling the gas volumes entitlements of a Libyan partner in the European market. Finally, y-o-y comparability was negatively affected by the de-recognition of our former subsidiary Eni Norge at the end of 2018, following a business combination with the Norwegian company Point Resources to established the Vår Energi joint-venture (Eni’s share 69.6%).
Revenues generated by the Gas & Power segment (€50,015 million) decreased by €5,675 million (or down by 10.2%). The decrease reflected lower natural gas prices in Europe and declining LNG prices due to a weaker Asian scenario and lower volumes sold.
Revenues generated by the Refining & Marketing and Chemical segment (€23,334 million) decreased by €1,882 million (or down by 7.5%) due to lower average selling prices 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 driven by lower 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, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million)​ | ​
Purchases, services and other | ​ | ​ | ​ | ​ | 50,874 | ​ | ​ | ​ | ​ | ​ | 55,622 | ​ | ​ | ​ | ​ | ​ | 51,548 | ​ | ​
Impairment losses (impairment reversals) of trade and other receivables, net | ​ | ​ | ​ | ​ | 432 | ​ | ​ | ​ | ​ | ​ | 415 | ​ | ​ | ​ | ​ | ​ | 913 | ​ | ​
Payroll and related costs | ​ | ​ | ​ | ​ | 2,996 | ​ | ​ | ​ | ​ | ​ | 3,093 | ​ | ​ | ​ | ​ | ​ | 2,951 | ​ | ​
Operating expenses | ​ | ​ | ​ | ​ | 54,302 | ​ | ​ | ​ | ​ | ​ | 59,130 | ​ | ​ | ​ | ​ | ​ | 55,412 | ​ | ​

2019 compared to 2018. Operating expenses for 2019 (€54,302 million) decreased by €4,828 million y-o-y, down by 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 due to lower
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prevailing market prices). Purchases, services and other costs included approximately €390 million relating mainly to environmental provisions and the recognition of losses on certain contractual and commercial disputes. Payroll and related costs (€2,996 million) decreased by €97 million from 2018, down by 3.1%, mainly due to the circumstance that in 2018 higher provisions for redundancy incentives were accounted relating to an early retirement program in the Eni gas e luce subsidiary.
c) Depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off
The table below sets forth a breakdown of depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off for the periods indicated.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million)​ | ​
Exploration & Production | ​ | ​ | ​ | ​ | 7,060 | ​ | ​ | ​ | ​ | ​ | 6,152 | ​ | ​ | ​ | ​ | ​ | 6,747 | ​ | ​
Gas & Power | ​ | ​ | ​ | ​ | 447 | ​ | ​ | ​ | ​ | ​ | 408 | ​ | ​ | ​ | ​ | ​ | 345 | ​ | ​
Refining & Marketing and Chemicals | ​ | ​ | ​ | ​ | 485 | ​ | ​ | ​ | ​ | ​ | 399 | ​ | ​ | ​ | ​ | ​ | 360 | ​ | ​
Corporate and other activities | ​ | ​ | ​ | ​ | 146 | ​ | ​ | ​ | ​ | ​ | 59 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​
Impact of unrealized intragroup profit elimination(1) | ​ | ​ | ​ | ​ | (32) | ​ | ​ | ​ | ​ | ​ | (30) | ​ | ​ | ​ | ​ | ​ | (29) | ​ | ​
Total depreciation, depletion and amortization | ​ | ​ | ​ | ​ | 8,106 | ​ | ​ | ​ | ​ | ​ | 6,988 | ​ | ​ | ​ | ​ | ​ | 7,483 | ​ | ​
Impairment losses of tangible and intangible and right of use assets, net | ​ | ​ | ​ | ​ | 2,544 | ​ | ​ | ​ | ​ | ​ | 1,292 | ​ | ​ | ​ | ​ | ​ | 862 | ​ | ​
Impairment of goodwill | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Impairment reversal of tangible and intangible assets, net | ​ | ​ | ​ | ​ | (382) | ​ | ​ | ​ | ​ | ​ | (426) | ​ | ​ | ​ | ​ | ​ | (1,087) | ​ | ​
Write-off of tangible and intangible assets | ​ | ​ | ​ | ​ | 300 | ​ | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 263 | ​ | ​
Total depreciation, depletion, amortization, impairment losses (impairment reversals) of tangible and intangible and right of use assets, net and write off of tangible and intangible assets | ​ | ​ | ​ | ​ | 10,594 | ​ | ​ | ​ | ​ | ​ | 7,954 | ​ | ​ | ​ | ​ | ​ | 7,521 | ​ | ​

​
(1)
This item concerned mainly intra-group sales of goods and capital, recorded at period end in the assets of the purchasing business segment.
​
2019 compared to 2018. In 2019, depreciation, depletion and amortization charges (€8,106 million) increased by €1,118 million from 2018, or 16%, mainly in the Exploration & Production segment (an increase of €908 million) mainly due to the depreciation charges of the right-of-use asset in accordance to IFRS 16, which provided a new accounting framework for operating leases without restating the comparative periods, higher charges recorded in connection with an upward revision of the present value of capitalized assets retirement costs due to lower interest rates, as well as fields started-up and new projects ramp-up.
In 2019, the Group recorded impairment losses at property, plant and equipment for a total amount of €2,188 million, mainly relating to: (i) impairment losses of oil&gas properties due to downward reserves revisions and 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 €1,217 million); (ii) impairment losses recorded by the Refining & Marketing business, mainly at the Sannazzaro refinery, reflecting a revised margin outlook both at high and 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 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 (€103 million in the full year).
Write-off charges amounted to €300 million and related to previously capitalized costs of exploratory wells which were expensed through profit because it was determined that they did not encounter commercial quantities of hydrocarbons or due to lack of management commitment in pursuing further appraisal activity mainly in Australia, Kazakhstan and Pakistan.
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d) Operating profit (loss) by segment
The table below sets forth Eni’s operating profit by business segment for the periods indicated.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million)​ | ​
Exploration & Production | ​ | ​ | ​ | ​ | 7,417 | ​ | ​ | ​ | ​ | ​ | 10,214 | ​ | ​ | ​ | ​ | ​ | 7,651 | ​ | ​
Gas & Power | ​ | ​ | ​ | ​ | 699 | ​ | ​ | ​ | ​ | ​ | 629 | ​ | ​ | ​ | ​ | ​ | 75 | ​ | ​
Refining & Marketing and Chemicals | ​ | ​ | ​ | ​ | (854) | ​ | ​ | ​ | ​ | ​ | (380) | ​ | ​ | ​ | ​ | ​ | 981 | ​ | ​
Corporate and other activities | ​ | ​ | ​ | ​ | (710) | ​ | ​ | ​ | ​ | ​ | (691) | ​ | ​ | ​ | ​ | ​ | (668) | ​ | ​
Impact of unrealized intragroup profit elimination | ​ | ​ | ​ | ​ | (120) | ​ | ​ | ​ | ​ | ​ | 211 | ​ | ​ | ​ | ​ | ​ | (27) | ​ | ​
Operating profit (loss) | ​ | ​ | ​ | ​ | 6,432 | ​ | ​ | ​ | ​ | ​ | 9,983 | ​ | ​ | ​ | ​ | ​ | 8,012 | ​ | ​

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

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (%)​ | ​
Exploration & Production | ​ | ​ | ​ | ​ | 31.5 | ​ | ​ | ​ | ​ | ​ | 39.7 | ​ | ​ | ​ | ​ | ​ | 39.2 | ​ | ​
Gas & Power | ​ | ​ | ​ | ​ | 1.4 | ​ | ​ | ​ | ​ | ​ | 1.1 | ​ | ​ | ​ | ​ | ​ | 0.1 | ​ | ​
Refining & Marketing and Chemicals | ​ | ​ | ​ | ​ | (3.7) | ​ | ​ | ​ | ​ | ​ | (1.5) | ​ | ​ | ​ | ​ | ​ | 4.4 | ​ | ​
Group | ​ | ​ | ​ | ​ | 9.2 | ​ | ​ | ​ | ​ | ​ | 13.2 | ​ | ​ | ​ | ​ | ​ | 12.0 | ​ | ​

Exploration & Production. In 2019, the Exploration & Production segment reported an operating profit of €7,417 million, with a decrease of €2,797 million compared to the operating profit of €10,214 million reported in 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 losses taken at oil&gas properties, partly offset by production growth and a better volume/mix performance reflecting higher contribution of barrels with higher-than-average profitability. The y-o-y comparison of operating profit was affected also by the following items: (i) the circumstance that the prior year result benefitted from the contribution of the former consolidated subsidiary Eni Norge (€1,278 million) which was de-recognized at the end of 2018 following the business combination with Point Resources to establish Vår Energi, an equity-accounted joint venture, fully operational since January 1, 2019; (ii) the adoption of IFRS 16, which was a positive of approximately €220 million, having Eni elected to adopt the modified retrospective approach, without restating the comparative information. A discussion on trends in production for 2019 is provided in the section “Executive summary”.
In 2019, the Company’s liquids and gas realizations decreased on average by 8.3% in dollar terms, driven by a weak trading environment. Eni’s average oil realizations decreased on average by 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 5%. The 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 marketed in Europe, because Eni’s average realized gas prices are calculated only with reference to equity production.
In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the non-core gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. In 2019, 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 €8,640 million, with a decrease of €2,210 million from 2018, down by 20.4%, driven by: (i) a negative impact of the trading environment (€2.23 billion) mainly due lower prices of equity gas as well as 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; (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 negative trends were partly offset by an improved performance driven by production growth and a better volume/mix performance reflecting higher contribution of barrels with higher-than-average profitability, partly offset by bigger write-off expenses related to unsuccessful exploration wells. Management estimated that the segment internal performance increased operating profit by 7%.
Operating profit included the revenues relating to certain gas volumes which were paid by the buyer without lifting the underlying volume due to the take-or-pay clause provided in a long-term supply agreement. Management has ascertained that it is highly likely that the buyer will not redeem its contractual right to lift the pre-paid volumes in future reporting periods within the contractual terms. Therefore the price paid by the buyer was recognized as revenue.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 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 2019, the Gas & Power segment reported an operating profit of €699 million, an increase of €70 million compared to the profit of €629 million of the previous year, mainly due to a better performance of the retail business.
In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. The items excluded from GAAP operating profit in determining the Non-GAAP measure of profitability mainly include effects associated with commodity fair-valued derivatives.
Particularly, we enter into commodity and currency derivatives to reduce our exposure to (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas and power or to lock in a commercial margin once a sale contract has been signed or is highly probable, and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge the Group net exposure to commodities and exchange rates but do not meet the requirements for being accounted for as hedges in accordance to IFRS.
Therefore, in explaining year-on-year charges and in evaluating the business performance management believes that is appropriate to identify the 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 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 where underlying physical transaction has yet to be settled with the delivery of the underlying commodity. Furthermore, although the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivable and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and currency differences at our dollar-denominated trade payables and receivables as part of the underlying business performance.
Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating profit of €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 to 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, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Gas & Power​ | ​ | ​ | (€ million)​ | ​
GAAP operating profit (loss) | ​ | ​ | ​ | ​ | 699 | ​ | ​ | ​ | ​ | ​ | 629 | ​ | ​ | ​ | ​ | ​ | 75 | ​ | ​
Impairment losses (impairment reversals), net | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | (71) | ​ | ​ | ​ | ​ | ​ | (146) | ​ | ​
Environmental provisions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Provision for redundancy incentives | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 122 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​
Fair value gains/losses on commodity derivatives | ​ | ​ | ​ | ​ | (423) | ​ | ​ | ​ | ​ | ​ | (156) | ​ | ​ | ​ | ​ | ​ | 157 | ​ | ​
Reclassification of currency derivatives and translation effects to management measure of business performance | ​ | ​ | ​ | ​ | 92 | ​ | ​ | ​ | ​ | ​ | 112 | ​ | ​ | ​ | ​ | ​ | (171) | ​ | ​
Estimated revenues accruals in the retail G&P | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 64 | ​ | ​
Revision of estimated revenues accruals in the retail G&P (difference between incurred loss vs. expected loss model) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 223 | ​ | ​
Other | ​ | ​ | ​ | ​ | 245 | ​ | ​ | ​ | ​ | ​ | (92) | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​
Total gains and charges | ​ | ​ | ​ | ​ | (45) | ​ | ​ | ​ | ​ | ​ | (86) | ​ | ​ | ​ | ​ | ​ | 139 | ​ | ​
Non-GAAP operating profit (loss) | ​ | ​ | ​ | ​ | 654 | ​ | ​ | ​ | ​ | ​ | 543 | ​ | ​ | ​ | ​ | ​ | 214 | ​ | ​
of which: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
– Gas & LNG Marketing and Power | ​ | ​ | ​ | ​ | 376 | ​ | ​ | ​ | ​ | ​ | 342 | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​
– retail business | ​ | ​ | ​ | ​ | 278 | ​ | ​ | ​ | ​ | ​ | 201 | ​ | ​ | ​ | ​ | ​ | 137 | ​ | ​

Refining & Marketing and Chemicals. In 2019, the Refining & Marketing and Chemicals segment reported an operating loss of €854 million, compared to an operating loss of €380 million reported in 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 the book value of inventories accounted for under the weighted-average cost method of accounting.
The main item excluded from GAAP operating profit in determining the Non-GAAP measure of profitability is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the
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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 described above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding those items, R&M business reported a Non-GAAP operating profit of €220 million (€390 million in 2018) while the Chemical business reported a Non-GAAP operating loss of €268 million (a loss of €10 million in 2018).
The refining activity was negatively affected by lower refining margins mainly due to narrowing price differentials between heavy crudes and the Brent market benchmark which impaired the profitability of 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 main end-markets, particularly the 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 Priolo hub, which was fully operational by the end of July, and by other unplanned shutdowns.

​ | ​ | ​ | 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 activities in support of operating subsidiaries, central functions like information technology,
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legal counselling, human resources, insurance activities general and administrative support, as well as the Group environmental clean-up and remediation activities performed by the subsidiary EniRewind and the Energy Solutions business engaged in the development of renewable energy.
The aggregate Corporate and Other activities reported an operating loss of €710 million in 2019, an increase of €19 million from 2018, or 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) | ​ | ​

In 2019, net finance expenses were €879 million, a small improvement of €92 million from 2018. This reduction was due to lower losses at fair-valued currency derivatives, lacking the formal criteria to be designated as hedges under IFRS, partly offset by lower gains on currency translation differences at dollar-denominated payables and receivables accrued by Italian subsidiaries, as the Group normally pools different exposures to the currency risk retained by operating subsidiaries and then hedges the Group net exposure to the risk.
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 a gain of €17 million, reverting a loss of €173 million accounted in 2018 driven by the impairment of operating financing receivables due by an equity-accounted entity, which engaged in the execution of an exploration projects that was written-off due to an unsuccessful outcome.
f) Net income from investments
In 2019 the Group reported a net profit from investments of €193 million related to:
i).
dividends of €247 million paid by minority investments in certain entities which were designated at fair value through other comprehensive income under IFRS 9 except for dividends which are recorded through profit. These entities mainly comprised Nigeria LNG Ltd (€186 million, where Eni has an interest of 10.4%) and Saudi European Petrochemical Co (€46 million, where Eni has an interest of 10%);
​
ii).
a loss of €88 million recorded at equity-accounted investments, mainly in the R&M and Chemical segment (€63 million) and in the Corporate and other activities (€21 million). These share of profits at equity-accounted investments included the contribution of the upstream joint venture Vår Energi (€49 million).
​
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​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 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 2019, income taxes amounted to €5,591 million, down by €379 million compared to 2018, or 6.3%. This decrease reflected lower income before taxes which was €4,361 million lower than in 2018.
Tax rate was approximately 97% compared to 59% reported in 2018, reflecting a higher share of taxable incomes reported by the Exploration & Production segment in jurisdictions subject to higher-than-average tax rates, the tax effect related to a loss incurred in connection with the reselling of gas entitlements of a Libyan partner as disclosed in the “executive summary” section, while taxable losses were incurred in jurisdictions with a lower-than-average statutory tax rate. The Group tax rate was also negatively impacted by the write-off of deferred tax assets of approximately €900 million due to projections of lower future taxable profit at Italian subsidiaries.
In 2020, we expect that a lower crude oil price environment will negatively affect our tax rate.
Liquidity and capital resources
Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and share repurchases over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of minority interests in certain of our exploration assets and other non-strategic activities. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and balanced financing structure.
The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million)​ | ​
Net profit (loss) | ​ | ​ | ​ | ​ | 155 | ​ | ​ | ​ | ​ | ​ | 4,137 | ​ | ​ | ​ | ​ | ​ | 3,377 | ​ | ​
Adjustments to reconcile net profit to net cash provided by operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
– amortization and depreciation charges, impairment losses, write-off and other non monetary items | ​ | ​ | ​ | ​ | 10,480 | ​ | ​ | ​ | ​ | ​ | 7,657 | ​ | ​ | ​ | ​ | ​ | 8,720 | ​ | ​
– net gains on disposal of assets | ​ | ​ | ​ | ​ | (170) | ​ | ​ | ​ | ​ | ​ | (474) | ​ | ​ | ​ | ​ | ​ | (3,446) | ​ | ​
– dividends, interest, taxes and other changes | ​ | ​ | ​ | ​ | 6,224 | ​ | ​ | ​ | ​ | ​ | 6,168 | ​ | ​ | ​ | ​ | ​ | 3,650 | ​ | ​
Changes in working capital related to operations | ​ | ​ | ​ | ​ | 366 | ​ | ​ | ​ | ​ | ​ | 1,632 | ​ | ​ | ​ | ​ | ​ | 1,440 | ​ | ​
Dividends received by equity investments | ​ | ​ | ​ | ​ | 1,346 | ​ | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 291 | ​ | ​
Taxes paid | ​ | ​ | ​ | ​ | (5,068) | ​ | ​ | ​ | ​ | ​ | (5,226) | ​ | ​ | ​ | ​ | ​ | (3,437) | ​ | ​
Interests (paid) received | ​ | ​ | ​ | ​ | (941) | ​ | ​ | ​ | ​ | ​ | (522) | ​ | ​ | ​ | ​ | ​ | (478) | ​ | ​
Net cash provided by operating activities | ​ | ​ | ​ | ​ | 12,392 | ​ | ​ | ​ | ​ | ​ | 13,647 | ​ | ​ | ​ | ​ | ​ | 10,117 | ​ | ​
Capital expenditures | ​ | ​ | ​ | ​ | (8,376) | ​ | ​ | ​ | ​ | ​ | (9,119) | ​ | ​ | ​ | ​ | ​ | (8,681) | ​ | ​
Acquisition of investments and businesses | ​ | ​ | ​ | ​ | (3,008) | ​ | ​ | ​ | ​ | ​ | (244) | ​ | ​ | ​ | ​ | ​ | (510) | ​ | ​
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | ​ | ​ | ​ | ​ | 504 | ​ | ​ | ​ | ​ | ​ | 1,242 | ​ | ​ | ​ | ​ | ​ | 5,455 | ​ | ​
Other cash flow related to investing activities | ​ | ​ | ​ | ​ | (254) | ​ | ​ | ​ | ​ | ​ | 942 | ​ | ​ | ​ | ​ | ​ | (373) | ​ | ​
Net investment (divestment) of securities and financing receivables not-related to operations (*) | ​ | ​ | ​ | ​ | (279) | ​ | ​ | ​ | ​ | ​ | (357) | ​ | ​ | ​ | ​ | ​ | 341 | ​ | ​

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​ | ​ | ​ | 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 the line items of the profit and loss account
In 2019, adjustments to reconcile net profit to net cash provided by operating activities mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization and impairment charges and the write-off of tangible and intangible assets (€10,594 million). Adjustments to net profit also included accrued income taxes (€5,591 million) and interest expense (€1,027 million), which were partly offset by amounts actually paid (€5,068 million and €1,029 million, respectively).
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Net profit was negatively impacted by extraordinary credit losses related to a valuation allowance for doubtful accounts incurred in the E&P business and certain provisions for an overall amount of €336 million.
a) Changes in working capital related to operations
In 2019, working capital generated an inflow of €366 million. This was mainly due to a positive balance between trade receivables collected and trade payables paid (a net inflow of €83 million) mainly in the Gas & Power segment 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 ongoing capital projects to develop hydrocarbons reserves in the Country (€280 million), mainly the Zohr project. These inflows were partly offset by the outflows in connection with the settlement of an arbitration proceeding which was provisioned in the previous reporting period.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | ​ | ​ | (€ million)​ | ​
Exploration & Production | ​ | ​ | ​ | ​ | 6,996 | ​ | ​ | ​ | ​ | ​ | 7,901 | ​ | ​ | ​ | ​ | ​ | 7,739 | ​ | ​
Gas & Power | ​ | ​ | ​ | ​ | 230 | ​ | ​ | ​ | ​ | ​ | 215 | ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​
Refining & Marketing and Chemicals | ​ | ​ | ​ | ​ | 933 | ​ | ​ | ​ | ​ | ​ | 877 | ​ | ​ | ​ | ​ | ​ | 729 | ​ | ​
Corporate and other activities | ​ | ​ | ​ | ​ | 231 | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | 87 | ​ | ​
Impact of unrealized intragroup profit elimination | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | (17) | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​
Capital expenditures | ​ | ​ | ​ | ​ | 8,376 | ​ | ​ | ​ | ​ | ​ | 9,119 | ​ | ​ | ​ | ​ | ​ | 8,681 | ​ | ​
Acquisitions of investments and businesses | ​ | ​ | ​ | ​ | 3,008 | ​ | ​ | ​ | ​ | ​ | 244 | ​ | ​ | ​ | ​ | ​ | 510 | ​ | ​
​ | ​ | ​ | ​ | ​ | 11,384 | ​ | ​ | ​ | ​ | ​ | 9,363 | ​ | ​ | ​ | ​ | ​ | 9,191 | ​ | ​
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | ​ | ​ | ​ | ​ | (504) | ​ | ​ | ​ | ​ | ​ | (1,242) | ​ | ​ | ​ | ​ | ​ | (5,455) | ​ | ​

Capital expenditures totaled €8,376 million and €9,119 million, respectively in 2019 and in 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 €3,008 million in 2019 and mainly related to the acquisition of a 20% interest in ADNOC Refining in Abu Dhabi for a cash consideration of €2,896 million. The transaction is part of Eni’s strategy aimed at achieving better geographical diversification of the portfolio and at rebalancing along the hydrocarbons value chain. Other investments comprised a share capital increase of €39 million at the Lotte Versalis Elastomers Co Ltd joint venture engaged in the elastomers production in South Korea and minor assets.
In 2019, disposals amounted to €504 million and mainly related to the divestment of a 20% interest in the Merakes discoveries to Neptune for €207 million, the sale of the wholly-owned subsidiary Agip Oil Ecuador BV (€189 million) and other minor non-strategic assets.
b) Dividends paid, share repurchases and changes in non-controlling interests and reserves
In 2019, dividends paid and changes in non-controlling interests and reserves (€3,424 million) related to dividend paid to Eni shareholders (€3,018 million, of which €1,542 million relating to the 2019 interim dividend and €1,476 million to the final dividend for fiscal year 2018) and the execution of a repurchase program of the Eni share for €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, a liquidity reserve made of held-for-trading securities and finally other liquid assets not related to operations (financing receivables and securities). The Company is retaining a liquidity reserve, which comprises very liquid investments, mainly sovereign bonds and corporate securities which management has selected based on their creditworthiness. This cash reserve was established by investing part of the proceeds from the disposal plan carried out in the latest years. Those securities amounted to €6,760 million as of end
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of 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 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.
The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure.

​ | ​ | ​ | As of December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
​ | ​ | ​ | Short-term | ​ | ​ | Long-term | ​ | ​ | Total | ​ | ​ | Short-term | ​ | ​ | Long-term | ​ | ​ | Total | ​
Finance debt (short-term and long-term debt) | ​ | ​ | ​ | ​ | 5,608 | ​ | ​ | ​ | ​ | ​ | 18,910 | ​ | ​ | ​ | ​ | ​ | 24,518 | ​ | ​ | ​ | ​ | ​ | 5,783 | ​ | ​ | ​ | ​ | ​ | 20,082 | ​ | ​ | ​ | ​ | ​ | 25,865 | ​ | ​
Lease liabilities | ​ | ​ | ​ | ​ | 889 | ​ | ​ | ​ | ​ | ​ | 4,759 | ​ | ​ | ​ | ​ | ​ | 5,648 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | ​ | ​ | ​ | (5,994) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5,994) | ​ | ​ | ​ | ​ | ​ | (10,836) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (10,836) | ​ | ​
Securities held for trading | ​ | ​ | ​ | ​ | (6,760) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6,760) | ​ | ​ | ​ | ​ | ​ | (6,552) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6,552) | ​ | ​
Non operating financing receivables | ​ | ​ | ​ | ​ | (287) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (287) | ​ | ​ | ​ | ​ | ​ | (188) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (188) | ​ | ​
Net borrowings | ​ | ​ | ​ | ​ | (6,544) | ​ | ​ | ​ | ​ | ​ | 23,669 | ​ | ​ | ​ | ​ | ​ | 17,125 | ​ | ​ | ​ | ​ | ​ | (11,793) | ​ | ​ | ​ | ​ | ​ | 20,082 | ​ | ​ | ​ | ​ | ​ | 8,289 | ​ | ​
​

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

At December 31, 2019, total finance debt of €24,518 million consisted of €5,608 million of short-term debt (including the portion of long-term debt due within twelve months equal to €3,156 million) and €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 €18,779 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €2,611 million (including accrued interest and discount). Bonds issued in 2019 amounted to €1,635 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (69%), U.S. dollar (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. In 2019, capital expenditures of the Exploration & Production segment amounted to €6,996 million, mainly related to the development of oil&gas reserves (€5,931 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, Nigeria, Kazakhstan, Indonesia, Mexico, the United States and Angola. Exploration expenditures (€586 million) were directed in particular to Egypt, Angola, Mexico, the United Arab Emirates and Libya.
In 2019, a total amount of €400 million related to the purchase of proved and unproved reserves in Alaska and Algeria.
Gas & Power. In 2019, capital expenditures in the Gas & Power segment totaled €230 million and mainly related to gas marketing initiatives (€176 million) due to the capitalization of expenses for the acquisition of retail customers, and to the business of power generation (€42 million).
Refining & Marketing and Chemicals. In 2019, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €933 million and regarded mainly: (i) refining activity in Italy and outside Italy (€683 million) for the rebuilding of the EST conversion plant at the Sannazzaro refinery, the upgrading of the Gela refinery into a biorefinery, increasing plants’ integrity, as well as initiatives to comply with stricter environmental and 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 (€132 million); (iii) plant upgrading, efficiency and compliance to stricter environmental and safety standards in the Chemical business (€93 million).
Recent developments
The table below sets forth certain indicators of the trading environment for the periods indicated:

​ | ​ | ​ | Three months ended March 31, | ​ | ​ | Three months ended March 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2020 | ​
Average price of Brent dated crude oil in U.S. dollars(1) | ​ | ​ | ​ | ​ | 63 | ​ | ​ | ​ | ​ | ​ | 51 | ​ | ​
Average EUR/USD exchange rate(2) | ​ | ​ | ​ | ​ | 1.136 | ​ | ​ | ​ | ​ | ​ | 1.100 | ​ | ​
Standard Eni Refining Margin (SERM)(3) | ​ | ​ | ​ | ​ | 3.4 | ​ | ​ | ​ | ​ | ​ | 3.3 | ​ | ​
Gas at the PSV in $/mmBTU | ​ | ​ | ​ | ​ | 7.1 | ​ | ​ | ​ | ​ | ​ | 3.7 | ​ | ​

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(1)
Price per barrel. Source: Platt’s Oilgram.
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(2)
Source: ECB.
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(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 31, 2020 the Brent crude oil price was approximately 51 $/BBL on average, approximately 20% lower than in the first quarter of 2019. This trend will negatively affect reported revenues, profitability and cash flow of our Exploration & Production segment in 2020. See “management expectations of operations” below.
Significant transactions
The significant transactions that occurred post-closing are described in 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
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, capital discipline, effective project execution and strict control of operating expenses and working capital.
Exploration will continue driving the Company’s growth in the short and long-term. 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 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 in case of material discoveries.
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Our dual exploration model contemplates the acquisition of high interests in exploration leases and, in case of exploration success, the partial divestiture of the discovered resources with a view of accelerating the conversion of resources into cash or of accomplishing asset swaps.
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 production to be negatively affected by the expected triggering of a 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 field in Egypt, Block 15/06 in Angola and the Area 1 fields off Mexico, as well as continuing production optimization to counteract fields natural decline. The main start-ups expected in the plan period include 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 Merakes gas field in Indonesia, phase two of the Nenè Marine field in Congo, the gas discovery of Coral in Area 4 offshore Mozambique, the Dalma gas fields offshore the UAE and other developments. We estimate that new field start-ups, production ramp-ups and expansion projects of
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existing fields will add approximately 800 KBOE/d of new production by 2023. We have good visibility as to the ability to achieve those production targets because they relate to already-sanctioned projects, mostly of which are operated, and to incremental development phases at our existing profit centers.
Our production plans include assumptions relating to production levels in certain countries that are particularly exposed to risks of disruptions and political instability. To factor in possible risks of unfavorable geopolitical developments in those countries, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, social unrest, clashes and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. We note that production at one of our field in Libya is currently shut down due to the situation of socio-political instability underway in the country. However, the above-mentioned contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. Furthermore, in recent years we have pursued a strategy intended to diversify the geographic reach of our operations aiming at reducing the geopolitical risk in our portfolio. Based on this, we forecast to lessen going forward our dependence on less politically stable areas such as Libya, where we expect to reduce the weight of this country production relative to our portfolio, by increasing the size of more stable areas like UAE, Mexico, Norway and Mozambique.
Our production plans and financial projects are based on a gradual recovery in Brent prices post 2020 up to our long-term case of 70 $/BBL in 2022 and going forwards (on constant monetary term 2022, i.e. from 2023 onwards crude oil prices will grow in line with a projected inflationary rate). Our pricing assumptions are based on forecast of a recovery in oil demand growth in the medium term, against the backdrop of a moderate pace of expansion in the global economy. We also expect that international oil companies will retain a disciplined approach to capital spending going forward, while US independent producers have shown recently the intention of shifting their focus from growth to shareholders’ returns. There are some risks to this outlook, including uncertainties over the strength of 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 Brent crude benchmark losing more than 50% from the highs recorded early in January at 65 $/barrel, down to current values below 30 $/barrel. This sudden movement was driven by a fall in global demand for oil and rising risks of oversupplies due to spread of a pandemic disease and to the recent developments within the OPEC+, as discussed in the previous paragraph. We expect a weak trading environment throughout 2020.
Due to those risks and uncertainties, management intends to retain a strong focus on capital and cost 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 projects will be carefully selected against our pricing assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure and the execution risk leveraging on a phased approach in developing our projects. Secondly, we plan to deliver our planned projects on time and on budget. Several of our projects are complex due to scale and reach of operations, environmentally-sensitive locations, external conditions, including offshore operations, industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. We plan to mitigate those risks in the future by continuing deployment of our skills and by our model of project execution driven by: (i) the execution in parallel of the main project activities, including discovery appraisal and pre-fid activities; (ii) the in-sourcing of critical engineering and project management phases, for example we are exercising strict control over construction, hook-up and commissioning; (iii) the design-to-cost method whereby the Company has redirected its exploration efforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies; (iv) continuing progress in our technologies designed to improve drilling performance and the recovery factor; (v) the promotion of the digital transformation of the business to further improve workplace safety and asset integrity.
Phased project development and strict integration between exploration and development have improved the overall project execution and cost efficiency. Finally, all of our projects undergo a thorough HSE assessment leading to the definition of an integrated plan to reduce blow-out and other well and operational risks and costs. Due to those drivers and our estimation that in recent years our discovery costs have been efficient, we believe that the price breakeven of our ongoing projects has decreased over the latest years, thus reducing the risk of a volatile scenario.
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Finally, we plan to seek opportunities for further reductions in our development and operating costs, for example by reducing the downtime at our facilities and other measures.
Gas & Power
We anticipate a weak outlook in the Gas & Power segment due to structural headwinds in the industry. Gas markets across the world are currently affected by oversupplies due to an ongoing reduction in global demand for energy and rising gas supplies driven by increasing volumes of LNG from upstream projects and associated gas in the US. Furthermore, our expectations point to additional volumes of LNG coming on stream in the medium-term based on the final investment decisions of LNG projects made in 2019 for approximately 60 MTPA. Other LNG projects are expected to be sanctioned in 2020. We forecast a weak demand environment in our main reference markets, primarily in Italy and in other European countries, due to an ongoing economic downturn also driven by the impact of the COVID-19 and strong competition from renewables and trends for increasing energy efficiency. Rising LNG supplies have also increased markets liquidity and interconnections, reducing arbitrage opportunities. In our wholesale gas business, these trends are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses, whereby wholesale operators are forced to compete aggressively on pricing in order to limit the financial exposure dictated by the contracts in case of volumes off-taken below the minimum take. We also expect continuing volatility in the spreads between gas spot prices at hubs in the northern Europe, which are the main indexation parameter of our supply contracts, and prices at the spot market in Italy which is the main market to sell our procured gas. In the LNG business, we expect a muted margin environment. In the retail business of gas and power we forecast a strong competitive environment due to lack of entry barriers and a proliferation of operators able to resell gas and power commodities to retail customers and to compete on pricing.
Against this scenario, the Company priority in its Gas & Power business is to gain stable profitability and cash generation based on the following drivers:
(i)
To continuously renegotiate our long-term gas supply contracts to align pricing terms to current market conditions and dynamics as they evolve and to obtain operational flexibilities (volumes, points of delivery, etc)
​
(ii)
To effectively manage our portfolio of assets (supply and sales contracts, their flexibilities and optionality and logistics availability) in order to extract value from market volatility;
​
(iii)
To grow the LNG marketing business leveraging on the integration with the E&P segment with the aim of maximizing the profitability along the entire gas value-chain and of supporting the achievement of the final investment decisions at large gas upstream projects (for example in Mozambique). Based on this approach in 2019 we made the final investment decision for the upgrading of the Bonny LNG project in Nigeria. We plan to accelerate the growth of our contracted supplies of LNG to achieve a robust portfolio of reselling opportunities, and we are targeting 16 million tons of contracted volumes of LNG by 2025, of which 70% deriving from our equity production;
​
(iv)
To boost the profitability of the gas&power retail business, by enhancing the value of the existing customer base against the backdrop of escalating competitive pressures. This will be achieved by selectively growing our customer base, by expanding the offer of new products and services other than the commodity and by continuing innovation in marketing processes including the deployment of digitalization in the acquisition of new customers, a reduction in the cost to serve and effective management of working capital. Our plans targets the expansion of our customer base to 11 million of points of delivery by 2023.
​
We make use of commodity and financial derivatives to hedge us against the risks of different indexation formulas in our gas procurement costs vs. selling prices in relation to contracted sales or highly-probable sales. A number of these derivatives are not accounted as hedges in accordance to IFRS and consequently there recorded through profit and loss and may add a component of volatility to our results of operations. Furthermore, we make use of derivatives to improve margins by leveraging on market volatility and availability of assets to capture arbitrage opportunities (for example the winter vs summer spread, the Italian spot market vs the continental spot markets spread, the spot vs. the Brent indexation spread). Those derivatives are of speculative nature with gains and losses recognized through profit. Our 2019 results were helped by this asset-backed trading leveraging the high market volatility recorded in the year; however it is difficult to make accurate forecast about future trends in this activity.
Based on the above outlined trends and industrial actions, management will seek to enhance profitability in the Company’s gas marketing business over the plan period. Our profitability outlook factors in the expected outcome of ongoing and planned renegotiations of the Company long-term supply
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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.
Refining & Marketing
The outlook of the European refining sector is challenging due to structural headwinds in the industry pressured by overcapacity, high global gasoline stocks, impact of energy efficiency on fuel consumptions and rising competition from cheaper products streams from the Middle East and other areas, where large expansion projects in new refineries or in the upgrading of existing plants are anticipated. Furthermore, fuel demand in Europe is projected to fall due to an ongoing economic slowdown now exacerbated by spread of the pandemic disease COVID-19. Management expects refining margins to remain on a downtrend in the 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. Our priority is to reduce the breakeven margin of Eni refineries in Europe, leveraging the full operability of our refining system, particularly with the restart of the EST high-conversion unit at the Sannazzaro refinery and the recovery of the Bayernoil plant. Other measures include optimization of plant run also in view of maximizing yields of valuable fuels and 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 savings and to improve plant reliability with the support of the deployment of a digital shift in our operations.
In Marketing activities, where we expect a very competitive environment due to lack of entry barrier and of product differentiation, we are planning to retain steady and robust profitability mainly by focusing on innovation of products and services anticipating customer needs, strengthening our line of premium products, as well as efficiency in the marketing and distribution activities. Further value will be extracted by the development of our initiatives in the segment of sustainable mobility and new fuels (for example the recharging for electric vehicles, hydrogen and compressed natural gas) and selling non-fuel products and services.
Chemical
The outlook in the chemical business is challenging due to 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 automotive sector which is one of the main end-markets of the chemicals business. The situation has been made worse by the spread of the COVID-19 and the related global slowdown. Furthermore, growing public sensitivity towards the preservation of the environment and stricter regulation have negatively affected the consumption of single-use plastics and we believe that this trend will strengthen in the future. As the market contracts, the profitability of our chemicals business is expected to be negatively affected by rising competitive pressures from cheaper products stream in the main commoditized segments, like polyethylene, from producers in Middle East and in the 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. Over the last few years, we have 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. The industrial plan identified the following lines of action intended to improve resiliency to the market volatility: (i) strengthening the productive footprint by means of improved plant integration and reliability as well as by rightsizing our captive ethylene capacity vs internal needs for the production of polyethylene; (ii) improving feedstock costs at our steam crackers by introducing a certain 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 growth opportunities and access to competitive feedstock and outlets; and (v) developing our portfolio of green products and products from recycled plastics and renewable feedstock.
Liquidity and leverage
Considering uncertain future trends in the oil markets and in the global economy, the risks of a macroeconomic downturn, oversupplies and price volatility, which have been exacerbated by the steep sell-off in commodity prices in the initial months of 2020 due to a global economic slowdown triggered by fears of pandemic disease and a failed attempt on part of OPEC + to support crude oil prices, management’s priorities in the short-term remain to maximize cash generation from operating activities and to preserve a solid balance sheet. We believe the initiatives implemented by management in recent years intended to increase efficiency in operations, to reduce the time-to-market of reserves and to restructure the mid and downstream businesses together with continuing management’s focus on capital discipline and the monetization of part of our exploration discoveries have improved the Company’s fundamentals and strengthened its capital structure. We believe that in 2019 we have made further progress in enhancing the competitive position of the Company and its resiliency to the market volatility through a number of actions and strategic deals aimed at rebalancing the asset portfolio along the hydrocarbons value chain and at increasing the geographic reach of our operations. Those included the expansion of the geographic presence of our Exploration & Production business in areas like the UAE, Mexico and Norway, this latter due to the acquisition of certain exploration and development E&P properties by our joint-venture Vår Energi, the growth achieved in Egypt and the acquisition of a 20% interest in the Ruwais refining complex in UAE. In future years, we will capitalize on those initiatives and acquisitions to extract the projected returns, while at the same time we expect to continue pursuing financial discipline and sustainable growth to drive profitable production increases and an improved sales volumes mix with the addition of more valuable barrels, reserve replacement and margin expansion at our mid and downstream businesses driven by synergies from integration, the repositioning of the refining and petrochemicals businesses and a growing customer base in the gas retail operations, as well as to reduce climate-related risks by developing our planned initiatives designed to expand the renewable generation capacity, to promote the circular economy and make our operations less carbon-emitting.
The initiatives planned in the next four years are designed to reach a low price of the 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 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 around 45 $/BBL for the Brent crude, at the end of the plan 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 hold its key ratio of net borrowings to equity – leverage – below a preset ceiling through a combination of cost cuts, asset disposals, capital expenditure curtailments and working capital optimizations. At the end of 2019, our leverage stood at 0.24 before the impact of IFRS 16 (0.36 including the effect of IFRS 16). The Company intends to retain a strong control on the evolution of leverage going forward.
Our cash flows from operating activities are 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 cash flow from operations vary by approximately €0.15 billion for each dollar change in Brent prices on a yearly basis compared to our price assumptions for 2020. Currently, oil prices are on a downtrend due to the recent developments occurred until now in 2020 described in the above paragraph
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“Impact of COVID-19 and other current trends in the 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 or in 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 1.11 – 1.21 U.S. dollars per euro in the 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. We note that in the first quarter 2020 the EUR/USD exchange rate was approximately 1.1 and was substantially unchanged year-on-year (it was 1 EUR=1.135 USD in the first quarter of 2019). See “Item 3 – Risk factors”.
Remuneration policy
Management is committed to a progressive remuneration policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. Dividends will be driven by the results that ultimately will be achieved in implementing our strategy and by our ability to achieve the targeted Brent prices at which the Company’s net cash provided from operating activities is able to fund planned capital expenditures and dividend payments. Management is forecasting to increase the dividend expected for fiscal year 2020 to 0.89 €/ share compared to 0.86 €/share for fiscal year 2019, up by 3.5%. The Company had previously announced and launched a share repurchase program as a flexible tool to return shareholders the cash in excess of that committed to achieve the targeted range of leverage, provided that Brent crude oil prices do not fall below a preset level. In 2019, we spent €400 million on share repurchases. Considering the current trends in the oil market, management has resolved to suspend the share repurchase plan for 2020.
The program will be reconsidered when the Brent price for the referenced year, which is the benchmark for decisions relating to the buyback plan activation, is at least equal to 60$/barrel.
In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year.
The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, the impact of COVID-19 on global hydrocarbon demand, the role of OPEC+ at supporting crude oil prices, political instability in Libya and other countries, crude oil and natural gas prices; global demand for oil&gas; trends in natural gas demand in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies designed to tackle the risks of climate change in countries and regions where Eni 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 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 27 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”.
Contractual obligations
The amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

​ | ​ | ​ | Total | ​ | ​ | 2020 | ​ | ​ | 2021 | ​ | ​ | 2022 | ​ | ​ | 2023 | ​ | ​ | 2024 | ​ | ​ | 2025 and thereafter | ​
Total debt | ​ | ​ | ​ | ​ | 32,748 | ​ | ​ | ​ | ​ | ​ | 8,948 | ​ | ​ | ​ | ​ | ​ | 2,338 | ​ | ​ | ​ | ​ | ​ | 1,760 | ​ | ​ | ​ | ​ | ​ | 3,177 | ​ | ​ | ​ | ​ | ​ | 2,209 | ​ | ​ | ​ | ​ | ​ | 14,316 | ​ | ​
Long-term finance debt | ​ | ​ | ​ | ​ | 21,920 | ​ | ​ | ​ | ​ | ​ | 2,908 | ​ | ​ | ​ | ​ | ​ | 1,704 | ​ | ​ | ​ | ​ | ​ | 1,259 | ​ | ​ | ​ | ​ | ​ | 2,743 | ​ | ​ | ​ | ​ | ​ | 1,785 | ​ | ​ | ​ | ​ | ​ | 11,521 | ​ | ​
Short-term finance debt | ​ | ​ | ​ | ​ | 2,452 | ​ | ​ | ​ | ​ | ​ | 2,452 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease liabilities | ​ | ​ | ​ | ​ | 5,622 | ​ | ​ | ​ | ​ | ​ | 884 | ​ | ​ | ​ | ​ | ​ | 632 | ​ | ​ | ​ | ​ | ​ | 487 | ​ | ​ | ​ | ​ | ​ | 434 | ​ | ​ | ​ | ​ | ​ | 424 | ​ | ​ | ​ | ​ | ​ | 2,761 | ​ | ​
Fair value of derivative instruments | ​ | ​ | ​ | ​ | 2,754 | ​ | ​ | ​ | ​ | ​ | 2,704 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​
Interest on finance debt | ​ | ​ | ​ | ​ | 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 | ​ | ​ | ​ | ​ | 926 | ​ | ​ | ​ | ​ | ​ | 926 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Decommissioning liabilities(1) | ​ | ​ | ​ | ​ | 13,474 | ​ | ​ | ​ | ​ | ​ | 331 | ​ | ​ | ​ | ​ | ​ | 325 | ​ | ​ | ​ | ​ | ​ | 163 | ​ | ​ | ​ | ​ | ​ | 179 | ​ | ​ | ​ | ​ | ​ | 424 | ​ | ​ | ​ | ​ | ​ | 12,052 | ​ | ​
Environmental liabilities | ​ | ​ | ​ | ​ | 2,591 | ​ | ​ | ​ | ​ | ​ | 403 | ​ | ​ | ​ | ​ | ​ | 368 | ​ | ​ | ​ | ​ | ​ | 319 | ​ | ​ | ​ | ​ | ​ | 238 | ​ | ​ | ​ | ​ | ​ | 198 | ​ | ​ | ​ | ​ | ​ | 1,065 | ​ | ​
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 | ​ | ​ | ​ | ​ | 2,155 | ​ | ​ | ​ | ​ | ​ | 1,751 | ​ | ​ | ​ | ​ | ​ | 240 | ​ | ​ | ​ | ​ | ​ | 101 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​
Other obligations(4) | ​ | ​ | ​ | ​ | 114 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 106 | ​ | ​
of which: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
– Memorandum of intent relating to Val d’Agri | ​ | ​ | ​ | ​ | 114 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 106 | ​ | ​
TOTAL | ​ | ​ | ​ | ​ | 182,373 | ​ | ​ | ​ | ​ | ​ | 21,488 | ​ | ​ | ​ | ​ | ​ | 13,698 | ​ | ​ | ​ | ​ | ​ | 12,325 | ​ | ​ | ​ | ​ | ​ | 13,699 | ​ | ​ | ​ | ​ | ​ | 13,028 | ​ | ​ | ​ | ​ | ​ | 108,135 | ​ | ​

​
(1)
Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
​
(2)
Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
​
(3)
Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay or ship-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Gas & Power – Natural Gas Purchases” and “Item 3 – Risk Factors – Risks in the G&P business.
​
(4)
In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to provisions for employee benefits (See Note 21 to the Consolidated Financial Statements).
​
The table below summarizes Eni’s capital expenditures commitments for property, plant and equipment as of December 31, 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 | ​ | ​ | 2020 | ​ | ​ | 2021 | ​ | ​ | 2022 | ​ | ​ | 2023 | ​ | ​ | 2024 and subsequent years | ​
​ | ​ | ​ | (€ million) | ​
Committed projects | ​ | ​ | ​ | ​ | 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 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 27 of the Notes on Consolidated Financial Statements”.
Working capital
Management believes that, taking into account unutilized credit facilities, the Company’s liquidity reserves, our credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements.
Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amount due. For a description of how the Company manages the credit risk see “Item 18 – Note 27 of the Notes on Consolidated Financial Statements”.
For information about credit losses in 2019 and the allowance for doubtful accounts see “Item 18 – Note 7 of the Notes on Consolidated Financial Statements”.
Market risk
In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see “Item 18 – Note 27 of the Notes on Consolidated Financial Statements”.
Research and development
For a description of Eni’s research and development operations in 2019, see “Item 4 – Research and development”.
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Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
Directors and Senior Management
The following table lists the Company’s Board of Directors as at December 31, 2019:

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

In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members.
The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on April 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, 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 Domenico 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 April 13, 2017, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.
Three Directors out of nine, including the Chairman, were drawn from the less represented gender, reaching the ratio of one-third of the Directors as provided by the 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 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 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 held the position of
​
1
Temporarily interdicted from the office of Director for facts relating to another issuer with Consob Resolution of June 26, 2019. The “Corte d’Appello” of Rome suspended the provision with effect from November 4, 2019.
​
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Chairman of the Aretè Onlus Foundation. From July 2010 to June 2019 she was President of the University Luiss Guido Carli. She graduated in Business Administration at the Bocconi University in Milan and attended a 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 Council and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala. He is a member of the National Petroleum Council. He joined Eni in 1981 as Oil & Gas field petroleum engineer and then became project manager for the development of North Sea, Libya, Nigeria and Congo. In 1990 he was appointed Head of Reservoir and operating activities for Italy. In 1994, he was appointed Managing Director of Eni’s subsidiary in Congo and in 1998 he became Vice President & Managing Director of Naoc, a subsidiary of Eni in Nigeria. From 2000 to 2001 he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005 he was Executive Vice President for Italy, Africa, Middle East, covering also the role of member of the Board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of the Exploration & Production Division in Eni. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer in the Exploration & Production Division of Eni. From 2010 to 2014 he held the position of Chairman of Eni UK. In 2012, Claudio Descalzi was the first European in the field of Oil&Gas to receive the prestigious “Charles F. Rand Memorial Gold Medal 2012” award from the Society of Petroleum Engineers and the American Institute of Mining Engineers. He is a Visiting Fellow at The University of Oxford. In December 2015 he was made a member of the “Global Board of Advisors of the Council on Foreign Relations”. In December 2016 he was awarded an Honorary Degree in Environmental and Territorial Engineering by the Faculty of Engineering of the University of Rome, Tor Vergata. He graduated in physics in 1979 from the University of Milan.
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 and was visiting professor at European Universities and at Villanova University. He is member of the Strategic Board of the American University of Rome. He is Appeal Court Lawyer. He is President of Board of Statutory Auditors of PS Reti SpA and Sirti SpA. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA and Sequoia Partecipazioni SpA.
Pietro A. Guindani was born in Milan in 1958 and has been Director of Eni since May 2014. Since July 2008 he has been Chairman of the Board of Directors of Vodafone Italia SpA, where between 1995-2008 he was Chief Financial Officer and subsequently Chief Executive Officer. He previously held positions in the Finance Departments of Montedison and Olivetti and started his career in Citibank after graduating in Business at the Bocconi University in Milan. He is currently also a Board member of the Italian Institute of Technology and Cefriel-Polytechnic of Milan. He is Board Member of Confindustria and Member of the Executive Board of Confindustria Digitale; he is President of Asstel-Assotelecomunicazioni and Vice President responsible for Universities, Innovation and Human Capital of Assolombarda. He was also Director of Société Française du Radiotéléphone – SFR S.A. (2008-2011), Pirelli & C. SpA (2011-2014), Carraro SpA (2009-2012), Sorin SpA (2009-2012), Finecobank SpA (2014-2017) and Salini-Impregilo SpA (2012-2018).
Karina A. Litvack was born in Montreal in 1962 and has been a Director in Eni since May 2014. She is currently a member of the Advisory Board in Bridges Ventures LLC, a member of Board of Business for Social Responsibility, a member of the Advisory Council for Transparency International 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 Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012). From 2003 to 2014 she was a member of the CEO Sustainability Advisory Panel of Lafarge SA; from January 2008 to December 2010 she was a member of the CEO Sustainability Advisory Panel of Veolia SA; from January to December 2010 she was a member of the CEO Sustainability Advisory Panel of ExxonMobil and Ipieca; from January 2010 to November 2017 she was a member of the CEO Sustainability Advisory Panel in SAP AG. From January 2015 to May 2019 she was a member of the Board of Yachad. She graduated in Political Economy at the University of Toronto and in Finance and International Business from Columbia University Graduate School of Business.
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Alessandro Lorenzi was born in Turin in 1948 and has been Director of Eni since May 2011. He is Director and Chairman of the Internal Control Committee of Ersel SIM SpA and of Banca Albertini SpA. He began his career at SAIAG SpA in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined GFT Group where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Operating Officer and was subsequently Director of Ersel SIM SpA until June 2000. In 2000 he became Executive Officer of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of Coin Group and in 2006 he became Chief Corporate Officer at Lavazza SpA, becoming Board member from 2008 to June 2011. From July 2011 to September 2017 he was Chairman of Società Metropolitana Acque Torino SpA. From June 2016 to April 2019 he was Director of Mutti SpA.
Diva Moriani was born in Arezzo in 1968 and has been a Director in Eni since May 2014. She is currently Executive Vice Chairman of Intek Group SpA, Vice Chairman of KME AG, a German holding company of KME Group, Director of KME Srl, Member of the Supervisory Board of KME Germany GmbH and Director of Assicurazioni Generali SpA, Moncler SpA, Dynamo Academy, Dynamo Foundation and Associazione Dynamo. From 2007 to 2012 she was CEO of I2 Capital Partners, a private equity fund sponsored by Intek Group SpA, with an investment strategy focused on “Special Situations” and from 2014 to 2017 CEO of KME AG. She graduated in Economics at the University of Florence.
Fabrizio Pagani was born in Pisa in 1967 and has been a Director in Eni since May 2014. He is Head of Economics and Capital Market Strategy of Muzinich & Co. and Board member of Save SpA, Banca Finint SpA. From 2014 to 2018 he has been Head of the Office of the Minister of Economy and Finance. He was Deputy Director of the International Training Programme for Conflict Management at the High School S. Anna 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 Office from 2006 to 2008, board member of SACE SpA from 2007 to 2008, Political Counsellor of the OECD General Secretary from 2009 to 2011, Director of the G8/G20 Office at the OECD from 2011 to 2013 and Senior Economic Counsellor to the Prime Minister and G20 Sherpa from 2013 to 2014. He was a NATO Fellow and was a visiting scholar at Columbia University, New York. He graduated in International Studies at the Scuola Superiore Sant’Anna, Pisa, and has a Master degree from the European University Institute, Florence.
Domenico Livio Trombone was born in Potenza in 1960 and has been Director of Eni since April 2017. He is a certified chartered accountant and a certified public auditor. He is partner of Studio Trombone Dottori Commercialisti e Associati. He is currently Chairman of the Board of Directors of Consorzio Cooperative Costruzioni-CCC, of Focus Investments SpA, of Società Gestione Crediti Delta SpA and of Prelios Credit Servicing SpA. He is, among the others, Director of International World Group Srl. Furthermore, he is Chief Executive Officer of Atrikè SpA and Sole Director of FINCCC SpA and of Focus Investment International Srl. He is also 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 the merger of the Company in FonSai SpA, he was Chairman of the Board of Statutory Auditors in Unipol Assicurazioni SpA. Until December 2008 he was Director in Banca Popolare del Materano SpA and BNT Consulting
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SpA. From April 2010 to 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 Aeroporto Guglielmo Marconi di Bologna SpA. From April 2013 to July 2019 he was Chairman of the Board of Statutory Auditors in Unipol Banca SpA. He graduated in Economics from the University of Modena.
Senior Management
The table below sets forth the composition of Eni’s Senior Management as at December 31, 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 | ​ | ​ | 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 Gas & LNG Marketing and Power Officer, the Chief Refining & Marketing Officer, the Chief Financial Officer, the Chief Services & Stakeholder Relations Officer, Chief Digital Officer, the Senior Executive Vice President Legal Affairs, the Senior Executive Vice President Internal Audit, the Senior Executive Vice President Corporate Affairs and Governance, the Commercial Negotiations Senior Executive Vice President as well as the Executive Vice President Energy Solutions, the Executive Vice President External Communication, the Executive Vice President International Affairs, the Executive Vice President Integrated Compliance, the Executive Vice President Integrated Risk
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Management, 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.
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 Internal Audit 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 with honours in geology in 1983 from the University of Florence. In 1984 he joined Eni’s geophysics division, working first as a researcher in the development of 3D seismic prospecting technology and subsequently as a manager of 3D seismic prospecting programmes, specialising in seismic-stratigraphy. In 1994 he was appointed manager of seismic-stratigraphy applications and in 1999 he increased the technical-managerial scope of his activities becoming manager of geological and geophysical services in Eni.
At the end of 2001, his career took a new international turn holding positions of increasing managerial complexity over a period of eight years, starting in Norway where he was Technical Director and Deputy Managing Director at Norsk Agip in Norway. In 2003 he was appointed Managing Director of Eni Indonesia and in 2006 he moved to Egypt as General Manager and Managing Director, a position he also held at Eni Angola in 2007. In 2009 he returned to Eni’s headquarters as Senior Vice Chairman of Global Exploration. He was appointed Executive Vice President of Exploration and Unconventional at the beginning of 2010. Since July 1, 2014, he has been Eni’s Chief Exploration Officer.
Stefano Maione was born in Avellino in1963. He has a degree in Civil Engineering from the University of Bologna. Stefano Maione was hired by Agip S.p.A. in 1991 as a Field Engineer, gaining significant experience in dynamic modelling of oil fields and contributing to studies of fields in Egypt and China. In 1994 he transferred to Agip Récherches Congo S.A., again as a Field Engineer, where he developed his skills and experience in oil fields and eventually reached the position of Head of Field Operations. Returning to headquarters in early 1999, he occupied increasingly important roles in technical services, finally becoming District Head of Production for Italy. From 2003 to 2006 he gained significant experience as a Development Project Manager in Egypt, Libya, Iran and Italy. In 2007, he was elected as a member of the Management Committee that runs Mellitah Gas B.V. Libyan Branch, 50% of which is controlled by Eni and 50% by the National Oil Corporation (NOC). In January 2009, he was appointed Managing Director of Eni Iran B.V. and in 2010 returned to Libya as Managing Director of Eni North Africa B.V. Returning to headquarters again in January 2012, he was appointed Senior Vice President of Development Projects and Deputy Chairman of the Development Department. He was put in charge of the Mozambique Programme in 2013 after Eni discovered super-giant gas fields in the country, becoming Executive Vice President for it in 2015. He was appointed Chief Development, Operations & Technology Officer on July 1, 2019.
Claudio Granata was born in Rome in 1960. Graduating with a degree in economics, he joined the Eni group in 1983. From 1983 to 1994 worked as a labour market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999 he continued his experience with Eni Corporate as an expert in industrial relations. In 2000 he was made responsible for Staff and Organisation within Eni Servizi Amministrativi, a company that was set up to centralise Eni’s administrative activities.
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2
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, restructuring the management of staff by geographical area and in 2003 he took on the role of Business HR for Eni Corporate, ensuring support for departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), which was characterised by the mergers of Snam and AgipPetroli and the restructuring of staff organisation. In the same year he was also appointed head of Human Resources and Organisation of SOFID (Eni’s financial services company).
In 2006 he was appointed Human Resources Director of the E&P Division, where he oversaw the planning, management, development and compensation processes for human resources and organization activities. He also collaborated with the top management in the reorganisation of macro processes for the division and promoted change management initiatives. He became a board member of Eni International Resources Ltd in 2006 and was Chairman of the board of Eni International Resources Ltd from 2012 to 2013. From 2012 to March 2015 he was a board member of Eni UK ltd.
In 2013 he was appointed Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, responsible for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in “time to market” and efficiency. From 2014 to May 2016, he was a member of the Board of Directors of the Eni Foundation. He has been Chairman of the board of Eni Corporate University since November 2014. He has been Chief Services & Stakeholder Relations Officer in Eni since 1 July 2014.
Cristian Signoretto was 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 the Italian Army. In 2000 he was awarded with a scholarship as a Ph.D. candidate at the Department of Energy of the Politecnico di Milano, where he was involved in research projects and teaching activities. In 2001 he 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 Oil&Gas and Banking&Insurance sectors. In 2007 he joined Eni in the Office of the CEO supporting the Top Management for corporate strategy and group-level projects. In 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 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 Trading & Shipping SpA (the fully owned subsidiary of Eni SpA in charge of all the trading operations within the group). He is a member of the Board of Directors in Union Fenosa Gas (Spain), a JV between Eni and 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 Gas, Lng and Power activities of Eni Trading & Shipping SpA.
Massimo Mondazzi was born in Monza in 1963. He graduated in Economics and 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 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 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 Ricci was born in Casale Monferrato in 1958. 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. He has been President of Confindustria Energia since July 2017 and President of AIDIC (Italian Association Of Chemical Engineering) since 2018. He has a degree in chemical engineering. He was appointed as Chief Refining & Marketing Officer on September 12, 2016.
Alessandro Puliti was born in Florence in 1963. He joined Agip SpA’s Reservoir Department in 1990 as a Reservoir Geologist and was involved in the study of reservoirs in Africa and Italy. His international professional career started in 1998, when he moved to Aberdeen to fill the position of Assistant Operated Asset Manager of Agip UK, where he gained operational experience in complex contexts. After returning to Italy in 2002, he was appointed Reservoir and Drilling and Completion Manager in the Val D’Agri project. In 2003 he was posted to Egypt as IEOC’s Development and Operations Manager and subsequently covered increasingly more complex managerial roles, first as General Manager and Managing Director of Petrobel and later as General Manager of IEOC. In 2009 he moved back to Italy to take on the role of Regional Management Russia and North Europe Vice President. In 2010, he moved to Stavanger, where he held the dual role of Eni Norge’s Managing Director and Regional Management Russia and North Europe Vice President. In 2012 he returned to the HQ Operations Department, first as Senior Vice President Petroleum Engineering, Production and Maintenance and then as Senior Vice President Drilling and Completion and Deputy Operations. In October 2015 he was appointed Reservoir & Development Projects Executive Vice President. He graduated with Honors in Geology from the University of Milan and earned the MEDEA Master in Energy and Environmental Management and Economics from “Scuola Mattei”. He is the author of several papers on reservoirs and drilling presented at international conferences. He was Chief Development, Operations & Technology Officer from 2018 to 2019. He was appointed Chief Upstream Officer on July 1, 2019.
Marco Bollini was 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) 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 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 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. He was a Board Member of Eni Foundation. From 2016 to 2018 he was Senior Executive Vice President Legal Affairs of Eni. He was nominated Senior Executive Vice President Commercial Negotiations on 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 of the Watch Structure of Eni SpA and Secretary of the Control and Risk Committee of Eni SpA. He holds international qualifications as well, in detail: Certified Internal Auditor (CIA), Certified Fraud Examiner (CFE), Certified Risk Management Assurance (CRMA). He is currently a Board Member of AiiA (Italian Internal Auditors Association). He is Eni’s Senior Executive Vice President Internal Audit.
Roberto Ulissi was born in Rome in 1962. He is a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance head of the Banking and Financial System and Legal Affairs Department. He was a Board member of Telecom Italia (and Chairman of the Audit Committee), Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He is a board member and Vice Chairman of Banor SIM. He was also a member of numerous Italian and European committees representing the Ministry of the Economy including, at a national level, the Commission for the Reform of Corporate Law (Commission “Vietti”) and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 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 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. He is a professional journalist working in the media world for 28 years before joining Eni in 2015. He has gained extensive experience on foreign policy and digital communications, particularly in Europe and America. Between 2009 and 2015 he was Managing Editor and Digital Editor at “La Stampa”. He was a key member of the team that worked on the transformation of a traditional newspaper to an integrated digital news organization, creating an innovative “concentric circles” multiplatform newsroom. He was one of the co-founders of  “Europa” a partnership between La Stampa, Le Monde, El País, The Guardian, Gazeta Wyborcza and Suddeutsche Zeitung. Before joining “La Stampa”, he was U.S. correspondent for the Italian news agency ANSA between 2000 and 2009, covering every aspect of American life for the Italian media. Among other things, he covered the Bush-Gore electoral race for the White House in 2000, the first international Al Qaeda trial in Manhattan, the September 11 attack on America, the wars in Afghanistan, and Iraq and the 2004 and 2008 presidential campaigns. He has visited and reported on the Guantanamo detention camp at the U.S. Navy Guantanamo Bay base in Cuba. He won the Saint-Vincent Award for Journalism for a series of reports on the death penalty in the USA. He covered the 2008 financial crisis, and he reported extensively on the American digital, energy and automobile industries.
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He holds an Associate of Arts degree in History from American Public University. His latest book is “L’Ultima Notizia” (with Massimo Gaggi, Rizzoli 2010), an essay on digital transformation in the media business. He is an external lecturer in the Masters in Journalism in ALMED-Università Cattolica del Sacro Cuore, Milan. He is a Visiting Fellow at the University of Oxford. In 2017 he was appointed as a Director of Agi SpA and Eni Gas e Luce. Since February 2015, he has been External Communication Executive Vice President.
Luca Cosentino was born in Venice in 1961. He graduated cum laude with a degree in geology in 1985 from the University of Padua and joined Eni in 1986. He spent the first years of his professional life in the Reservoir Department, within the reservoir modeling group. Between 1992 and 1996, he worked in different operational positions in Italy and abroad in the reservoir sector. From 1996 to 2003, he worked as Project Manager with IFP (Institut Français du Petrol, France), in Venezuela and in the Persian Gulf. In this period, he also taught at the IFP School and published several technical papers, including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to 2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From 2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed Senior Vice President Non Operated Business Performance and Stranded Resources Valorization. Since November 1, 2015, he has been Executive Vice President Energy Solutions.
Lapo Pistelli was born in Florence in 1964. Having graduated with honors in 1988 in International Law at the Political Science faculty “Cesare Alfieri” at the University of Florence, he started working at a research center, while serving for two mandates in the local administration of Florence. He was member of the Italian Parliament from 1996 to 2015 (1996/2004 and 2008/2015), and also member of the European Parliament (2004/2008). As an Italian MP, he was member of the Committees on Constitutional Affairs, European Affairs and on International Affairs. As a MEP in Brussels, he worked at the Economic and Monetary Affairs and Foreign Affairs Committees. During this period, he has also been the President of the EU-South Africa Delegation and a member of the Italian Delegation to the OSCE, where he conducted several monitoring missions in transitional democracies.
He served as Deputy Minister of Foreign Affairs and International Cooperation of Italy from 2013 to 2015. He resigned from all his institutional and political roles in July 2015, when he entered Eni as Senior Vice President for Strategic Analysis for Business Development Support. He taught and lectured at the University of Florence, the Overseas Studies Program of Stanford University and many others international academic institutions. He regularly contributed to many European and American think tanks and research centers specialized in international relations. Among other things, he’s a member of the Council of Chatham house, member of the board of the European Council on Foreign Relations (ECFR) and of the Istituto Affari Internazionali (IAI), member of the WE – World of Energy editorial committee and of the EastWest scientific committee. He’s Vice Chairman of OME (Observatoire Mediterranéen de l’Energie) and member of the IRENA’s (International Renewable Energy Agency) Global Commission on the Geopolitics of Energy Transformation. As a journalist, he regularly publishes in various newspapers issues related to European and international affairs and on specialized magazines, such as Limes. He authored several publications: in his last book, Il nuovo sogno arabo – Dopo le rivoluzioni, Feltrinelli 2012, he analyses the origin and challenges of the ‘Arab Spring’ and its impact on the geo-political scenario in North Africa and the Middle East. He was appointed Executive Vice President of International Affairs on April 14, 2017.
Luca Franceschini was born in Milan in 1966. He is a graduate in Law from the University of Milan and is registered to practice law on the special list of the Ordine degli Avvocati (the Italian Bar Association) in Rome. He first joined Eni in 1991 in the legal department of Agip 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 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. From 2015 to 2016 he was 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 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
The information concerning compensation is provided in the remuneration report prepared in accordance to Italian listing standards, which is incorporated herein by reference.
See the Exhibit 15. a (i).
As of December 31, 2019, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief Executive Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the 2019 period, filled said roles, even if only for a fraction of the year), was €1,427 thousand.

Name | ​ | ​ | ​ | ​ | ​ | (€ thousand) | ​
Descalzi Claudio | ​ | ​ | Chief Executive Officer | ​ | ​ | ​ | ​ | 371 | ​ | ​
Senior managers(a) | ​ | ​ | ​ | ​ | 1,056 | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,427 | ​ | ​

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(a)
No. 20 managers.
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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”), lastly amended on July 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.
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3
The information contained in this chapter is updated to December 31, 2019 and for specific aspects, expressly indicated, up to the date of approval of this Report.
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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 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 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 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 April 13, 2017, the Board reserved to itself the strategic, operational and organizational powers briefly described below:
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defines the system and rules of Corporate Governance for the Company and the Group;
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establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets;
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expresses the general criteria for determining the maximum number of offices that a Director may hold in other companies;
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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;
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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;
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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;
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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;
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•
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;
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•
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;
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receives a report from the Board’s internal committees on at least a semi-annual basis;
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assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts;
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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 Board4, as well as transactions in which the CEO has an interest;
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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;
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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;
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•
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;
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resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries;
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formulates the proposals to present to the Shareholders’ Meeting; and
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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.
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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 April 13, 2017 and, after an investigation by the Nomination Committee, lastly at its meeting of February 27, 2020, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Trombone satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and 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
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, and between Eni and companies of the KME Group, companies subject to significant influence, also indirectly, by Director Moriani, are not significant for the purpose of assessing the independence of these Directors, having regard to the nature and the amounts of these relationships. The relationships were evaluated on the basis of statements made by the Directors and other information available to the Company, and taking into account that – due to the nature of the companies mentioned above – transactions between these
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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 and, lastly, on April 4, 2017.
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5
Although the Chairman of the Board of Directors is a non-executive Director, the Code treats her as a significant representative of the Company (Application Criterion 3.C.2 of the Corporate Governance Code).
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companies and Eni were subject to related parties’ transactions regulation and reported to the Company’s body. The Board of Directors also confirmed the independence of Director Lorenzi, who the next May 5, 2020 will complete the ninth year of office as Director, taking into account that his office as Director will expire on May 13, 2020.
The Board of Statutory Auditors always verified the proper application of criteria and procedures adopted by the Board of Directors in assessing the independence of its members.
The independence criteria may be not equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company.
Board Committees
The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the Remuneration Committee; (c) the Nomination Committee; and (d) the Sustainability and Scenarios Committee. Committees under letters (a), (b) and (c) are recommended by the Corporate Governance Code. 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 Remuneration Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their 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, Remuneration Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on April 13, 2017.
Remuneration Committee
Members: Andrea Gemma (Chairman), Pietro A. Guindani, Alessandro Lorenzi, Diva Moriani.
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6
Rules of the Remuneration Committee establish that “no Director and, in particular, no Director with delegated powers may take part in meetings of the Committee during which Board proposals regarding his remuneration are being discussed, unless are deemed proposals on all the members of the Committees established within the Board of Directors.”
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The 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. The Committee’s rules require that at least one of its members possess adequate knowledge and experience of financial matters or remuneration policies, as assessed by the Board at the time of his or her appointment.
Established by the Board of Directors for the first time in 1996, in accordance with the By-laws, the Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee:
a)
submits the Remuneration Report and in particular the Remuneration Policy for Directors and Managers with strategic responsibilities to the Board of Directors for approval, prior to its presentation at the Shareholders’ Meeting called to approve the year’s financial statements, in accordance with the time limits set by applicable law;
​
b)
periodically evaluates the adequacy, overall consistency and effective implementation of the Policy, formulating proposals, as appropriate, for approval by the Board of Directors;
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c)
presents proposals for the remuneration of the Chairman and the Chief Executive Officer, including the various components of compensation and non monetary benefits;
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d)
presents proposals for the remuneration of Board Committee members;
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e)
having examined the Chief Executive Officer’s indication, proposes general criteria for the compensation of Managers with strategic responsibilities, the annual and Long-Term incentive plans, including equity-based ones, sets performance objectives and assesses performance against them, in connection with the determination of the variable portion of the remuneration for Directors with delegated powers and with the implementation of the approved incentive plans;
​
f)
monitors execution of decisions taken by the Board;
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g)
reports at the first available meeting of the Board of Directors through the Committee Chairman on the most significant issues addressed by the Committee during the meetings. It also reports to the Board on its activities at least every six months and no later than the time limit for the approval of the Annual Report and the Interim Report at June 30, at the Board meeting designated by the Chairman of the Board of Directors.
​
Furthermore, in exercising its functions, the Committee may issue opinions as required by Company procedures in relation to operations with related parties, in accordance with specified procedures.
The Committee performs its duties pursuant to an annual plan. In carrying out its duties, the Committee may access the information and 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, in accordance with the recommendations in the Corporate Governance Code and with the goal of establishing and appropriate channel for dialogue with shareholders and investors.
During 2019, the Remuneration Committee met ten times, with an average attendance of 100% of its members and an average duration of 2 hours and 10 minutes. At least one member of the Board of Statutory Auditors participated in each meeting, whit constant participation of 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 evaluation of Remuneration Policy implemented in 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 implementing the Short- and Long-Term variable incentive plans, using a predetermined gap analysis method approved by the Committee in order to neutralize the positive or negative impact of exogenous factors and enable the objective assessment of the performance achieved;
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iii.
the definition of 2019 performance targets relevant to the variable incentive plans;
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iv.
the finalization of the proposal for the implementation of the annual variable incentive system for the Chief Executive Officer and General Manager;
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v.
the review of the 2019 Eni Remuneration Report;
​
vi.
the examination of the outcome of the engagement activities held with leading institutional investors and proxy advisors in view of the general meeting, in order to maximize shareholder consensus on the 2019 Remuneration 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, which were performed with the support of a leading consulting firm;
​
viii.
the start of a further extensive dialogue with a broad range of investors in the run-up to the annual meeting, with a view to promoting participation and support for the Eni Remuneration Policy.
​
In the second half of the year, the Committee examined the 2019 Shareholders’ Meeting vote results, with regard to the Eni Remuneration Report, compared to the results of the major Italian and European listed companies and of the Eni’s Peer Group.
As regards further relevant activities carried out, the Committee:
i
finalized the proposal (2019 grant) for the implementation of the 2017-2019 Long Term Share Incentive Plane for the Chief Executive Officer and General Manager and for key management personnel;
​
ii
finalized the proposal on the exercise of the option to activate the non-compete agreement entered into with the Chief Executive Officer and General Manager, as set out in the 2019 Remuneration Report;
​
iii
started to examine the proposal for the Long-Term Share Incentive Plan 2020-2022 for key management personnel;
​
iv
examined the updating of remuneration benchmark studies and started to review the proposals for Remuneration Policy Guidelines for the 2020-2023 term;
​
v
examined the general criteria for defining the 2020 engagement plan by conducting a preliminary analysis and segmentation of the institutional investors that attended the 2019 Shareholders’ Meeting;
​
vi
monitored developments in the legislative framework and market standards concerning the reporting of remuneration-related information, with a specific focus on changes introduced with Legislative Decree no. 49/2019, transposing the SRD II, including a binding vote of the Shareholders’ Meeting on the Remuneration policy described in the first section of the Remuneration Report, and an advisory vote on the second section, concerning remuneration paid during the reporting period.
​
The Committee scheduled four meetings for the first four months of 2020, three of which had already been held as of the date of approval of this Report.
Control and Risk Committee
Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Karina Litvack and Diva 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 Directors7 who possess the necessary expertise consistent with the duties they are required to perform8.
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 on the adoption and amendment of the rules on the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or Statutory Auditor holds a personal interest or an interest on behalf of a third party, while performing additional duties assigned it by the Board of Directors, including examining and issuing an evaluation on specific types of transactions, except for those relating to compensation; and c) gives an opinion on the fundamental guidelines of the Regulatory System, the regulatory instruments to be approved by the Board of Directors, their amendment or update and, upon request by the CEO, on specific aspects in relation to the instruments implementing the fundamental guidelines.
In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the Officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the Consolidated Financial Statements, prior to their approval by the Board of Directors; b) examines and evaluates Reports prepared by the CFO/Officer in charge of preparing financial reports through which it shall give its opinion to the Board of Directors on the appropriateness of the powers and resources assigned to the Officer himself and on the proper application of accounting and administrative procedures, enabling the Board to exercise its legally mandated supervision tasks; c) at the request of the Board, it supports, with adequate preliminary activities, the Board of Directors’ assessments and resolutions on the management of risks arising from detrimental facts of which the Board may have become aware and d) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and
​
7
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.
​
8
The Governance system put in place by Eni establishes that at least two members of the Committee – and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.
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oversees 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.
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 the CEO and/or the Chairman of the Company and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, for crimes against the Public Administration and/or corporate crimes and/ or environmental crimes, related to their mandate and their scope of responsibility.
The composition and appointment, as well as duties and operational procedures of the Committee, are governed by rules approved by the Board of Directors lastly on May 9, 2017 available to the public at the Company’s website.
Nomination Committee
Members: Diva Moriani (Chairman), Andrea Gemma, Fabrizio Pagani and 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. More specifically, the Committee:
a)
assists the Board of Directors in formulating any criteria for the appointment of those persons indicated in letter b) below, and of the members of the other boards and bodies of Eni’s subsidiaries and associated companies;
​
b)
provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment falls under the Board’s responsibility and oversees the associated succession plans. Where possible and appropriate, and with due regard to the shareholding structure, the Committee proposes the CEO succession plan to the Board of Directors;
​
c)
acting upon a proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession planning for the Company’s managers with strategic responsibilities;
​
d)
proposes candidates to serve as Directors to the Board of Directors in the event one or more positions need to be filled during the course of the financial year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements regarding the minimum number of independent Directors and the percentage reserved for the less represented gender;
​
e)
proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, taking account of any recommendations received from shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders;
​
f)
oversees the annual self-assessment program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and deals with the preliminary activity for appointing an external consultant for such self-assessment. On the basis of the results of the self-assessment, the Committee provides its opinions to the Board of Directors regarding the size and composition of the Board or its Committees, as well as, the skills and managerial and professional qualifications it feels should be represented within the same Board and Committees so that the Board itself can give its opinion to the shareholders prior to the appointment of the new Board;
​
g)
proposes to the Board of Directors the slate of candidates for the position of Director to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3, first period, of the By-laws;
​
h)
in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of positions of Director or Statutory Auditor that a Company Director may hold and performs the preliminary activity for the associated periodic checks and evaluations for submission to the Board;
​
i)
periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible;
​
j)
provides its opinion to the Board of Directors on any activities carried out by the Directors in competition with the Company;
​
k)
through the Chairman of the Committee, informs the Board of Directors on the main issues examined by the Committee thereof during the first available meeting of the Board; furthermore, the Committee reports to the Board of Directors, at least once every six months and no later than the deadline for the approval of the annual and semi-annual financial report, on the activity carried out as well as on the adequacy of the appointment system, at the Board meeting indicated by the Chairman of the Board of Directors.
​
The preliminary examination of corporate affairs or governance issues is carried out jointly with the Senior Executive Vice President Corporate Affairs and Governance who, in this case, participates in the Committee meetings.
The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors lastly on May 9, 2017, 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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The Sustainability and Scenarios Committee is made up of non-executive Directors, a majority of whom are independent.
The Sustainability and Scenarios Committee provides recommendations and advice to the Board of Directors on scenarios and sustainability, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: health, well-being and safety of people and communities; respect and the protection of rights, particularly of the human rights; local development; access to energy, energy sustainability and climate change; environment and efficient use of resources; integrity and transparency; and innovation.
Board of Statutory Auditors
The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of April 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, 2019.

Name | ​ | ​ | Position | ​ | ​ | Year first appointed to Board of Statutory Auditors | ​
Rosalba Casiraghi | ​ | ​ | Chairman | ​ | ​ | 2017 | ​
Enrico Maria Bignami | ​ | ​ | Auditor | ​ | ​ | 2017 | ​
Paola Camagni | ​ | ​ | Auditor | ​ | ​ | 2014 | ​
Andrea Parolini | ​ | ​ | Auditor | ​ | ​ | 2017 | ​
Marco Seracini | ​ | ​ | Auditor | ​ | ​ | 2014 | ​
Stefania Bettoni | ​ | ​ | Alternate | ​ | ​ | 2014 | ​
Claudia Mezzabotta | ​ | ​ | Alternate | ​ | ​ | 2017 | ​

Paola Camagni, Andrea Parolini, Marco Seracini and Stefania Bettoni (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; Rosalba Casiraghi (Chairman), Enrico Maria Bignami and Claudia Mezzabotta (Alternate) were candidates listed in the slate presented by non-controlling shareholders.
The Auditors are appointed by means of a slate voting system: the lists are presented by shareholders representing at least 0.5% of the share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders.
In accordance with the provisions designed to ensure gender balance, two Statutory Auditors were drawn from the less represented gender.
The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. Regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of Financial Statements and internal control processes. In addition, the Board of Statutory Auditors, acting as the Internal Control and Financial Auditing Committee pursuant to Legislative Decree no. 39/2010 (Consolidate Law on Statutory Audits of annual accounts and consolidated accounts), must satisfy the requirement imposed by Art. 19 of that law, providing that “the members of the internal control and financial auditing committee, as a body, are competent in the sector in which the company being audited operates”.
Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters within the scope of the Board’s Authority, the adequacy of the internal control system and the
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administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.
In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, in its role as the “internal control and financial auditing committee” the Board of Statutory Auditors: a) informs the Board of Directors of the conclusion of the statutory audit and transmits to the Board the “additional report” of the audit firm adding proper evaluation if deemed necessary; b) oversees the financial reporting process and presents recommendations to ensure its integrity; c) controls the effectiveness of internal quality control system and Risk Management, the effectiveness of internal audit, with reference to the financial reporting process, without violating its independence; d) oversees the statutory audit of annual accounts and consolidated accounts, also considering results of quality control of the audit activity performed by the public authority responsible for regulating the Italian financial markets; e) verifies and monitors the independence of the audit Firm with particular reference to non-audit services; f) is responsible of the procedure to select the audit Firm, making a recommendation to the Shareholders’ Meeting for the appointment of the audit Firm.
The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee” are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “U.S. Sarbanes-Oxley Act” (discussed in greater detail below).
In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements.
On March 22, 2005, the Board of Directors, electing the exemption granted by the 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, the Board of Statutory Auditors approved the internal rules, later updated, concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC include:
•
evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor;
​
•
overseeing the work of the external Auditor engaged to audit the accounts or perform other audit, review or certification services;
​
•
examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;
​
•
making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting.
​
In addition the Board of statutory auditor:
•
approves the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;
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•
examines reports from the CEO and the CFO 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 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 September 19, 2019 approved the updating of Model 231.
During 2019, in accordance with Eni Watch Structure, Eni has conducted a project to revise and transform the existing Code of Ethics, 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 which is one of the pillars of 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 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.
Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of May 10, 2018 approved the engagement of PricewaterhouseCoopers SpA to perform the external statutory audit of the accounts of Eni SpA and the audit of the internal control system over financial reporting, pursuant to US law, for the 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 has been carried out by the Magistrate of the Court of Auditors, Adolfo Teobaldo De Girolamo, appointed by the Presidential Council of the Court of Auditors on December 22, 2014, until February 28, 2019.
As from March 1, 2019 the task is performed by the Magistrate of the Court of Auditors Manuela Arrigucci, on the basis of the resolution approved 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, 2019, Eni had a total of 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 134 employees working 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

​ | ​ | ​ | 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, 2017, 2018 and 2019 in Italy and outside Italy:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | 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, 2020, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 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 | ​ | ​ | ​ | ​ | 87,010(1) | ​ | ​
Claudio Descalzi | ​ | ​ | CEO | ​ | ​ | ​ | ​ | 68,755(2) | ​ | ​
Board of | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Statutory Auditors | ​ | ​ | ​ | ​ | none | ​ | ​
Senior Managers | ​ | ​ | ​ | ​ | 142,713(3) | ​ | ​

​
(1)
Of which No. 597 shares held under Asset Management, No. 7,143 shares held under Asset Management jointly a third person, and No. 45,000 shares held in bare ownership jointly with a third person.
​
(2)
Updated as of March 19, 2020.
​
(3)
Of which No. 6,890 shares owned by 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, 2020, the total amount of Eni’s voting securities owned, either directly or indirectly, by persons that have notified that their holding exceeds the threshold of 3%1 pursuant to Article 120 of the Legislative Decree No. 58/1998 and to the Consob Regulation No. 11971/1999 was:

Title of class | ​ | ​ | Number of shares owned | ​ | ​ | Percent of class | ​
Ministry of Economy and Finance | ​ | ​ | ​ | ​ | 157,552,137 | ​ | ​ | ​ | ​ | ​ | 4.34 | ​ | ​
Cassa Depositi e Prestiti SpA | ​ | ​ | ​ | ​ | 936,179,478 | ​ | ​ | ​ | ​ | ​ | 25.76 | ​ | ​

As of February 28, 2020, the percentage of Eni’s treasury shares was equal to 1.70% of the share capital2.
In relation to the Italian legislation governing the special powers of the Italian State see “Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)”.
As of March 10, 2020, there were 33,623,608 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 1.9% of Eni’s share capital. See “Item 9 – The offer and the listing”.
Related parties transactions
In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with associates, joint ventures, joint operations or other affiliates, as well as other companies owned or controlled by the Italian Government. All such transactions are conducted on an arm’s length basis and in the interest of 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 36 of the Notes on Consolidated Financial Statements”.
​
(1)
Major holdings pursuant to Article 120 of the Legislative Decree No. 58/1998 are updated also on the basis of communication made by intermediaries pursuant to Article 83-novies of the Legislative Decree No. 58/1998 in order to exercise the corporate rights.
​
(2)
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 these legal proceedings will likely not have a material adverse effect on Eni’s Consolidated Financial Statements.
For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see “Item 18 – Note 27 of the Notes on Consolidated Financial Statements”.
Dividends
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 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 oil price and exchange rate assumptions adopted by management and other planning and scenario assumptions described in “Item 5 – Management’s expectations of operations”. The parent company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. For further information on the Company’s dividend policy see “Item 5 – Management’s expectations of operations.”
The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. For further details see “Item 3 – Risk factors”.
At the General Shareholders’ Meeting scheduled on May 13, 2020, management intends to propose the distribution of a dividend of €0.86 per share for fiscal year 2019, of which €0.43 already paid as interim dividend in September 2019.
Total cash outlay for the 2019 final dividend is expected at approximately €1.5 billion to be paid in 2020 (whereas €1.5 billion were distributed in September 2019) if the General Shareholders’ Meeting approves the annual dividend.
Significant changes
See “Item 5 – Recent developments and Management’s expectations of operations” for a discussion of significant subsequent business developments and transactions occurred after the closing date up to the latest practicable date.
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Item 9. THE OFFER AND THE LISTING
Offer and listing details
Since 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 March 10, 2020, there were 33,623,608 ADRs outstanding, representing 67,247,216 ordinary shares or approximately 1.9% of all Eni’s shares outstanding, held by 92 holders of record (including the Depository Trust Company) in the United States, 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 Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian Stock Exchange. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The constituents of the FTSE MIB are selected based on market capitalization of free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free float and foreign ownership limits. FTSE MIB is the principal indicator used to track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are a component of the FTSE MIB, with a weighting of approximately 9,4%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective December 23, 2019.
A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the multilateral trading facility of securitised derivatives financial instruments, organised and managed by Borsa Italiana (SeDeX). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic multilateral trading facility where it is possible to trade securitized derivatives (for instance, covered warrants and certificates).
Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an “official price”, calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades, and a “reference price”, calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective February 3, 2020: (i) ± 5.0% (or such other amount established by Borsa Italiana in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price being the previous day’s reference price, in the opening auction or the price at which contracts are concluded in the auction phase after each auction phase; if no auction price is determined, the static price is equal to the price of the first contract concluded in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the “Guide to the Parameters”) with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.
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 (for example, shares, convertible bonds, pre-emptive rights, warrants), ETFplus (for example, Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes, Structured ETFs and Actively managed ETFs), IDEM (futures and options contracts whose underlying assets are financial instruments, interest rates, foreign currencies, goods or related indexes), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets.
According to the regulatory framework introduced by Markets in Financial Instruments Directive 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 which, on an organized, frequent systematic and substantial basis, deals on own account when executing client orders outside a Regulated Market, an MTF or an Organized Trading Facility (“OTF”) without operating a multilateral system. Following the transposition in Italy of MiFID II and the application of MiFIR, OTFs are now included among the “trading venues” that are subject to regulation.
An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract.
According to Legislative Decree No. 58 of February 24, 1998, as amended from time to time (“Decree No. 58”, the Consolidated Law on Financial Intermediation), the provision of investment services and activities to the public on a professional basis is, inter alia, reserved to investment firms, EU investment companies, Italian banks, EU banks and companies of non-EU countries authorized to operate in Italy (“authorized persons”). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct. Besides, for the purposes of the application of certain provisions of MiFIR the Bank of Italy and Consob are the Italian competent authorities: 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. 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.
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 shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required.
Moreover, to ensure compliance with the procedures envisaged by the above mentioned MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in which they state their potential interests related to Eni and its subsidiaries. In any case the Directors and the Statutory Auditors report in good time the single transactions that Eni intends to carry out in which they have an interest. Directors report the interest to the Chief Executive officer (or the Chairman, in the case of interests of the Chief Executive Officer), who will in turn notify the other Directors and the Board of Statutory Auditors. Statutory Auditors report the interest to the other Statutory Auditors and the Chairman of the Eni SpA Board of Directors.
Compensation
Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors with delegated powers in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the Remuneration Committee, after examining the opinion of the Board of Statutory Auditors (for more details about the compensation policy in 2019, see 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.
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(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.
Voting rights
The general provisions on share “voting rights” are described at the paragraph “Shareholders’ Meeting” below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see “Item 6”), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 30, 2020, 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 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 34 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.
Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban.
Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.
Limitation on changes in control of the Company (Special Powers of the Italian State)
Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012 (Law No. 56/2012), 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 rules5.
The special powers apply to companies that hold strategic assets vital to the interests of the Italian State as defined by the 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.
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(4)
This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below.
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(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 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 Finance6 and the Consob Regulation7, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%8, 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 criteria9. 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 investments10.
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
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(6)
Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.
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(7)
Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.
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(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.
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(9)
Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.
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(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), 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 of the Italian Civil Code, in case of a reciprocal participation exceeding the limit of 3% of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.
The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-quater.1 of the Consolidated Law on 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) 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, pursuant to Law No. 287 of October 10, 1990, any merger or acquisition of  (legal or factual) sole or joint control over a company or any change of control over a company is subject to the prior authorization by the Italian Antitrust 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 Italian market in a manner that eliminates or significantly reduces competition, the Italian Antitrust Authority can either prohibit the transaction or make it subject to remedies preventing a restriction of competition. Moreover, if the transaction or the companies involved exceed other thresholds set by European or other countries’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value or market shares of the parties), the transaction can also be subject to the prior authorization by competition authorities of other jurisdictions.
Changes in share capital
Eni’s By-laws do not provide for more stringent conditions than 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.
Exchange controls
Under current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by an Italian resident to a non-resident.
Taxation
The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.
Italian taxation
The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.
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 connection with entrepreneurial activity, are included in the taxable income subject to personal income tax to the extent of 58.14% of their amount. Personal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends received by Italian resident individuals holding the shares or ADRs otherwise than in connection with entrepreneurial activity, are subject to a substitute tax of 26% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return.
Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, and società di investimento a capitale variabile (“SICAV”) are not subject to
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(11)
Autorità garante per la concorrenza e il mercato (AGCM – www.agcm.it)
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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.
Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment.
Dividends are subject to a 1,20% substitute tax introduced by the Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to companies and entities subject to a corporate income tax in a European Union Member State or in the European Economic Area.
The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income Tax Treaties with approximately 90 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.
In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes.
Under the Tax Treaty between the United States and Italy (the “Italy U.S. Tax Treaty”), dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the “IRS”) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.
Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.
As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (“ADSs”), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities
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until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith.
Capital gains tax
This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy.
Profits gained by Italian resident individuals, not in connection with entrepreneurial activity, in financial year 2019, are subject to substitute tax for 26%.
For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return:
•
the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and
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•
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.
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Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.
On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to 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).
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 discuss all material tax consequences of the ownership of Shares or ADSs, including tax consequences arising under the Medicare contribution tax on net investment income. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of the combined voting power of Eni SpA’s voting stock or of the total value of Eni SpA’s stock, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar.
This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, (the “Code”), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.
If an entity or arrangement that is treated as a partnership for U.S. federal income tax purposes holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs.
As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.
The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the Italy U.S. Tax Treaty with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax.
Distributions
Subject to the passive foreign investment company (“PFIC”) rules discussed below, distributions paid on the shares 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 that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by Eni SpA that are received with respect to the ADSs will generally be qualified dividend income if the ADSs are readily tradable on an established securities market in the United States. Eni SpA’s ADSs are listed on the New York Stock Exchange and Eni SpA therefore expects that dividends with respect to the ADSs will be qualified dividend income. Dividends paid by Eni SpA with respect to the Shares will generally be qualified dividend income provided that, in the year that you receive the dividend, Eni SpA is eligible for the benefits of the Italy U.S. Tax Treaty. Eni SpA believes that it is currently eligible for the benefits of the Italy U.S. Tax Treaty and Eni SpA therefore expects that dividends on the Shares 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 ADSs or Shares will generally be income from sources outside the United States and will, generally be “passive” income for purposes of computing the foreign tax credit allowable to you. However, if  (a) Eni SpA is 50% or more owned, by vote or value, by United States persons and (b) at least 10% of Eni SpA’s earnings and profits are attributable to sources within the United States, then for foreign tax credit purposes, a portion of Eni SpA’s dividends would be treated as derived from sources within the United States. With respect to any dividend paid for any taxable year, the United States source ratio of Eni SpA’s dividends for foreign tax credit purposes would be equal to the portion of Eni SpA’s earnings and profits from sources within the United States for such taxable year, divided by the total amount of our earnings and profits for such taxable year. Eni SpA does not expect to be 50% or more owned, by vote or value, by United States persons, and therefore does not expect that any portion of Eni SpA’s dividends will be treated as derived from sources within the United States.
Sale or exchange of Shares
Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent). The amount realized will generally be reduced by any Italian Financial Transaction Tax paid in respect of such transfer, and a U.S. Holder will not be entitled to claim a foreign tax credit in respect of the payment of the Italian Financial Transaction Tax. Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.
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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 and Eni SpA does not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, the U.S. Holder would be treated as having realized such gains and certain “excess distributions” ratably over the holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, a U.S. Holder’s Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during the period the Shares or ADSs were held. Dividends received from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to the U.S. Holders either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.
Documents on display
Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at: https://www.eni.com/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 website (www.sec.gov).
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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 other market benchmarks will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.
The impact of changes in crude oil prices on the Company’s refining and marketing and petrochemical businesses depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.
As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives.
The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and its subsidiaries Eni Finance International, Eni Finance USA and Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA, Eni Finance International and Eni Finance USA manage the Group subsidiaries’ financing requirements in Italy, outside Italy and in the United States, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies are managed by the parent company. The 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 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. 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 of different assets under Eni control or that Eni will have under its controls in the normal course of business driven by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk; or
​
(ii)
qualifies as a hedging contract pursuant to IFRS.
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Use of financial derivatives (in euro or currencies different from euro) is allowed with the following risk reducing purposes:
•
Back to back: includes market risk-free instruments that are negotiated in accordance to an execution criteria and normally settled with an intermediation fee. They normally comply with hedge accounting requirements or own use exemption. These are transaction-based activities characterized by a substantial absence of market risk. A hedging instrument can be considered back to back when the financial derivative is structured as to match as much as possible asset class, size and maturity of the hedged position. As a result, the combination of the hedged item, normally a single asset/contract or an order received by mean of an internal derivative, and the hedging instrument, i.e. the financial derivative, is substantially market risk free or is exposed only to a basic risk related to the ineffective portion of the hedging item. In addition, the hedging item may entail counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes.
​
•
Flow hedging: flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, in accordance to a portfolio basis. A central department processes a continuous flow of orders from the Group various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity on the received orders, which are normally related to assets managed by the business units. The central broker entity can normally rely on a continuous flow of hedging orders that can be predictable to a large extent, on the basis of the regular hedging programs made by the Group’s business units. The central entity is therefore in the position to net opposite orders, by retaining the level of risk necessary to cover timing, volume and asset class mismatch among orders. The benefits are the maximization of integration across the whole of the Group assets portfolio and the related netting potential, avoiding unnecessary derivatives, thus reducing costs and aggregated notional amounts of hedging programs. Flow hedging is managed on a portfolio basis and is dynamic by nature, since resulting net position is normally adjusted in order to take into account new orders received and maximum allowed exposure, related to timing, volume and asset classes mismatch. Those derivatives are accounted to profit and loss as the hedging of net exposures does not qualify as hedges under IFRS.
​
•
Asset-backed hedging: is a portfolio-based activity performed to protect assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated to assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible the asset, the higher its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. To protect the value of asset flexibility, a business unit may transfer to a central entity part or the whole of an asset flexibility or a portfolio of flexibilities and the central entity will hedge such flexibility on financial markets so to lock its value by monetizing it via derivatives. Hedging strategies adopted for asset-backed hedging are normally portfolio based, very dynamic and entail large use of proxies. Depending on the optimization model such strategies are continuously adjusting relevant hedging ratios buying and selling same financial products several times, since the underlying asset flexibility to be hedged is changing depending on price level, price volatility, time to delivery, etc. These derivatives may lead to gains as well as losses which in each case may be significant and are accounted through profit and loss as they lack the hedge requirements provided by IFRS. However, we believe that the risks associated with those derivatives are mitigated by the natural hedge granted by the asset availability.
​
•
Portfolio management: is a portfolio based activity performed on a combination of underlying positions, such as physical assets (production plants, transmission infrastructures, storages, etc.), commercial assets (spot and forward short/medium/long term supply and sale contracts with physical delivery) and related financial derivatives. Normally, the target of a portfolio management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, prices scenarios and logistic flexibility/constraints, determine the optimal configuration in terms of volume, price and flexibility for physical and commercial assets in the portfolio. Financial derivatives are then used in the portfolio management activity in order to manage the overall risk level associated to such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the
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portfolio in line with company’s targets. Market risk associated to portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence, financial derivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several times in a given time frame. These derivatives may lead to gains, as well as losses which in each case may be significant and are accounted through profit as they lack the hedge requirements provided by IFRS.
Pursuant to internal policy, all derivatives transactions concerning interest rates and foreign currencies are executed for risk reducing purposes, as described above. Only commodity derivatives can also be executed in the context of non-risk reducing operations and be consequently classified as Proprietary Trading, which is an ancillary activity not related to industrial assets that makes use of financial derivatives which are entered into with the objective to obtain an uncertain profit, if favorable market expectations occur.
Eni monitors on a daily basis that every activity involving derivatives is correctly classified according to the risk reducing taxonomy (i.e. back to back, flow hedging, asset-backed hedging or portfolio management), is directly or indirectly related to the hedged industrial assets and effectively optimizes the risk profile to which Eni is, or could be, exposed. When some derivatives fail to prove their risk reducing purpose, they are reclassified as Proprietary Trading. Provided that Proprietary Trading is segregated ex ante from other activities, its resulting market risk exposure is subject to specific limits expressed in terms of Stop Loss, VaR and notional amounts. The aggregated notional amounts of non-risk reducing derivatives at Group level are constantly benchmarked with the thresholds required by relevant international financial regulations.
Please refer to “Item 18 – Note 27 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks.
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Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Item 12A. Debt securities
Not applicable.
Item 12B. Warrants and rights
Not applicable.
Item 12C. Other securities
Not applicable.
Item 12D. American Depositary Shares
In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares.
Pursuant to the Deposit Agreement dated June 27, 2017 (the “Deposit Agreement”) between Eni, Citibank N.A. and the holders and beneficial owners ADSs, Citibank N.A. serves as the Depositary for Eni’s ADR Program, and Citibank N.A. Milan Branch serves as Custodian.
Computershare is the transfer agent for the Eni SpA ADR program.
Fees and charges payable by ADR holders
Pursuant to the Deposit Agreement, ADR holders may be required to pay various fees to the Depositary, and the Depositary may refuse to provide any service for which a fee is assessed until the applicable fee has been paid.
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The following ADS fees are payable under the terms of the Deposit Agreement:

Service | ​ | ​ | Rate | ​ | ​ | By Whom Paid | ​
(1) Issuance of ADSs (e.g., an issuance upon a deposit of Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason), excluding issuances as a result of distributions described in paragraph (4) below. ​ | ​ | ​ | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) issued. | ​ | ​ | Person receiving ADSs. | ​
(2) Cancellation of ADSs (e.g., a cancellation of ADSs for delivery of deposited Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason). ​ | ​ | ​ | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) cancelled. | ​ | ​ | Person whose ADSs are being cancelled. | ​
(3) Distribution of cash dividends or other cash distributions (e.g., upon a sale of rights and other entitlements). ​ | ​ | ​ | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. | ​ | ​ | Person to whom the distribution is made. | ​
(4) Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) an exercise of rights to purchase additional ADSs. ​ | ​ | ​ | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. | ​ | ​ | Person to whom the distribution is made. | ​
(5) Distribution of securities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares). ​ | ​ | ​ | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. | ​ | ​ | Person to whom the distribution is made. | ​
(6) ADS Services. ​ | ​ | ​ | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary. | ​ | ​ | Person holding ADSs on the applicable record date(s) established by the Depositary. | ​

Direct and indirect payments by the Depositary
The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the NYSE. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing U.S. SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.
For the year 2019, the Depositary will reimburse to Eni up to $1,800,000 in connection with the above mentioned expenditures.
The Depositary has also agreed to waive certain standard fees associated with the administration of the ADR Program.
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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.
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, 2019.
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The effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, has been audited by PricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F.
Changes in Internal Control over Financial Reporting
There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 16. [RESERVED]
Item 16A. Board of Statutory Auditors financial expert
Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: Rosalba Casiraghi, who is the Chairman of the Board, Enrico Maria Bignami, Paola Camagni, 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 Chiefs, Officers, principal Financial and Accounting Officers, Directors and Statutory Auditors. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Governance. A copy of this Code of Ethics is included as an exhibit to 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
PwC SpA has served as Eni principal independent public auditor for fiscal 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 for services rendered to Eni by its public auditors 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 which has served as Eni principal independent public auditor since the fiscal year 2018.

​ | ​ | ​ | Year ended December 31, | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
​ | ​ | ​ | (€ thousand) | ​
Audit fees | ​ | ​ | ​ | ​ | 15,748 | ​ | ​ | ​ | ​ | ​ | 25,445 | ​ | ​
Audit -related fees | ​ | ​ | ​ | ​ | 1,045 | ​ | ​ | ​ | ​ | ​ | 1,628 | ​ | ​
Tax fees | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
All other fees | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total | ​ | ​ | ​ | ​ | 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, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards.
Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value-added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities.
All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.
Pre-approval policies and procedures of the Internal Control Committee
The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities controlled (directly or indirectly) by Eni SpA as well as to jointly controlled entities that are material to the Eni Group. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors.
During 2019, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (C) of Rule 2-01 of Regulation S-X.
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Item 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 Eni Board of Directors, in execution of the authorization granted by the Eni Shareholders’ Meeting of May 14, 2019 and in accordance with the terms announced to the market on that date, has approved measures to begin the 2019 share buy-back programme, in the maximum amount of €400,000,000 and up to a maximum of 67,000,000 shares. The purchases started in the first week of June 2019 and ended in the month of December 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
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. 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. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a Director’s independence.
Eni standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of judgment.
Eni’s By-laws require that at least one Director – if the Board has no more than five members – or at least three Directors – if the Board is composed of more than five members – must satisfy the independence requirements. The Corporate Governance Code 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. Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors. In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year.
Eni standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year without the other Directors. During 2019, Eni’s independent Directors had opportunities to meet, informally, to hold discussions and exchange opinions.
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Audit Committee
NYSE standards. Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.
Eni standards. At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of 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. U.S. listed companies must have a Nominating/Corporate Governance Committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers.
Eni standards. Pursuant to the Corporate Governance Code, 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. On April 13, 2017, the Board of Directors of Eni established the Nomination Committee, chaired by Diva Moriani (independent Director) and composed of Andrea Gemma (independent Director), Fabrizio Pagani (non-executive Director) and Domenico Livio Trombone (independent Director). Further details on this Committee are reported in the Item 6.
Remuneration Committee
NYSE standards. U.S. listed companies must have a Remuneration Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The Remuneration Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The Remuneration Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers.
Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a Remuneration Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have an adequate understanding of and experience in financial matters or compensation policies. First established by the Board of Directors in 1996, the Remuneration Committee is currently chaired by Director Andrea Gemma. The other members include directors Pietro Guindani, Alessandro Lorenzi and Diva 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. 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 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 September 19, 2019, approved the updating of Model 231, as defined by the CEO with the support of 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; the new Code sets out the fundamental principles of Eni’s Model 231 which is one of the pillars of Eni “regulatory system” and inspires it.
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.
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, 2019 and December 31, 2018 and January 1, 2018 | ​ | ​ | ​ | ​ | F-5 | ​ | ​
Consolidated profit and loss account for the years ended December 31, 2019, 2018 and 2017 | ​ | ​ | ​ | ​ | F-6 | ​ | ​
Consolidated Statements of comprehensive income for the years ended December 31, 2019, 2018 and 2017 | ​ | ​ | ​ | ​ | F-7 | ​ | ​
Consolidated Statements of changes in shareholders’ equity for the years ended December 31, 2019, 2018 and 2017 | ​ | ​ | ​ | ​ | F-8 | ​ | ​
Consolidated Statement of cash flows for the years ended December 31, 2019, 2018 and 2017 | ​ | ​ | ​ | ​ | F-11 | ​ | ​
Notes on Consolidated Financial Statements | ​ | ​ | ​ | ​ | 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 | ​

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Eni SpA
OPINIONS ON THE FINANCIAL STATEMENTS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
We have audited the accompanying consolidated balance sheet of Eni SpA and its subsidiaries (the “Company”) as of December 31, 2019, and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders’ equity and cash flows for 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 Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019, and the results of its operations and its cash flows for the year then ended in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 15. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
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assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Estimates of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net
As described in 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 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 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 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 have served as the Company’s auditor since 2019.
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Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of
Eni S.p.A.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Eni S.p.A. (the Company) as of December 31, 2018, the related consolidated profit and loss accounts and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company 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 opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ EY S.p.A.
We served as the Company’s auditor from 2010 to 2018.
Rome, Italy
April 5, 2019
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.
F-4

TABLE OF CONTENTS​
CONSOLIDATED BALANCE SHEET
(€ million)

​ | 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.
F-5

TABLE OF CONTENTS​
CONSOLIDATED PROFIT AND LOSS ACCOUNT
(€ million except as otherwise stated)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | 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 AND OTHER INCOME | ​ | ​ | (28)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 69,881 | ​ | ​ | ​ | ​ | ​ | 1,248 | ​ | ​ | ​ | ​ | ​ | 75,822 | ​ | ​ | ​ | ​ | ​ | 1,383 | ​ | ​ | ​ | ​ | ​ | 66,919 | ​ | ​ | ​ | ​ | ​ | 1,567 | ​ | ​
Other income and revenues | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,160 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 1,116 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 4,058 | ​ | ​ | ​ | ​ | ​ | 41 | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 71,041 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 76,938 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 70,977 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
COSTS | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Purchases, services and other | ​ | ​ | (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 | ​ | ​ | (29)​ | ​ | ​ | ​ | ​ | (2,996) | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​ | ​ | ​ | ​ | (3,093) | ​ | ​ | ​ | ​ | ​ | (22) | ​ | ​ | ​ | ​ | ​ | (2,951) | ​ | ​ | ​ | ​ | ​ | (34) | ​ | ​
Other operating income (expense) | ​ | ​ | (23)​ | ​ | ​ | ​ | ​ | 287 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 129 | ​ | ​ | ​ | ​ | ​ | 319 | ​ | ​ | ​ | ​ | ​ | (32) | ​ | ​ | ​ | ​ | ​ | 331 | ​ | ​
Depreciation and amortization | ​ | ​ | (11) (12) (13)​ | ​ | ​ | ​ | ​ | (8,106) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6,988) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (7,483) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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 | ​ | ​ | (11) (13)​ | ​ | ​ | ​ | ​ | (300) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (100) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (263) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
OPERATING PROFIT | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6,432 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 9,983 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8,012 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
FINANCE INCOME (EXPENSE) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Finance income | ​ | ​ | (30)​ | ​ | ​ | ​ | ​ | 3,087 | ​ | ​ | ​ | ​ | ​ | 96 | ​ | ​ | ​ | ​ | ​ | 3,967 | ​ | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 3,924 | ​ | ​ | ​ | ​ | ​ | 191 | ​ | ​
Finance expense | ​ | ​ | (30)​ | ​ | ​ | ​ | ​ | (4,079) | ​ | ​ | ​ | ​ | ​ | (36) | ​ | ​ | ​ | ​ | ​ | (4,663) | ​ | ​ | ​ | ​ | ​ | (283) | ​ | ​ | ​ | ​ | ​ | (5,886) | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​
Net finance income (expense) from financial assets held for trading | ​ | ​ | (30)​ | ​ | ​ | ​ | ​ | 127 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (111) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivative financial instruments | ​ | ​ | (23) (30)​ | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (307) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 837 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (879) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (971) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,236) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
INCOME (EXPENSE) FROM INVESTMENTS | ​ | ​ | (15) (31)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Share of profit (loss) from equity-accounted investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (88) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (68) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (267) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other gain (loss) from investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 281 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,163 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 335 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 193 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,095 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 68 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
PROFIT BEFORE INCOME TAXES | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5,746 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 10,107 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6,844 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income taxes | ​ | ​ | (32)​ | ​ | ​ | ​ | ​ | (5,591) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5,970) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3,467) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net profit | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 155 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4,137 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3,377 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Attributable to Eni | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4,126 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3,374 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Attributable to non-controlling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 155 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4,137 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3,377 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Earnings per share attributable to Eni (€ per share) | ​ | ​ | (33)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.04 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.94 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Diluted | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.04 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.94 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

See the accompanying notes.
F-6

TABLE OF CONTENTS​​
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(€ million)

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 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.
F-7

TABLE OF CONTENTS​
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(€ 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, 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-8

TABLE OF CONTENTS
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued)
(€ 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-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
(€ million)

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | Note | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Net profit | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 155 | ​ | ​ | ​ | ​ | ​ | 4,137 | ​ | ​ | ​ | ​ | ​ | 3,377 | ​ | ​
Adjustments to reconcile net profit to net cash provided by operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depreciation and amortization | ​ | ​ | (11) (12) (13) | ​ | ​ | ​ | ​ | 8,106 | ​ | ​ | ​ | ​ | ​ | 6,988 | ​ | ​ | ​ | ​ | ​ | 7,483 | ​ | ​
Net Impairments (reversals) of tangible and intangible assets and right-of-use assets | ​ | ​ | (14) | ​ | ​ | ​ | ​ | 2,188 | ​ | ​ | ​ | ​ | ​ | 866 | ​ | ​ | ​ | ​ | ​ | (225) | ​ | ​
Write-off of tangible and intangible assets | ​ | ​ | (11) (13) | ​ | ​ | ​ | ​ | 300 | ​ | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 263 | ​ | ​
Share of  (profit) loss of equity-accounted investments | ​ | ​ | (15) (31) | ​ | ​ | ​ | ​ | 88 | ​ | ​ | ​ | ​ | ​ | 68 | ​ | ​ | ​ | ​ | ​ | 267 | ​ | ​
Net gain on disposal of assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (170) | ​ | ​ | ​ | ​ | ​ | (474) | ​ | ​ | ​ | ​ | ​ | (3,446) | ​ | ​
Dividend income | ​ | ​ | (31) | ​ | ​ | ​ | ​ | (247) | ​ | ​ | ​ | ​ | ​ | (231) | ​ | ​ | ​ | ​ | ​ | (205) | ​ | ​
Interest income | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (147) | ​ | ​ | ​ | ​ | ​ | (185) | ​ | ​ | ​ | ​ | ​ | (283) | ​ | ​
Interest expense | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,027 | ​ | ​ | ​ | ​ | ​ | 614 | ​ | ​ | ​ | ​ | ​ | 671 | ​ | ​
Income taxes | ​ | ​ | (32) | ​ | ​ | ​ | ​ | 5,591 | ​ | ​ | ​ | ​ | ​ | 5,970 | ​ | ​ | ​ | ​ | ​ | 3,467 | ​ | ​
Other changes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (179) | ​ | ​ | ​ | ​ | ​ | (474) | ​ | ​ | ​ | ​ | ​ | 894 | ​ | ​
Changes in working capital: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- inventories | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (200) | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | (346) | ​ | ​
- trade receivables | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,023 | ​ | ​ | ​ | ​ | ​ | 334 | ​ | ​ | ​ | ​ | ​ | 657 | ​ | ​
- trade payables | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (940) | ​ | ​ | ​ | ​ | ​ | 642 | ​ | ​ | ​ | ​ | ​ | 284 | ​ | ​
- provisions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 272 | ​ | ​ | ​ | ​ | ​ | (238) | ​ | ​ | ​ | ​ | ​ | 96 | ​ | ​
- other assets and liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 211 | ​ | ​ | ​ | ​ | ​ | 879 | ​ | ​ | ​ | ​ | ​ | 749 | ​ | ​
Cash flow from changes in working capital | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 366 | ​ | ​ | ​ | ​ | ​ | 1,632 | ​ | ​ | ​ | ​ | ​ | 1,440 | ​ | ​
Net change in the provisions for employee benefits | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (23) | ​ | ​ | ​ | ​ | ​ | 109 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​
Dividends received | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,346 | ​ | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 291 | ​ | ​
Interest received | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 88 | ​ | ​ | ​ | ​ | ​ | 87 | ​ | ​ | ​ | ​ | ​ | 104 | ​ | ​
Interest paid | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,029) | ​ | ​ | ​ | ​ | ​ | (609) | ​ | ​ | ​ | ​ | ​ | (582) | ​ | ​
Income taxes paid, net of tax receivables received | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5,068) | ​ | ​ | ​ | ​ | ​ | (5,226) | ​ | ​ | ​ | ​ | ​ | (3,437) | ​ | ​
Net cash provided by operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12,392 | ​ | ​ | ​ | ​ | ​ | 13,647 | ​ | ​ | ​ | ​ | ​ | 10,117 | ​ | ​
- of which with related parties | ​ | ​ | (36) | ​ | ​ | ​ | ​ | (6,356) | ​ | ​ | ​ | ​ | ​ | (2,707) | ​ | ​ | ​ | ​ | ​ | (2,843) | ​ | ​
Investing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- tangible assets | ​ | ​ | (11) | ​ | ​ | ​ | ​ | (8,049) | ​ | ​ | ​ | ​ | ​ | (8,778) | ​ | ​ | ​ | ​ | ​ | (8,490) | ​ | ​
- prepaid right-of-use assets | ​ | ​ | (12) | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- intangible assets | ​ | ​ | (13) | ​ | ​ | ​ | ​ | (311) | ​ | ​ | ​ | ​ | ​ | (341) | ​ | ​ | ​ | ​ | ​ | (191) | ​ | ​
- consolidated subsidiaries and businesses net of cash and cash equivalent acquired | ​ | ​ | (26) | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | (119) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- investments | ​ | ​ | (15) | ​ | ​ | ​ | ​ | (3,003) | ​ | ​ | ​ | ​ | ​ | (125) | ​ | ​ | ​ | ​ | ​ | (510) | ​ | ​
- securities held for operating purposes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- financing receivables held for operating purposes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (229) | ​ | ​ | ​ | ​ | ​ | (358) | ​ | ​ | ​ | ​ | ​ | (585) | ​ | ​
- change in payables in relation to investing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (307) | ​ | ​ | ​ | ​ | ​ | 408 | ​ | ​ | ​ | ​ | ​ | 152 | ​ | ​
Cash flow from investing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (11,928) | ​ | ​ | ​ | ​ | ​ | (9,321) | ​ | ​ | ​ | ​ | ​ | (9,624) | ​ | ​
Disposals: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- tangible assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 264 | ​ | ​ | ​ | ​ | ​ | 1,089 | ​ | ​ | ​ | ​ | ​ | 2,745 | ​ | ​
- intangible assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- consolidated subsidiaries and businesses net of cash and cash equivalent disposed of | ​ | ​ | (26) | ​ | ​ | ​ | ​ | 187 | ​ | ​ | ​ | ​ | ​ | (47) | ​ | ​ | ​ | ​ | ​ | 2,662 | ​ | ​
- tax on disposals | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (436) | ​ | ​
- investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 195 | ​ | ​ | ​ | ​ | ​ | 482 | ​ | ​
- securities held for operating purposes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- financing receivables held for operating purposes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 178 | ​ | ​ | ​ | ​ | ​ | 279 | ​ | ​ | ​ | ​ | ​ | 493 | ​ | ​
- change in receivables in relation to disposals | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 95 | ​ | ​ | ​ | ​ | ​ | 606 | ​ | ​ | ​ | ​ | ​ | (434) | ​ | ​
Cash flow from disposals | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 794 | ​ | ​ | ​ | ​ | ​ | 2,142 | ​ | ​ | ​ | ​ | ​ | 5,515 | ​ | ​
Net change in securities and financing receivables held for non-operating purposes﻿(a) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (279) | ​ | ​ | ​ | ​ | ​ | (357) | ​ | ​ | ​ | ​ | ​ | 341 | ​ | ​
Net cash used in investing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (11,413) | ​ | ​ | ​ | ​ | ​ | (7,536) | ​ | ​ | ​ | ​ | ​ | (3,768) | ​ | ​
- of which with related parties | ​ | ​ | (36) | ​ | ​ | ​ | ​ | (2,912) | ​ | ​ | ​ | ​ | ​ | (3,314) | ​ | ​ | ​ | ​ | ​ | (3,115) | ​ | ​

See the accompanying notes.
​
(a)
From 2019, Eni’s cash flow statement is reporting in a dedicated line-item the net cash outflow (investments minus divestments) in held-for-trading financial assets and current non-operating receivables financing, with the latter being investment of temporary cash surpluses. Those two assets are netted against financial liabilities to determine the Group net borrowings in accordance to applicable listing standards. In previous reporting periods, cash inflows and outflows relating those assets were reported among investing activities or divesting activities relating to securities and financing receivables, respectively. The cash flow statements of comparative periods have been reclassified accordingly.
​
F-11

TABLE OF CONTENTS
CONSOLIDATED STATEMENT OF CASH FLOWS (continued)
(€ million)

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | Note | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Increase in long-term financial debt | ​ | ​ | (18) | ​ | ​ | ​ | ​ | 1,811 | ​ | ​ | ​ | ​ | ​ | 3,790 | ​ | ​ | ​ | ​ | ​ | 1,842 | ​ | ​
Repayments of long-term financial debt | ​ | ​ | (18) | ​ | ​ | ​ | ​ | (3,512) | ​ | ​ | ​ | ​ | ​ | (2,757) | ​ | ​ | ​ | ​ | ​ | (2,973) | ​ | ​
Payments of lease liabilities | ​ | ​ | (12) | ​ | ​ | ​ | ​ | (877) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Increase (decrease) in short-term financial debt | ​ | ​ | (18) | ​ | ​ | ​ | ​ | 161 | ​ | ​ | ​ | ​ | ​ | (713) | ​ | ​ | ​ | ​ | ​ | (581) | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (2,417) | ​ | ​ | ​ | ​ | ​ | 320 | ​ | ​ | ​ | ​ | ​ | (1,712) | ​ | ​
Dividends paid to Eni’s shareholders | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3,018) | ​ | ​ | ​ | ​ | ​ | (2,954) | ​ | ​ | ​ | ​ | ​ | (2,880) | ​ | ​
Dividends paid to non-controlling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​
Reimbursements to non-controlling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Acquisition of additional interests in consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Acquisition of treasury shares | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (400) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash used in financing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5,841) | ​ | ​ | ​ | ​ | ​ | (2,637) | ​ | ​ | ​ | ​ | ​ | (4,595) | ​ | ​
- of which with related parties | ​ | ​ | (36) | ​ | ​ | ​ | ​ | (817) | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​
Effect of change in consolidation (inclusion/exclusion of significant/​insignificant subsidiaries) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​
Effect of exchange rate changes and other changes on cash and cash equivalents | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | (72) | ​ | ​
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.
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(b)
In 2018, cash and cash equivalents at the end of the year included €19 million of cash and cash equivalents of consolidated subsidiaries held for sale that were reported in the item “Assets held for sale”.
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Notes on Consolidated Financial Statements
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).
The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value as described in the accounting policies that follow.
The 2019 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on March 18, 2020, were audited by the external auditor PricewaterhouseCoopers SpA. The external auditor of Eni SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other external auditors, PricewaterhouseCoopers SpA takes the responsibility of their work.
The Consolidated Financial Statements are presented in euros and all values are rounded to the nearest million euros (€ million), except where otherwise indicated.
Significant accounting estimates and judgements
The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognised in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are based on complex judgements and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgements and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of financial and non-financial assets, leases, decommissioning and restoration liabilities, environmental liabilities, business combinations, employee benefits, revenue from contracts with customers, fair value measurements and income taxes. Although the Company uses its best estimates and judgements, actual results could differ from the estimates and assumptions used. The accounting estimates and judgements relevant for the preparation of the Consolidated Financial Statement are described below.
Principles of consolidation
Subsidiaries
The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee, i.e. the activities that significantly affect the investee’s returns.
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1
IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).
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Subsidiaries are 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 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 revenue and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognised directly in the financial statements of the companies involved based on their own share. Some subsidiaries are not consolidated because they are immaterial, either individually or in the aggregate; this exclusion has not produced material2 effects on the Consolidated Financial Statements3.
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 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 or loss calculated as the difference between the consideration received and the corresponding transferred net assets; (ii) any gain or loss recognised as a result of the remeasurement of any investment retained in the former subsidiary at its fair value; and (iii) any amount related to the former subsidiary previously recognised in other comprehensive income which may be reclassified subsequently to the profit and loss account4. Any investment retained in the former subsidiary is recognised at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria.
Interests in joint arrangements
Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.
A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement. In the Consolidated Financial Statements, Eni recognises its share of the assets/liabilities and revenue/expenses of joint operations on the basis of its rights and obligations relating to the arrangements.
After the initial recognition, the assets/liabilities and revenue/expenses of the joint operations are measured in accordance with the applicable measurement criteria. Immaterial joint operations structured through a separate vehicle are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of any impairment losses.
Investments in associates
An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.
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2
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”.
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3
Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”.
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4
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.
The equity method of accounting
Investments in joint ventures, associates and immaterial unconsolidated subsidiaries, are accounted for using the equity method.5 6
Under the equity method, investments are initially recognised at cost, allocating, similarly to business combinations procedures, the purchase price of the investment to the investee’s identifiable assets/liabilities; if this allocation is provisionally recognised at initial recognition, it can be retrospectively adjusted within one year from the date of initial recognition, to reflect new information obtained about facts and circumstances that existed at the date of initial recognition. Subsequently, the carrying amount is adjusted to reflect: (i) the investor’s share of the profit or loss of the investee after the date of acquisition, adjusted to account for depreciation, amortization and any impairment losses of the equity-accounted entity’s assets based on their fair values at the date of acquisition; and (ii) the investor’s share of the investee’s other comprehensive income. Distributions received from an equity-accounted investee reduce the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). Losses arising from the application of the equity method in excess of the carrying amount of the investment, recognised in the profit and loss account within “Income (Expense) from investments”, reduce the carrying amount, net of the related expected credit losses (see below), of any financing receivables towards the investee for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests), which are, in substance, an extension of the investment in the investee. The investor’s share of any losses of an equity-accounted investee that exceeds the carrying amount of the investment and any long-term interests (the so-called net investment), is recognised in a specific provision only to the extent that the investor has incurred legal or constructive obligations or made payments on behalf of the investee.
Whenever there is objective evidence of impairment (e.g. relevant breaches of contracts, significant financial difficulty, probable default of the counterparty, etc.), the net investment is tested for impairment by comparing its carrying amount with the related recoverable amount, determined by adopting the criteria indicated in the accounting policy for “Impairment of non-financial assets”. When an impairment loss no longer exists or has decreased, any reversal of the impairment loss is recognised in the profit and loss account within “Income (Expense) from investments”. The impairment reversal of the net investment shall not exceed the previously recognised impairment losses.
The sale of equity interests with loss of joint control or significant influence over the investee determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognised as a result of the remeasurement of any investment retained in the former joint venture/associate at its fair value7; and (iii) any amount related to the former joint venture/associate previously recognised in other comprehensive income which may be reclassified subsequently to the profit and loss account8. Any investment retained in the former joint venture/associate is recognised at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria.
Business combinations
Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is the sum of the acquisition-date fair value of the assets transferred, the liabilities incurred and the equity interests issued by the acquirer. Acquisition-related costs are accounted for as expenses when incurred.
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5
In the case of step acquisition of significant influence (joint control), the investment is recognised, at the acquisition date of significant influence (joint control), at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity.
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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.
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7
If the retained investment continues to be accounted for using the equity method, no remeasurement at fair value is recognised in the profit and loss account.
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8
Conversely, any amount related to the former joint venture/associate previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.
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The acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values9, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the acquisition-date fair values of the identifiable assets acquired and liabilities assumed is recognised, on the balance sheet, as goodwill; conversely, a gain on a bargain purchase is recognised in the profit and loss account.
Any non-controlling interests are measured as the proportionate share in the recognised amounts of the acquiree’s identifiable net assets at the acquisition date excluding the portion of goodwill attributable to them (partial goodwill method); as an alternative, non-controlling interests may be measured at fair value, which means that goodwill includes the portion attributable to them (full goodwill method)10. The choice of measurement basis for goodwill (partial goodwill method vs. full goodwill method) is made on a transaction-by-transaction basis.
In a business combination achieved in stages, the purchase price is determined by summing the acquisition-date fair value of previously held equity interests in the acquiree and the consideration transferred for obtaining control; the previously held equity interests are remeasured at their acquisition-date fair value and the resulting gain or loss, if any, is recognised in the profit and loss account. Furthermore, on obtaining control, any amount recognised in other comprehensive income related to the previously held equity interests is reclassified to the profit and loss account, or in another item of equity when such amount may not be reclassified to the profit and loss account.
If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognised at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date.
The acquisition of interests in a joint operation whose activity constitutes a business is accounted for applying the principles on business combinations accounting. In this regard, if the entity obtains control over a business that was a joint operation, the previously held interest in the joint operation is remeasured at the acquisition-date fair value and the resulting gain or loss is recognized in the profit and loss account.11
Significant accounting estimates and judgements: investments and business combinations
The assessment of the existence of control, joint control, significant influence over an investee, as well as for joint operations, the assessment of the existence of enforceable rights 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 facts and circumstances. Significant accounting estimates by management are required also for measuring the identifiable assets acquired and the liabilities assumed in a business combination at their acquisition-date fair values. For such measurement, to be performed also for the application of the equity method, Eni adopts the valuation techniques generally used by market participants taking into account the available information; for the most significant business combinations, Eni engages external independent evaluators.
Intragroup transactions
All balances and transactions between consolidated companies, and not yet realised with third parties, including unrealised profits arising from such transactions have been eliminated.
Unrealised profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity. In both cases, unrealised losses are not eliminated unless the transaction provides evidence of an impairment loss of the asset transferred.
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9
Fair value measurement principles are described in the accounting policy for “Fair value measurements”.
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10
The choice between the partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account.
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11
If the entity acquires additional interests in a joint operation that is a business, while retaining joint control, the previously held interest in the joint operation is not remeasured.
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Foreign currency translation
The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency, are translated into euros using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows (source: Reuters — WMR).
The cumulative resulting exchange differences are presented in the separate component of Eni shareholders’ equity “Cumulative currency translation differences”12. Cumulative amount of exchange differences relating to a foreign operation are reclassified to the profit and loss account when the entity disposes the entire interest in that foreign operation or when the partial disposal involves the loss of control, joint control or significant influence over the foreign operation. On a partial disposal that does not involve loss of control of a subsidiary that includes a foreign operation, the proportionate share of the cumulative exchange differences is reattributed to the non-controlling interests in that foreign operation. On a partial disposal of interests in joint arrangements or in associates that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account.
The financial statements of foreign operations which are translated into euros are denominated in the foreign operations’ functional currencies which generally is the U.S. dollar.
The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below:

(currency amount for 1 €) | ​ | ​ | Annual average exchange rate 2019 | ​ | ​ | Exchange rate at December 31, 2019 | ​ | ​ | Annual average exchange rate 2018 | ​ | ​ | Exchange rate at December 31, 2018 | ​ | ​ | Annual average exchange rate 2017 | ​ | ​ | Exchange rate at December 31, 2017 | ​
U.S. Dollar | ​ | ​ | ​ | ​ | 1.12 | ​ | ​ | ​ | ​ | ​ | 1.12 | ​ | ​ | ​ | ​ | ​ | 1.18 | ​ | ​ | ​ | ​ | ​ | 1.15 | ​ | ​ | ​ | ​ | ​ | 1.13 | ​ | ​ | ​ | ​ | ​ | 1.20 | ​ | ​
Pound Sterling | ​ | ​ | ​ | ​ | 0.88 | ​ | ​ | ​ | ​ | ​ | 0.85 | ​ | ​ | ​ | ​ | ​ | 0.88 | ​ | ​ | ​ | ​ | ​ | 0.89 | ​ | ​ | ​ | ​ | ​ | 0.88 | ​ | ​ | ​ | ​ | ​ | 0.89 | ​ | ​
Australian Dollar | ​ | ​ | ​ | ​ | 1.61 | ​ | ​ | ​ | ​ | ​ | 1.60 | ​ | ​ | ​ | ​ | ​ | 1.58 | ​ | ​ | ​ | ​ | ​ | 1.62 | ​ | ​ | ​ | ​ | ​ | 1.47 | ​ | ​ | ​ | ​ | ​ | 1.53 | ​ | ​

Significant accounting policies
The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.
Oil and natural gas exploration, appraisal, development and production activities
Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting as described below.
Acquisition of exploration rights
Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalised within the line item “Intangible assets” as “exploration rights — unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortised, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that indicate the absence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognised in the profit and loss account as write-off. Lower value exploration rights are pooled and amortised on a straight-line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of
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12
When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognised as part of  “Non-controlling interest”.
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proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. Upon reclassification, 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 amortised according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortisation”).
Acquisition of mineral interests
Costs incurred for the acquisition of mineral interests are capitalised in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows.
Acquired exploration potential is measured in accordance with the criteria illustrated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are amortised according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortisation”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortised until classified as proved reserves; in case of a negative result, it is written off.
Exploration and appraisal expenditure
Geological and geophysical exploration costs are recognised as an expense as incurred.
Costs directly associated with an exploration well are initially recognised within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalised in the following 12-month period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalised if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project; on the contrary, the capitalised costs are recognised in the profit and loss account as write-off. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognised as unproved is reclassified to proved exploration and appraisal costs within tangible assets in progress. Upon reclassification, 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 amortisation”).
Development expenditure
Development expenditure, including the costs related to unsuccessful and damaged development wells, are capitalised as “Tangible asset in progress — proved”. Development costs are incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. They are amortised, from the commencement of production, generally on a UOP basis. When development projects are unfeasible/not carried on, the related costs are written off when it is decided to abandon the project. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.
UOP depreciation, depletion and amortisation
Proved oil and gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of proved oil and gas reserves, by applying, to the depreciable amounts at the end of each quarter a rate representing the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This
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method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil and gas reserves. Proved exploration rights and acquired proved mineral interests are amortised over proved reserves; proved exploration and appraisal costs and development expenditure are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves.
Production costs
Production costs are those costs incurred to operate and maintain wells and field equipment and are recognised as an expense as incurred.
Production Sharing Agreements and buy-back contracts
Oil and gas reserves related to Production Sharing Agreements and buy-back contracts are determined on the basis of contractual terms related to the recovery of the contractor’s costs to undertake and finance exploration, development and production activities at its own risk (Cost Oil) and the Company’s stipulated share of the production remaining after such cost recovery (Profit Oil). Revenues from the sale of the lifted production, against both Cost Oil and Profit Oil, are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above-mentioned accounting policies. The Company’s share of production volumes and reserves includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognise at the same time an increase in the taxable profit, through the increase of the revenue, and a tax expense.
Plugging and abandonment of wells
Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalised, consistent with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis.
Significant accounting estimates and judgements: oil and natural gas activities
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be categorised as “proved”, the accuracy of reserve estimates depends on a number of factors, assumptions and variables, including: (i) the quality of available geological, technical and economic data and their interpretation and judgement; (ii) projections regarding future rates of production and operating costs as well as timing and amount of development expenditures; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and (v) changes in oil and natural gas prices which could affect expected future cash flows and the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.
Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves.
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 recognised using the cost model and stated at their purchase price or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management. For assets that necessarily take a substantial period of time to get ready for their intended use, the purchase price or construction cost comprises the borrowing costs incurred in the period to get the asset ready for use that would have been avoided if the expenditure had not been made.
In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs; a corresponding amount is recognised as part of a specific provision (see the accounting policy for “Decommissioning and restoration liabilities”.
Property, plant and equipment are not revalued for financial reporting purposes.
Expenditures on upgrading, revamping and reconversion are recognised as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary for running the business.
Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. Property, plant and equipment are depreciated on a systematic basis over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company. When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when acquired together with a building. Tangible assets held for sale are not depreciated (see the accounting policy for “Assets held for sale and discontinued operations”). Changes in the asset’s useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, are accounted for prospectively.
Assets to be handed over for no consideration are depreciated over the shorter term between the duration of the concession or the asset’s useful life.
Replacement costs of identifiable parts in complex assets are capitalised and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Non-removable leasehold improvements are depreciated over the earlier of the useful life of the improvements and the lease term. Expenditures for ordinary maintenance and repairs are recognised as an expense as incurred.
The carrying amount of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognised in the profit and loss account.
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Leases13 14
A contract is, or contains, a lease, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration15; such right exists whether, throughout the period of use, the customer has both the right to obtain substantially all of the economic benefits from use of the identified asset and the right to direct the use of the identified asset.
At the commencement date of the lease (i.e. the date on which the underlying asset is available for use), a lessee recognises on the balance sheet an asset representing its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability representing its obligation to make lease payments during the lease term (hereinafter also referred as lease liability).16 The lease term is the non-cancellable period of a contract, together with, if reasonably certain, periods covered by extension options or by the non-exercise of termination options.
In particular, the lease liability is initially recognised at the present value of the following lease payments17 that are not paid at the commencement date: (i) fixed payments (including in-substance fixed payments), less any lease incentives receivable; (ii) variable lease payments that depend on an index or a rate18; (iii) amounts expected to be payable by the lessee under residual value guarantees; (iv) the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and (v) payments of penalties for terminating the lease, if the lease term reflects the lessee exercising an option to terminate the lease. The lease payments are discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the lessee’s incremental borrowing rate. The latter is determined considering the term of the lease, the frequency and currency of the contractual lease payments, as well as the features of the lessee’s economic environment (reflected in the country risk premium assigned to each country where Eni operates).
After the initial recognition, the lease liability is measured on an amortised cost basis and is remeasured, normally, as an adjustment to the carrying amount of the related right-of-use asset, to reflect changes to the lease payments due, essentially, to: (i) modifications in the lease contract not accounted as a separate lease; (ii) changes in indexes or rates (used to determine the variable lease payments); or (iii) changes in the assessment of contractual options (e.g. options to purchase the underlying asset, extension or termination options).
The right-of-use asset is initially measured at cost, which comprises: (i) the amount of the initial measurement of the lease liability; (ii) any initial direct costs incurred by the lessee19; (iii) any lease payments made at or before the commencement date, less any lease incentives received; and (iv) an estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease. After the initial recognition, the right-of-use asset is adjusted for any accumulated depreciation20, any accumulated impairment losses (see the accounting policy for “Impairment of non-financial assets”) and any remeasurement of the lease liability.
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
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13
The accounting policies related to leases have been defined on the basis of IFRS 16 “Leases” effective from January 1, 2019. As allowed by the accounting standard, the new requirements have been applied without restating the comparative years. The previous accounting policies about leases required essentially that: (i) assets held under finance lease, or under arrangements that did not take the legal form of a finance lease but substantially transferred all the risks and rewards incidental to ownership of the leased asset, were recognised, at the commencement of the lease, at their fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments, within property, plant and equipment as a contra account to a financing payable to the lessor; and (ii) lease payments under an operating lease were recognised as an expense over the lease term.
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14
As expressly provided for in IFRS 16, this accounting policy does not apply to leases to explore for and extract resources such as those for oil and gas rights, leases of land and any rights of way related to oil and gas activities.
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15
The assessment of whether the contract is, or contains, a lease is performed at the inception date, that is the earlier of the date of a lease agreement and the date of commitment by the parties to the principal terms and conditions of the lease.
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16
Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognising the lease payments associated with those leases as an expense on a straight-line basis over the lease term.
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17
Eni, in accordance with the practical expedient allowed by the accounting standard, does not separate non-lease components from lease components except for main contracts related to upstream activities (drilling rigs), which provide for single payments relating to both lease and non-lease components.
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18
Conversely, the other kinds of variable lease payments (e.g. payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability, but are recognised in the profit and loss account as operating expenses over the lease term.
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19
Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained.
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20
Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee by the end of the lease term, or if the cost of the right-of-use asset reflects that the lessee will exercise a purchase option, the right-of-use asset is depreciated from the commencement date to the end of the useful life of the underlying asset.
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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. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or other legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or together with other assets. An entity controls an intangible asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits.
Intangible assets are initially recognised at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes.
Intangible assets with finite useful lives are amortised on a systematic basis over their useful life; the amount to be amortised and the recoverability of the carrying amount are determined in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.
Goodwill and intangible assets with indefinite useful lives are not amortised. For the recoverability of the carrying amounts of the goodwill and other intangible assets see the accounting policy “Impairment of non-financial assets”.
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Costs of obtaining a contract with a customer are recognised on the balance sheet if the Company expects to recover those costs. The intangible asset arising from those costs is amortised on a systematic basis, that is consistent with the transfer to the customer of the goods or services to which the asset relates, and is tested for impairment21 .
Costs of technological development activities are capitalised when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits.
The carrying amount of intangible assets is derecognised on disposal or when no future economic benefits are expected from its use or disposal; any resulting gain or loss is recognised in the profit and loss account.
Impairment of non-financial assets
Non-financial assets (tangible assets, intangible assets and right-of-use assets) are tested for impairment whenever events or changes in circumstances indicate that the carrying amounts for those assets may not be recoverable.
The recoverability assessment is performed for each cash-generating unit (hereinafter also CGU) represented by the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or group of assets. CGUs are identified considering, inter alia, how management monitors the entity’s operations (such as by business lines) or how management makes decisions about continuing or disposing of the entity’s assets and operations.
Cash-generating units may include corporate assets which do not generate cash inflows independently of other assets or group of assets, allocable on a reasonable and consistent basis. Corporate assets not attributable to a single cash-generating unit are allocated to a group of cash-generating units. Goodwill is tested for impairment at least annually, and whenever there is any indication of impairment, at the lowest level within the entity at which it is monitored for internal management purposes. Right-of-use assets, which generally do not generate cash inflows independently of other assets or groups of assets, are allocated to the CGU to which they belong; the right-of-use assets which cannot be fully attributed to a CGU are considered as corporate assets.
The recoverability of 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
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21
The accounting policies adopted until 2017 (before applying IFRS 15) required the capitalisation of directly attributable customer acquisition costs when all the following conditions were met: (i) the capitalised costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenue from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.
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(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 recognised by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received.
Inventories
Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business less the estimated costs of completion and the estimated costs necessary to make the sale, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual selling price. Inventories which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell. 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.
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22
For the recognition criteria of forestry certificates see the accounting policy for “Costs”.
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23
Impairment losses recognised for goodwill in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognised in a smaller amount or would not have been recognised.
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When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations are measured using the pricing formulas contractually defined. They are recognised under “Other assets” as “Deferred costs” as a contra to “Other payables” or, after settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn — the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas, within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realisable value, determined adopting the same criteria described for inventories.
Significant accounting estimates and judgements: impairment of non-financial assets
The recoverability of non-financial assets is assessesed 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.
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24
The accounting policies related to financial instruments were defined on the basis of IFRS 9 “Financial Instruments” effective from 2018; as required by the accounting standard, the new requirements have been applied starting from January 1, 2018 without restating the comparative information. With reference to the financial instruments held by the Company, the previous accounting policies (applied until2017) required essentially: (i) the classification of financial assets on the basis of the categories under IAS 39; (ii) recognition and measurement of impairment losses if there was objective evidence that an impairment loss had been incurred (the so-called incurred loss model); and (iii) more stringent hedge accounting requirements (mainly referred to the assessment of hedge effectiveness).
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After initial recognition, financial assets whose contractual terms give rise to cash flows that are solely payments of principal and interest on the principal amount outstanding are measured at amortised cost if they are held within a business model whose objective is to hold financial assets in order to collect contractual cash flows (the so-called hold to collect business model). For financial assets measured at amortised cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses25 (see the accounting policy for “Impairment of financial assets”) are recognised in the profit and loss account.
Conversely, financial assets that are debt instruments are measured at fair value through OCI (hereinafter also FVTOCI) if they are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets (the so-called hold to collect and sell business model). In these cases: (i) interest income determined using the effective interest rate, foreign exchange differences and any impairment losses (see the accounting policy for “Impairment of financial assets”) are recognised in the profit and loss account; (ii) changes in fair value of the instruments are recognised in equity, within other comprehensive income. The accumulated changes in fair value, recognised in the equity reserve related to other comprehensive income, is reclassified to the profit and loss account when the financial asset is derecognised. Currently the Group does not have any financial assets measured at fair value through OCI.
A financial asset represented by a debt instrument that is neither measured at amortised cost nor at FVTOCI, is measured at fair value through profit or loss (hereinafter FVTPL); financial assets held for trading fall into this category. Interest income on assets held for trading contributes to the fair value measurement of the instrument and is recognised in “Finance income (expense)”, within “Net finance income (expense) from financial assets held for trading”.
When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date.
Impairment of financial assets
The expected credit loss model is adopted for the impairment of financial assets that are debt instruments, but are not measured at fair value through profit or loss.
In particular, the expected credit losses are generally measured by multiplying: (i) the exposure to the counterparty’s credit risk net of any collateral held and other credit enhancements (Exposure At Default, EAD); (ii) the probability that the default of the counterparty occurs (Probability of Default, PD); and (iii) the percentage estimate of the exposure that will not be recovered in case of default (Loss Given Default, LGD), considering the past experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.).
With reference to trade and other receivables, Probabilities of Default of counterparties are determined by adopting the internal credit ratings already used for credit worthiness and are periodically reviewed using, inter alia, back-testing analyses; for government entities (e.g. National Oil Companies), the Probability of Default, represented essentially by the probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for the impairment review of non-financial assets.
For customers without internal credit ratings, the expected credit losses are measured by using a provision matrix, defined by grouping, where appropriate, receivables into adequate clusters to which apply expected loss rates defined on the basis of their historical credit loss experiences, adjusted, where appropriate, to take into account forward-looking information on credit risk of the counterparty or clusters of counterparties.26
Considering the characteristics of the reference markets, financial assets with more than 180 days past due or, in any case, with counterparties undergoing litigation, restructuring or renegotiation, are considered to be in default. Counterparties are considered undergoing litigation when judicial/legal proceedings aimed
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25
Receivables and other financial assets measured at amortised cost are presented on the balance sheet net of their loss allowance.
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26
For credit exposures arising from intragroup transactions, the recovery rate is normally assumed equal to 100% taking into account, inter alia, the Group central treasury function which supports both financial and capital needs of subsidiaries.
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to recover a receivable have been activated or are going to be activated. Impairment losses of trade and other receivables are recognised in the profit and loss account, net of any impairment reversal, within the line item of the profit and loss account “Net (impairment losses) reversals of trade and other receivables”.
The financing receivables held for operating purposes, granted to associates and joint ventures, for which settlement is neither planned nor likely to occur in the foreseeable future and which in substance form part of the entity’s net investment in these investees, are tested for impairment, first, on the basis of the expected credit loss model and, then, together with the carrying amount of the investment in the associate/joint venture, in accordance with the criteria indicated in the accounting policy for “The equity method of accounting”. In applying the expected credit loss model, any adjustments to the carrying amount of long-term interest that arise from applying the accounting policy for “The equity method of accounting” are not taken into account.
Significant accounting estimates and judgements: impairment of financial assets
Measuring impairment losses of financial assets requires management evaluation of complex and highly uncertain elements such as, for example, Probabilities of Default of counterparties, the existence of any collateral or other credit enhancements, the expected exposure that will not be recovered in case of default, as well as the definition of customers’ clusters to be adopted.
Investments in equity instruments
Investments in equity instruments that are not held for trading are measured at fair value through other comprehensive income, without subsequent transfer of fair value changes to profit or loss on derecognition of these investments; conversely, dividends from these investments are recognised in the profit and loss account, within the line item “Income (Expense) from investments”, unless they clearly represent a recovery of part of the cost of the investment. In limited circumstances, an investment in equity instruments can be measured at cost if it is an appropriate estimate of fair value.
Financial liabilities
At initial recognition, financial liabilities, other than derivative financial instruments, are measured at their fair value, minus transaction costs that are directly attributable, and are subsequently measured at amortised cost.
Derivative financial instruments and hedge accounting
Derivative financial instruments, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value.
With reference to the defined risk management objectives and strategy, the qualifying criteria for hedge accounting requires: (i) the existence of an economic relationship between the hedged item and the hedging instrument in order to offset the related value changes and the effects of counterparty credit risk do not dominate the economic relationship between the hedged item and the hedging instrument; and (ii) the definition of the relationship between the quantity of the hedged item and the quantity of the hedging instrument (the so-called hedge ratio) consistent with the entity’s risk management objectives, under a defined risk management strategy; the hedge ratio is adjusted, where appropriate, after taking into account any adequate rebalancing. A hedging relationship is discontinued prospectively, in its entirety or a part of it, when it no longer meets the risk management objectives on the basis of which it qualified for hedge accounting, it ceases to meet the other qualifying criteria or after rebalancing it.
When derivatives hedge the risk of changes in the fair value of the hedged items (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured.
When derivatives hedge the exposure to variability in cash flows of the hedged items (cash flow hedge, e.g. hedging the variability in the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the effective changes in the fair value of the derivatives are initially recognised in the equity reserve
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related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account.
If a hedged forecast transaction subsequently results in the recognition of a non-financial asset or a non-financial liability, the accumulated changes in fair value of hedging derivatives, recognised in equity, are included directly in the carrying amount of the hedged non-financial asset/liability (commonly referred to as a “basis adjustment”).
The changes in the fair value of derivatives that are not designated as hedging instruments, including any ineffective portion of changes in fair value of hedging derivatives, are recognised in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognised in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognised in the profit and loss account line item “Other operating (expense) income”. Derivatives embedded in financial assets are not accounted for separately; in such circumstances, the entire hybrid instrument is classified depending on the contractual cash flow characteristics of the financial instrument and the business model for managing it (see the accounting policy for “Financial assets”). Derivatives embedded in financial liabilities and/or non-financial assets are separated if: (i) the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract; (ii) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and (iii) the entire hybrid contract is not measured at FVTPL.
Eni assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows occurs.
Contracts to buy or sell commodities entered into and continued to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognised on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).
Offsetting of financial assets and liabilities
Financial assets and liabilities are set off on the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realise the asset and settle the liability simultaneously).
Derecognition of financial assets and liabilities
Transferred financial assets are derecognised when the contractual rights to receive the cash flows from the financial assets expire or are transferred to another party. Financial liabilities are derecognised when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired.
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 liabilities and contingent assets
A provision is a liability of uncertain timing or amount on the balance sheet date. Provisions are recognised when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. The amount recognised as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties at the balance sheet date. The amount recognised for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued
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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 recognised as “Finance income (expense)”.
A provision for restructuring costs is recognised only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring.
Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognised in the same profit and loss account line item where the original provision was charged.
Contingent liabilities are: (i) possible obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent liabilities are not recognised in the financial statements, but are disclosed.
Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not recognised unless the realisation of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable.
Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements; if it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are 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
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
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27
These liabilities relate essentially to the Exploration & Production segment’s assets. The decommissioning and restoration liabilities associated with the Refining & Marketing and Chemical and Gas & Power segments’ assets are generally not recognised, as the obligations cannot be reliably estimated, given their indeterminate settlement dates. In this regard, Eni performs periodic reviews of Refining & Marketing and Chemical and Gas & Power segments’ tangible assets for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.
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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.
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 interest cost to be recognised in the profit and loss account. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognised in “Finance income (expense)”.
Remeasurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognised within the statement of comprehensive income. Remeasurements of the net defined benefit liability, recognised within other comprehensive income, are not reclassified subsequently to the profit and loss account.
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28
With reference to the environmental liabilities assumed, the expected operating costs to be incurred for managing groundwater treatment plants are not included in the estimates of environmental liabilities because it is not possible to reliably define a time horizon within which the operations of the plant will be terminated. In this regard, Eni performs periodic reviews for any changes in facts and circumstances, including changes in regulatory framework and technology, that might require the recognition of the environmental liability.
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Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of remeasurements are taken to profit and loss account in their entirety.
Share-based payments
The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistent with its actual remunerative nature.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 recognised as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognised in equity.
Revenue from contracts with customers
Revenue from contracts with customers is recognised on the basis of the following five steps: (i) identifying the contract with the customer; (ii) identifying the performance obligations, that are promises in a contract to transfer goods and/or services to a customer; (iii) determining the transaction price; (iv) allocating the transaction price to each performance obligation on the basis of the relative stand-alone selling prices of each good or service; and (v) recognising revenue when (or as) a performance obligation is satisfied, that is when a promised good or service is transferred to a customer. A promised good or service is transferred when (or as) the customer obtains control of it. Control can be transferred over time or at a
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29
The current share-based incentive plan, to be settled by treasury shares, was approved by the shareholders’ meeting held on April 13, 2017.
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point in time. With reference to the most important products sold by Eni, revenue is generally recognised for:
•
crude oil, upon shipment;
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•
natural gas and electricity, upon delivery to the customer;
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•
petroleum products sold to retail distribution networks, upon delivery to the service stations, whereas all other sales of petroleum products are recognised upon shipment; and
​
•
chemical products and other products, upon shipment.
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Revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers is recognised on the basis of the quantities actually lifted and sold (sales method); costs are recognised on the basis of the quantities actually sold.30
Revenue is measured at the fair value of the consideration to which the Company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third parties. In determining the transaction price, the promised amount of consideration is adjusted for the effects of the time value of money if the timing of payments agreed to by the parties to the contract provides the customer or the entity with a significant benefit of financing the transfer of goods or services to the customer. The promised amount of consideration is not adjusted for the effect of the significant financing component if, at contract inception, it is expected that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. If the consideration promised in a contract includes a variable amount, the Company estimates the amount of consideration to which it will be entitled in exchange for transferring the promised goods and/or services to a customer; in particular, the amount of consideration can vary because of discounts, refunds, incentives, price concessions, performance bonuses, penalties or if the price is contingent on the occurrence or non-occurrence of future events.
If, in a contract, the Company grants a customer the option to acquire additional goods or services for free or at a discount (e.g. sales incentives, customer award points, etc.), this option gives rise to a separate performance obligation in the contract only if the option provides a material right to the customer that it would not receive without entering into that contract. When goods or services are exchanged for goods or services which are of a similar nature and value, the exchange is not regarded as a transaction which generates revenue.
Significant accounting estimates and 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 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.
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30
In accordance with the accounting policy adopted until 2017 (entitlement method, before applying IFRS 15), revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers were recognised on the basis of Eni’s net working interest in those properties. On the balance sheet, lifting imbalances were recognised respectively as payables and receivables and measured at current prices at the balance sheet date.
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Costs
Costs are recognised when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) determined on the basis of market prices, are recognised in relation to the amounts of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights that exceed the amount necessary to meet regulatory obligations are recognised as intangible assets. Revenue related to emission quotas is recognised when they are sold. Monetary receivables granted to replace the free award emission rights are 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.
The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalised (see also the accounting policy for “Intangible assets”), are included in the profit and loss account when they are incurred.
Exchange differences
Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognised. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realisable value are retranslated using the exchange rate at the date when the value is determined.
Dividends
Dividends are recognised when the right to receive payment of the dividend is established.
Dividends and interim dividends to owners are shown as changes in equity when the dividends are declared by, respectively, the shareholders’ meeting and the Board of Directors.
Income taxes
Current income taxes are determined on the basis of estimated taxable profit. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period.
Deferred tax assets and liabilities are recognised for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets are recognised when their recoverability is considered probable, i.e. when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognised to the extent that their recoverability is probable. The carrying amount of the deferred tax assets is reviewed, at least, on an annual basis.
If there is uncertainty over income tax treatments, if the company concludes it is probable that the taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognised in the financial statements consistent with the tax treatment used or planned
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to be used in its income tax filings. Conversely, if the company concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognised in the financial statements.
Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognised if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets and liabilities are presented within non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognised in the line item “Deferred tax assets” and, if negative, in the line item “Deferred tax liabilities”. When the results of transactions are recognised 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 amounts will be recovered principally through a sale transaction rather than through their continuing use. This condition is regarded as met only when the sale is highly probable and the asset or the disposal group is available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale.
Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognised on the balance sheet separately from other assets and liabilities.
Immediately before the initial classification of a non-current asset and/or a disposal group as held for sale, the non-current asset and/or the assets and liabilities in the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated or amortised and they are measured at the lower of the fair value less costs to sell and their carrying amount. If an equity-accounted investment, or a portion of that investment meets the criteria to be classified as held for sale, it is no longer accounted for using the equity method and it is measured at the lower of its carrying amount at the date the equity method is discontinued, and its fair value less costs to sell. Any retained portion of the equity-accounted investment that has not been classified as held for sale is accounted for using the equity method until disposal of the portion that is classified as held for sale takes place. After the disposal, any retained interest in the investee is measured in accordance with the measurement criteria indicated in the accounting policy for “Investments in equity instruments”, unless the retained interest continues to be an equity-accounted investment.
Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognised up to the cumulative impairment losses, including those recognised prior to qualification of the asset as held
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for sale. Non-current assets classified as held for sale and disposal groups are considered a discontinued operation if they, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognised on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements.
If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortisation impairment losses and reversals that would have been recognised had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell. 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.
Fair value measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured.
A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximise the value of the asset.
The fair value of a liability, both financial and non-financial, or of the Company’s own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty’s credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the Company’s own credit risk for a financial liability (Debit Valuation Adjustment, DVA). In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximising the use of relevant observable inputs and minimising the use of unobservable inputs.
Significant accounting estimates and judgements: fair value
Fair value measurement, although based on the best available information and on the use of appropriate valuation techniques, is inherently uncertain, requires the use of professional judgement and could result in expected values other than the actual ones.
2 Primary financial statements31
Assets and liabilities on the balance sheet are classified as current and non-current. Items in the profit and loss account are presented by nature.32 Assets and liabilities are classified as current when: (i) they are expected to be realised/settled in the entity’s normal operating cycle or within twelve months after the
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31
The impacts on the primary financial statements arising from the adoption, starting from January 1, 2019, of the new IFRSs, as well as the other changes in the primary financial statements, are described in note 3 — Changes in accounting policies.
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32
Further information about classification of financial instruments is provided in note 27 — Guarantees, commitments and risks — Other information about financial instruments.
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balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be realised/​settled within twelve months after the balance sheet date; on the contrary they are classified as non-current.
The statement of comprehensive income (loss) shows net profit integrated with income and expenses that are not recognised directly in the profit and loss account according to IFRSs.
The statement of changes in 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.
3 Changes in accounting policies
Starting from January 1, 2019, Eni has applied IFRS 16 (hereinafter IFRS 16), which replaces IAS 17 and related interpretations. In particular, IFRS 16 eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial statements. Conversely, a lessor continues to classify its leases as either operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and lessors.
With reference to the lessee’s primary financial statements, starting from January 1, 2019:
-
on the balance sheet, right-of-use assets and lease liabilities are recognised and presented separately from other assets and other liabilities;
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-
in the 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 the construction of an asset are capitalised as part of the cost of such asset and subsequently recognised in the profit and loss account through depreciation/impairments or write-off, mainly in the case of exploration assets. 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;
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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 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 improvement of the 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 that are not capitalised34; (b) an improvement of the net cash used in investing activities, which no longer includes capitalised lease payments, but only includes cash payments for the capitalised interest portion of the lease liability; and (c) a worsening in the net cash used in financing activities, which includes cash payments for the principal portion of the lease liability.
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33
The prepayments for right-of-use assets, made before the commencement date of lease contracts, are classified within investing activities.
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34
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 measurement of lease liabilities; and (iii) payments for 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:
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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;
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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;
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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;
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-
possibility to exclude initial direct costs from the measurement of the right-of-use asset at January 1, 2019.
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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.
​
35
In previous reporting periods, income tax receivables and income tax payables were recognised within the non-current section of the balance sheet, respectively, in the line items “Other assets” and “Other liabilities”.
​
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On January 23, 2020, the IASB issued amendments to IAS 1 “Presentation of Financial Statements: Classification of Liabilities as Current 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.
Eni is currently reviewing the IFRSs not yet adopted in order to determine the likely impact on the Consolidated Financial Statements.
5 Cash and cash equivalents
Cash and cash equivalents of €5,994 million (€10,836 million at December 31, 2018) included financial assets with maturity generally of up to three months at the date of inception amounting to €3,984 million (€8,732 million at December 31, 2018) and mainly included short-term deposits in euro and U.S. dollars with financial institutions, having notice of more than 48 hours, to meet the Group’s short-term financing needs.
Restricted cash amounted to €198 million.
The average maturity of bank deposits in euro of €3,086 million was 9 days and the effective interest rate was a negative 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%.
6 Financial assets held for trading

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
Bonds issued by sovereign states | ​ | ​ | ​ | ​ | 1,462 | ​ | ​ | ​ | ​ | ​ | 1,083 | ​ | ​
Other | ​ | ​ | ​ | ​ | 5,298 | ​ | ​ | ​ | ​ | ​ | 5,469 | ​ | ​
​ | ​ | ​ | ​ | ​ | 6,760 | ​ | ​ | ​ | ​ | ​ | 6,552 | ​ | ​

The Company has established a liquidity reserve as part of its internal targets and financial strategy with a view of ensuring an adequate level of flexibility to the Group development plans and of coping with unexpected fund requirements or difficulties in accessing financial markets. The management of this liquidity reserve is performed through trading activities in view of the 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, 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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The breakdown by issuing entity and credit rating is presented below:

​ | ​ | ​ | Nominal value (€ million) | ​ | ​ | Fair Value (€ million) | ​ | ​ | Rating – Moody’s | ​ | ​ | Rating – S&P | ​
Quoted bonds issued by sovereign states | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed rate bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Italy | ​ | ​ | ​ | ​ | 734 | ​ | ​ | ​ | ​ | ​ | 743 | ​ | ​ | ​ | Baa3​ | ​ | ​ | BBB​ | ​
Chile | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | 181 | ​ | ​ | ​ | A1​ | ​ | ​ | A+​ | ​
Other(*) | ​ | ​ | ​ | ​ | 216 | ​ | ​ | ​ | ​ | ​ | 224 | ​ | ​ | ​ | from Aaa to Baa1​ | ​ | ​ | from AAA to BBB+​ | ​
​ | ​ | ​ | ​ | ​ | 1,127 | ​ | ​ | ​ | ​ | ​ | 1,148 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Floating rate bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Italy | ​ | ​ | ​ | ​ | 126 | ​ | ​ | ​ | ​ | ​ | 126 | ​ | ​ | ​ | Baa3​ | ​ | ​ | BBB​ | ​
Germany | ​ | ​ | ​ | ​ | 106 | ​ | ​ | ​ | ​ | ​ | 106 | ​ | ​ | ​ | Aaa​ | ​ | ​ | AAA​ | ​
Other(*) | ​ | ​ | ​ | ​ | 81 | ​ | ​ | ​ | ​ | ​ | 82 | ​ | ​ | ​ | from Aaa to Baa3​ | ​ | ​ | from AAA to BBB​ | ​
​ | ​ | ​ | ​ | ​ | 313 | ​ | ​ | ​ | ​ | ​ | 314 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total quoted bonds issued by sovereign states | ​ | ​ | ​ | ​ | 1,440 | ​ | ​ | ​ | ​ | ​ | 1,462 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other Bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed rate bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Quoted bonds issued by industrial companies | ​ | ​ | ​ | ​ | 1,183 | ​ | ​ | ​ | ​ | ​ | 1,212 | ​ | ​ | ​ | from Aa2 to Baa3​ | ​ | ​ | from AA to BBB-​ | ​
Quoted bonds issued by financial and insurance companies | ​ | ​ | ​ | ​ | 862 | ​ | ​ | ​ | ​ | ​ | 879 | ​ | ​ | ​ | from Aa3 to Baa3​ | ​ | ​ | from AA- to BBB-​ | ​
Other bonds | ​ | ​ | ​ | ​ | 105 | ​ | ​ | ​ | ​ | ​ | 106 | ​ | ​ | ​ | from Aaa to Baa2​ | ​ | ​ | from AAA to BBB​ | ​
​ | ​ | ​ | ​ | ​ | 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 | ​ | ​ | ​ | ​ | 1,116 | ​ | ​ | ​ | ​ | ​ | 1,122 | ​ | ​ | ​ | from Aa1 to Baa3​ | ​ | ​ | from AA+ to BBB-​ | ​
Other bonds | ​ | ​ | ​ | ​ | 444 | ​ | ​ | ​ | ​ | ​ | 444 | ​ | ​ | ​ | from Aaa to Baa2​ | ​ | ​ | from AAA to BBB​ | ​
​ | ​ | ​ | ​ | ​ | 3,090 | ​ | ​ | ​ | ​ | ​ | 3,101 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total other bonds | ​ | ​ | ​ | ​ | 5,240 | ​ | ​ | ​ | ​ | ​ | 5,298 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total other financial assets held for trading | ​ | ​ | ​ | ​ | 6,680 | ​ | ​ | ​ | ​ | ​ | 6,760 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

​
(*)
Amounts included herein are lower than €50 million.
​
The fair value hierarchy is level 1 for €6,219 million and level 2 for €541 million. During 2019, there were no transfers between the different hierarchy levels of fair value.
7 Trade and other receivables

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
Trade receivables | ​ | ​ | ​ | ​ | 8,519 | ​ | ​ | ​ | ​ | ​ | 9,520 | ​ | ​
Receivables from divestments | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 122 | ​ | ​
Receivables from joint ventures in exploration and production activities | ​ | ​ | ​ | ​ | 2,637 | ​ | ​ | ​ | ​ | ​ | 3,024 | ​ | ​
Other receivables | ​ | ​ | ​ | ​ | 1,687 | ​ | ​ | ​ | ​ | ​ | 1,435 | ​ | ​
​ | ​ | ​ | ​ | ​ | 12,873 | ​ | ​ | ​ | ​ | ​ | 14,101 | ​ | ​

Generally, trade receivables do not bear interest and provide payment terms within 180 days.
Trade receivables decreased by €1,001 million, of which €874 million related to the Gas & Power segment following a drop in prices and volumes of gas sold in the fourth quarter 2019 compared to the same period of 2018.
At December 31, 2019, Eni sold without recourse receivables due in 2020 for €1,782 million (€1,769 million at December 31, 2018 due in 2019). Derecognized receivables related to the Gas & Power segment for €1,369 million and to the Refining & Marketing and Chemical business line for €413 million.
Receivables from divestments decreased by €92 million during 2019 due to the collection of the last installment of €123 million related to the sale of a 10% interest in the Zohr asset in Egypt made to BP in 2017.
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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 allowed to recover about 45% of the original amount from the implementation of the agreement two years ago. The overdue receivable is stated net of a 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 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 (€300 million at December 31, 2018) of certain overdue trade receivables towards the state-owned oil company of Venezuela, PDVSA, in relation to gas equity volumes supplied by the joint venture Cardón IV, equally participated by Eni and Repsol. Those trade receivables were agreed to be transferred from the joint venture to the two shareholders. The receivables are stated net of 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 reflect the strategic value of the Oil&Gas sector, and also applied for assessing the recoverability of the carrying amount of the investment and the long-term interest in the initiative, as described in note 16 — Other financial assets.
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 has been prepared on the basis of internal ratings as follows:

​ | ​ | ​ | Performing receivables | ​ | ​ | Defaulted receivables | ​ | ​ | Eni gas e luce customers | ​ | ​ | Total | ​
(€ million) | ​ | ​ | Low risk | ​ | ​ | Medium Risk | ​ | ​ | High Risk | ​
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 risks. Business customers other than National Oil Companies (NOC) and 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
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payment, number of claims, etc.); (iii) presence of mitigation factors of the credit risk (e.g. securitization package, insurance against the credit risk, guarantee from third parties, etc.); (iv) other specialized pieces of information obtained by the Company’s business commercial departments or by specialized info-providers; (v) industrial and market trends. Internal ratings and the probability of default are constantly updated by means of back-testing analysis and risk assessment of the current credit portfolio. The loss given default associated with those industrial customers is estimated by the business departments based on the past experience in credit recoverability; in the case of defaulting customers, loss given default is estimated based on the recovery rates obtained in situations of credit restructurings or litigation procedures.
The probability of default associated with NOCs and public administrations is estimated based on the country risk premium incorporated in the risk-adjusted weighted average cost of capital utilized by the Company to perform the impairment review of its fixed assets. The loss given default of these business partners, essentially represented by the probability of a delay in repaying due amounts, is estimated based on historical averages of delays in collecting overdue receivables, substantially assessing the time value of money. The resulting loss given default is adjusted to factor in any existing mitigation factor. In case of particular market conditions or sovereign defaults, the expected loss associated with NOCs is re-rated based on the empirical evidence and outcomes obtained from restructuring of sovereign debts considering the specificities of trading relationships with energy companies. Customers of the Eni subsidiary “Eni gas e luce”, which engages in marketing gas and power to residential customers, were grouped into homogeneous clusters with different credit risk and probability of default which have been estimated based on past experience on credit collection, systematically updated and, in case of particular market conditions, adjusted to take into account expected market and credit trends in any given cluster.
The exposure to credit risk and expected losses relating to retail customers of the Gas & Power segment was assessed on the basis of a provision matrix as follows:

​ | ​ | ​ | Ageing | ​
(€ million) | ​ | ​ | Not-past due | ​ | ​ | from 0 to 3 months | ​ | ​ | from 3 to 6 months | ​ | ​ | from 6 to 12 months | ​ | ​ | over 12 months | ​ | ​ | Total | ​
December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Customers – Eni gas e luce: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Retail | ​ | ​ | ​ | ​ | 991 | ​ | ​ | ​ | ​ | ​ | 105 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | 376 | ​ | ​ | ​ | ​ | ​ | 1,618 | ​ | ​
- Middle | ​ | ​ | ​ | ​ | 93 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 263 | ​ | ​ | ​ | ​ | ​ | 403 | ​ | ​
- Other | ​ | ​ | ​ | ​ | 76 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 84 | ​ | ​
Gross amount | ​ | ​ | ​ | ​ | 1,160 | ​ | ​ | ​ | ​ | ​ | 137 | ​ | ​ | ​ | ​ | ​ | 65 | ​ | ​ | ​ | ​ | ​ | 102 | ​ | ​ | ​ | ​ | ​ | 641 | ​ | ​ | ​ | ​ | ​ | 2,105 | ​ | ​
Allowance for doubtful accounts | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | (27) | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​ | ​ | ​ | ​ | (49) | ​ | ​ | ​ | ​ | ​ | (548) | ​ | ​ | ​ | ​ | ​ | (666) | ​ | ​
Net amount | ​ | ​ | ​ | ​ | 1,144 | ​ | ​ | ​ | ​ | ​ | 110 | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 53 | ​ | ​ | ​ | ​ | ​ | 93 | ​ | ​ | ​ | ​ | ​ | 1,439 | ​ | ​
Expected loss (%) | ​ | ​ | ​ | ​ | 1.4 | ​ | ​ | ​ | ​ | ​ | 19.7 | ​ | ​ | ​ | ​ | ​ | 40.0 | ​ | ​ | ​ | ​ | ​ | 48.0 | ​ | ​ | ​ | ​ | ​ | 85.5 | ​ | ​ | ​ | ​ | ​ | 31.6 | ​ | ​
December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Customers – Eni gas e luce: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Retail | ​ | ​ | ​ | ​ | 575 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 64 | ​ | ​ | ​ | ​ | ​ | 554 | ​ | ​ | ​ | ​ | ​ | 1,276 | ​ | ​
- Middle | ​ | ​ | ​ | ​ | 449 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 349 | ​ | ​ | ​ | ​ | ​ | 883 | ​ | ​
- Other | ​ | ​ | ​ | ​ | 207 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 215 | ​ | ​
Gross amount | ​ | ​ | ​ | ​ | 1,231 | ​ | ​ | ​ | ​ | ​ | 94 | ​ | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | 95 | ​ | ​ | ​ | ​ | ​ | 906 | ​ | ​ | ​ | ​ | ​ | 2,374 | ​ | ​
Allowance for doubtful accounts | ​ | ​ | ​ | ​ | (20) | ​ | ​ | ​ | ​ | ​ | (18) | ​ | ​ | ​ | ​ | ​ | (18) | ​ | ​ | ​ | ​ | ​ | (56) | ​ | ​ | ​ | ​ | ​ | (745) | ​ | ​ | ​ | ​ | ​ | (857) | ​ | ​
Net amount | ​ | ​ | ​ | ​ | 1,211 | ​ | ​ | ​ | ​ | ​ | 76 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 161 | ​ | ​ | ​ | ​ | ​ | 1,517 | ​ | ​
Expected loss (%) | ​ | ​ | ​ | ​ | 1.6 | ​ | ​ | ​ | ​ | ​ | 19.1 | ​ | ​ | ​ | ​ | ​ | 37.5 | ​ | ​ | ​ | ​ | ​ | 58.9 | ​ | ​ | ​ | ​ | ​ | 82.2 | ​ | ​ | ​ | ​ | ​ | 36.1 | ​ | ​
​

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Trade and other receivables are stated net of the allowance for doubtful accounts which has been determined considering the counterparty risk mitigation factors amounting to €2,914 million (€3,072 million at December 31, 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 Exploration & Production segment for €339 million (€291 million in 2018) and were in relation with receivables for the supply of equity hydrocarbons to State-owned companies and receivables towards joint operators for cash calls in oil projects operated by Eni.
Utilizations of allowance for doubtful accounts on trade and other performing and defaulted receivables amounted to €603 million (€721 million in 2018) and mainly related to the 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 retail business. The mitigation measures regarding the counterparty risk executed by the Company, including better customer selection, allowed to reduce the incidence of unpaid amounts on retail sales of gas and power to physiological levels. Utilizations in Exploration & Production segment of €177 million (€66 million in 2018) related to the progress in the collection of overdue amounts for cash calls.
Net (impairment losses) reversals of trade and other receivables 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 disclosed in note 36 — Transactions with related parties.
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8 Non-current and current inventories
Current inventories 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 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 €1,359 million (€1,334 million at December 31, 2018).
Finished products and goods included gas and petroleum products for €1,467 million (€1,543 million at December 31, 2018) and chemical products for €547 million (same amount at December 31, 2018).
Certificates and emission rights are measured at the fair value based on market prices. The fair value hierarchy is level 1.
Inventories of €95 million (same amount at December 31, 2018) were pledged to guarantee the estimated imbalance in volumes input to/off-taken from the national gas network operated by Snam Rete Gas SpA.
Inventories are stated net of 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 likely outcome of pending litigation with tax authorities in relation to uncertain tax matters relating to foreign subsidiaries of the Exploration & Production segment for €362 million (€255 million at December 31, 2018).
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10 Other assets and liabilities

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
​ | Assets | ​ | ​ | Liabilities | ​ | ​ | Assets | ​ | ​ | Liabilities | ​
​ | Current | ​ | ​ | Non-current | ​ | ​ | Current | ​ | ​ | Non-current | ​ | ​ | Current | ​ | ​ | Non-current | ​ | ​ | Current | ​ | ​ | Non-current | ​
Fair value of derivative financial instruments | ​ | ​ | ​ | ​ | 2,573 | ​ | ​ | ​ | ​ | ​ | 54 | ​ | ​ | ​ | ​ | ​ | 2,704 | ​ | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 1,594 | ​ | ​ | ​ | ​ | ​ | 68 | ​ | ​ | ​ | ​ | ​ | 1,445 | ​ | ​ | ​ | ​ | ​ | 40 | ​ | ​
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 | ​ | ​
​ | ​ | ​ | ​ | ​ | 3,972 | ​ | ​ | ​ | ​ | ​ | 871 | ​ | ​ | ​ | ​ | ​ | 7,146 | ​ | ​ | ​ | ​ | ​ | 1,611 | ​ | ​ | ​ | ​ | ​ | 2,819 | ​ | ​ | ​ | ​ | ​ | 624 | ​ | ​ | ​ | ​ | ​ | 5,412 | ​ | ​ | ​ | ​ | ​ | 1,475 | ​ | ​

The fair value related to derivative financial instruments is disclosed in note 23 — Derivative financial instruments and hedge accounting.
Assets related to other current taxes refer to VAT for €742 million, of which €557 million are current, and related to advances made in December (€608 million at December 31, 2018, of which €383 million current).
Other assets include: (i) gas volumes prepayments that were made in previous years due to the take-or-pay obligations in relation to the Company’s long-term supply contracts of €174 million (€26 million at December 31, 2018); in 2019 the Company opted to increase the take-or-pay advance with a view of optimizing its gas portfolio, expecting to recover the underlying 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 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, 2018); the non-current portion amounted to €455 million (€518 million at December 31, 2018).
Other current liabilities included overlifting imbalances of the Exploration & Production segment for €917 million (€1,004 million at December 31, 2018).
Liabilities related to other current taxes include excise duties and consumer taxes for €628 million (€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 supply of gas and electricity of €231 million (€233 million at December 31 2018).
Transactions with related parties are described in note 36 — Transactions with related parties.
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11 Property, plant and equipment

(€ million) | ​ | ​ | Land and buildings | ​ | ​ | E&P wells, plant and machinery | ​ | ​ | Other plant and machinery | ​ | ​ | E&P exploration assets and appraisal | ​ | ​ | E&P tangible assets in progress | ​ | ​ | Other tangible assets in progress and advances | ​ | ​ | Total | ​
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 depreciation
​
Capital expenditures included capitalized finance expenses of €93 million (€52 million in 2018) related to the Exploration & Production segment for €71 million (€37 million in 2018). The interest rate used for capitalizing finance expense ranged from 2.6% to 2.8% (2.3% to 2.4% at December 31, 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 | ​ | ​
Mineral exploration wells and plants | ​ | ​ | ​ | ​ | UOP | ​ | ​
Refining and chemical plants | ​ | ​ | ​ | ​ | 3 – 17 | ​ | ​
Gas pipelines and compression stations | ​ | ​ | ​ | ​ | 4 – 12 | ​ | ​
Power plants | ​ | ​ | ​ | ​ | 4 – 5 | ​ | ​
Other plant and machinery | ​ | ​ | ​ | ​ | 6 – 12 | ​ | ​
Industrial and commercial equipment | ​ | ​ | ​ | ​ | 5 – 25 | ​ | ​
Other assets | ​ | ​ | ​ | ​ | 10 – 20 | ​ | ​
​

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The criteria adopted by Eni for determining impairment losses and reversal is reported in note 14 — Impairment review of tangible and intangible assets and right-of-use assets.
Foreign currency translation differences primarily related to subsidiaries which utilize the U.S. dollar as functional currency (€976 million).
Initial recognition and 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 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 year. Changes relating to suspended wells 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 (ageing):

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

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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 as follows:

(€ 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 interests comprised a property denominated Oil Prospecting License 245 (OPL 245), offshore Nigeria, with a net book value of €874 million corresponding to the price paid in 2011 to the Nigerian Government to acquire a 50% interest in the property, together with the partner Shell which acquired the remaining 50%. As of December 31, 2019, the net book value of the property amounted to €1,184 million, including capitalized exploration 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 27 — Guarantees, Commitments and Risks. The impairment test of the asset confirmed the book value also considering a stress test assuming possible delays in the start of development activities.
Accumulated provisions for impairments amounted to €18,226 million (€16,471 million at December 31, 2018).
Property, plant and equipment include assets subject to leases for €241 million.
At December 31, 2019, Eni pledged property, plant and equipment for €24 million to guarantee payments of excise duties (same amount as of December 31, 2018).
Government grants recorded as a decrease of property, plant and equipment amounted to €112 million (€125 million at December 31, 2018).
Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 27 — Guarantees, commitments and risks — Liquidity risk.
Property, plant and equipment under concession arrangements are described in note 27 — Guarantees, commitments and risks — Assets under concession arrangements.
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12 Right-of-use assets and lease liabilities

(€ million) | ​ | ​ | Floating production storage and offloading vessels (FPSO) | ​ | ​ | Drilling rig | ​ | ​ | Naval facilities and related logistic bases for oil and gas transportation | ​ | ​ | Motorway concessions and service stations | ​ | ​ | Oil and gas distribution facilities | ​ | ​ | Office buildings | ​ | ​ | Vehicles | ​ | ​ | Other | ​ | ​ | Total | ​
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) | ​ | ​ | 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 comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on UOP criteria and are regularly reviewed for impairment. Furthermore, they include the cost of unproved areas which are suspended pending a final determination of the success of the exploration activity or until management confirms its commitment to the initiative. Additions for the year related to signature bonuses paid for the acquisition of new exploration acreage mainly in United Arab Emirates, Mozambique, Mexico and Indonesia.
The breakdown of exploration rights by type of asset was as follows:

(€ 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 mainly regarded the acquisition and internal development of software and rights for the use of production processes and software.
Other intangible assets comprised: (i) customer acquisition costs relating to the retail gas business for €226 million (€166 million at December 31, 2018); (ii) concessions, licenses, trademarks and similar items for €102 million (€151 million at December 31, 2018) comprised transmission rights for natural gas imported from Algeria of €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 €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 | ​ | ​ | ​ | ​ | UOP – 33 | ​ | ​
Transport rights of natural gas | ​ | ​ | ​ | ​ | 3 | ​ | ​
Other concessions, licenses, trademarks and similar items | ​ | ​ | ​ | ​ | 3 – 33 | ​ | ​
Service concession arrangements | ​ | ​ | ​ | ​ | 20 – 33 | ​ | ​
Capitalized costs for customer acquisition | ​ | ​ | ​ | ​ | 25 – 33 | ​ | ​
Other intangible assets | ​ | ​ | ​ | ​ | 4 – 20 | ​ | ​

The carrying amount of goodwill at the end of the year amounted €2,454 million, net of cumulative impairments charges. The breakdown by segment is provided below:

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
Gas & Power | ​ | ​ | ​ | ​ | 981 | ​ | ​ | ​ | ​ | ​ | 977 | ​ | ​
Exploration & Production | ​ | ​ | ​ | ​ | 190 | ​ | ​ | ​ | ​ | ​ | 187 | ​ | ​
Refining & Marketing and Chemicals | ​ | ​ | ​ | ​ | 93 | ​ | ​ | ​ | ​ | ​ | 119 | ​ | ​
Other activities | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | ​ | ​ | ​ | ​ | 1,265 | ​ | ​ | ​ | ​ | ​ | 1,284 | ​ | ​

An impairment loss of the entire allocated goodwill was recorded by the Chemical business line in relation to activities concerning the development, industrialization, licensing of bio-chemical technologies and processes based on the use of renewable sources.
An increase in goodwill was recorded in connection with the allocation of the acquisition cost of the company SEA SpA, which engages in providing services and solutions for energy efficiency in the residential and industrial segments.
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.
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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 the allocated goodwill.
In assessing the recoverability of the carrying amount of the CGU domestic gas market, including the allocated portion of goodwill, management determined the value in use of the CGU considering the sales margin exclusively of the retail market (excluding 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 a terminal value calculated as perpetuity of the last year of the plan by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of 5.3% for Italy. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.
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 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 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 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 cannot be reversed.
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 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 CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields when technical, economic or contractual features make underlying cash flows interdependent; (ii) in the 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) in the Refining & Marketing business line, refining plants, and 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 Chemical business five lines of activities have been identified as autonomous CGUs: intermediates, polyethylene, styrenes, elastomers and biotech activities.
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As of 2019, following the application of IFRS 16, the book values of the identified CGUs include the right of use assets (RoU), associated to plants and 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 unlevered valuation methodology used for capital projects. Rather, a small number of RoU not allocated to CGU are considered corporate assets, whose recoverability depends on the whole of the company’s CGUs.
The value-in-use is calculated by discounting the estimated future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from disposal 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 so-called CO2 Emission Trading Scheme applicable to CGUs operating within the EU economic space. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns.
The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair.
The oil market continues to be affected by weak fundamentals against the backdrop of an unabated supply glut, fueled by continuing grow in U.S. tight oil output and a seemingly fading commitment on part of the oil producers of the OPEC+ agreement at supporting crude oil prices going forward. The market is also weighed down by uncertainties about the strength of the global economic recovery, exposed to a wide range of systemic risks, including geopolitical risks, any possible development in the trade dispute between USA and China, the relationship between the EU and the UK post Brexit. Eni’s management forecast a gradual rebalancing of global supplies and demand for crude oil over the medium term, under the assumptions of moderate economic growth and taking into account the stricter capital discipline adopted 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 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 Asian economies and also considering an ongoing switch from coal to gas in the power generation in Europe. Overall, price assumptions for the main gas benchmarks in Europe have been retained at the same level as the previous planning projections, whilst gas prices assumptions have been revised downward for the reference Henry Hub gas prices in USA due to structural headwinds.
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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 G&P fixed assets (particularly the goodwill recorded in the retail segment).
The Company’s downstream businesses of the refining and the petrochemicals sectors are currently in a down-cycle due to weak end-demands, excess production capacity and 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 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 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 the light benchmark Brent crude, thus impairing the cost-advantage of 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 and by this way reduced the 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 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.
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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 UAE downstream sector and increases its global refining capacity by 35%, in line with the Company’s strategy of making Eni’s overall portfolio more geographically diversified and more balanced along the value chain; (ii) a capital contribution of €39 million made to Lotte Versalis Elastomers Co Ltd, joint venture operating in 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 Saipem shares and the ongoing uncertainties surrounding a recovery in the investing cycle of oil companies and competitive pressure in the Engineering & Construction segment, management performed an impairment review of the investment to assess its recoverability based on an internal financial model of future cash flows of Saipem. Inputs to that model were estimated based on financial projections made by the sell-side analysts who cover the Saipem shares, publicly available data on Saipem and the observed historical correlation which link the Saipem turnover to crude oil prices and spending in capital projects made by oil companies. This review supported the book value of the investment.
Share of losses of equity-accounted investments 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 companies:

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

​
(a)
The ownership cannot be determined.
​
(*)
Each individual amount included herein was lower than €25 million.
​
As of December 31, 2019, the book value of investments included Vår Energi SA which was established at the end of 2018 following the merger between the former Eni subsidiary Eni Norge AS and Point Resources AS for maximizing synergies in the development of hydrocarbon reserves in Norway through the sharing of assets and know-how. The decrease of €980 million compared to the opening balance was due to the distribution of dividends classified as part of the cash flow from operating activities considering that Vår Energi SA is an investment integrated in the industrial plans and the upstream growth strategy of Eni. This decrease was partially absorbed by Eni’s share of profit.
Results of equity-accounted investments by segment are disclosed in note 35 — Segment information and information by geographical area.
The carrying amounts of equity-accounted investments included differences between the purchase price of acquired interests and their underlying book value of net assets amounting to €72 million, related to Novamont SpA for €43 million and Unión Fenosa Gas SA for €29 million. These surpluses were driven by the long-term profitability outlook of the acquired companies at the time of the acquisition.
As of December 31, 2019, the market value of the investments listed in regulated stock markets was as follows:

​ | ​ | ​ | Saipem SpA | ​
Number of shares held | ​ | ​ | ​ | ​ | 308,767,968 | ​ | ​
% of the investment | ​ | ​ | ​ | ​ | 30.99 | ​ | ​
Share price (€) | ​ | ​ | ​ | ​ | 4.356 | ​ | ​
Market value (€ million) | ​ | ​ | ​ | ​ | 1,345 | ​ | ​
Book value (€ million) | ​ | ​ | ​ | ​ | 1,250 | ​ | ​
​

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

(€ 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 | ​ | ​

The fair value of the main non-controlling interests in non-listed investees on regulated markets, classified within level 3 of the fair value hierarchy, was estimated based on a methodology that combines future expected earnings and the sum-of-the-parts methodology (so-called residual income approach) and takes into account, inter alia, the following inputs: (i) expected results, as a gauge of the future profitability of the investees, derived from the business plans, but adjusted, where appropriate, to include the assumptions that market participants would incorporate; (ii) the cost of capital, adjusted to include the risk premium of the specific country in which each investee operates. A stress test based on a 1% change in the cost of capital considered in the valuation did not produce significant changes at the fair value evaluation.
Dividend income from these investments is disclosed in note 31 — Income (expense) from investments.
The investment book value as of December 31, 2019 primarily related to 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 Exploration & Production segment (€1,041 million) and the Gas & Power segment (€49 million) to execute capital projects of interest to Eni. These receivables are expression of
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long-term interests in the initiatives funded. The greatest exposure is towards the joint venture Cardón IV SA (Eni’s interest 50%) in Venezuela, which is currently operating the Perla offshore gas field, for €563 million at December 31, 2019 (€705 million at December 31, 2018).
Financing receivables held for operating purposes due beyond five years amounted to €1,018 million (€1,088 million at December 31, 2018).
The fair value of non-current financing receivables held for operating purposes of €1,119 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from -0.3% to 2.0% (-0.2% and 2.9% at December 31, 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 held for operating purposes related to listed bonds issued by sovereign states.
Securities for €20 million (same amount at December 31, 2018) were pledged as guarantee of the deposit for gas cylinders as provided for by the Italian law.
The following table analyses securities per issuing entity:

​ | ​ | ​ | Amortized cost (€ million) | ​ | ​ | Nominal value (€ million) | ​ | ​ | Fair Value (€ million) | ​ | ​ | Nominal rate of return (%) | ​ | ​ | Maturity date | ​ | ​ | Rating- Moody’s | ​ | ​ | Rating- S&P | ​
Sovereign states | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed rate bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Italy | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | from 0.20 to 4.75​ | ​ | ​ | from 2020 to 2025​ | ​ | ​ | Baa3​ | ​ | ​ | BBB​ | ​
Others (*) | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | from 0.05 to 4.20​ | ​ | ​ | from 2020 to 2024​ | ​ | ​ | from Aa3 to Baa1​ | ​ | ​ | from AA to A-​ | ​
Floating rate bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Italy | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | from 2020 to 2022​ | ​ | ​ | Baa3​ | ​ | ​ | BBB​ | ​
Others | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | ​ | 2022​ | ​ | ​ | Baa3​ | ​ | ​ | BBB​ | ​
Total sovereign states | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

​
(*)
Amounts included herein are lower than €10 million.
​
All securities have maturity within five years.
The fair value of securities was derived from quoted market prices.
Receivables with related parties are described in note 36 — Transactions with related parties.
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17 Trade and other payables​
The 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 3 — 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 | ​ | ​

Trade and other payables were denominated in euro for €5,866 million and in U.S. dollar for €8,371 million.
Because of the short-term maturity and conditions of remuneration of trade and other payables, the fair values approximated the carrying amounts.
Payables due to related parties are described in note 36 — Transactions with related parties.
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 | ​ | ​

Finance debts decreased of €1,347 million due to repayments made net of new issuance of €1,540 million and increased due to currency translation differences relating to foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €249 million.
Commercial papers were issued by the Group’s financial subsidiaries.
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The following table reflects long-term debt as of December 31, 2019 by maturity:

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

Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the retention of a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees could be required to be agreed upon with the European Investment Bank. In addition, Eni entered into long-term facilities subject to the retention of certain financial ratios based on the Consolidated Financial Statements of Eni with Citibank Europe Plc. In case of default, the bank may request early repayment. At December 31, 2019, debts subjected to restrictive covenants amounted to €1,243 million (€1,337 million at December 31, 2018). Eni was in compliance with those covenants.
Ordinary bonds consisted of bonds issued within the Euro Medium Term Notes Program for a total of €15,030 million and other bonds for a total of €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, 2019:

(€ million) | ​ | ​ | Amount | ​ | ​ | Discount on bond issue and accrued expense | ​ | ​ | Total | ​ | ​ | Currency | ​ | ​ | Maturity | ​ | ​ | Rate % | ​
​ | from | ​ | ​ | to | ​ | ​ | from | ​ | ​ | to | ​
Issuing entity | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Euro Medium Term Notes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 1,200 | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | 1,216 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2025 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3.750 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​ | ​ | ​ | ​ | 1,038 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2020 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.250 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​ | ​ | ​ | ​ | 1,028 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2029 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3.625 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 1,020 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2020 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.000 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 1,010 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2023 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3.250 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 1,008 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2026 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.500 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 900 | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​ | ​ | ​ | ​ | 896 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2024 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.625 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 800 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 802 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2021 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2.625 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 800 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | 799 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2028 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.625 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 750 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | 759 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2024 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.750 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 750 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 755 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2027 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.500 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 750 | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​ | ​ | ​ | ​ | 746 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2034 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.000 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 700 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 702 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2022 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 0.750 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 650 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 653 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2025 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.000 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 600 | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​ | ​ | ​ | ​ | 596 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2028 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.125 | ​ | ​
Eni Finance International SA | ​ | ​ | ​ | ​ | 1,558 | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | 1,555 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | 2026 | ​ | ​ | ​ | ​ | ​ | 2027 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | variable | ​ | ​
Eni Finance International SA | ​ | ​ | ​ | ​ | 295 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 299 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | 2028 | ​ | ​ | ​ | ​ | ​ | 2043 | ​ | ​ | ​ | ​ | ​ | 3.875 | ​ | ​ | ​ | ​ | ​ | 5.441 | ​ | ​
Eni Finance International SA | ​ | ​ | ​ | ​ | 118 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 123 | ​ | ​ | ​ | ​ | ​ | GBP | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2021 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.750 | ​ | ​
Eni Finance International SA | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | YEN | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2021 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1.955 | ​ | ​
​ | ​ | ​ | ​ | ​ | 14,896 | ​ | ​ | ​ | ​ | ​ | 134 | ​ | ​ | ​ | ​ | ​ | 15,030 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other bonds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 890 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 894 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2023 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.000 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 890 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 892 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2028 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.750 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 890 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | 889 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2029 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.250 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 401 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 405 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2020 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4.150 | ​ | ​
Eni SpA | ​ | ​ | ​ | ​ | 312 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 313 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2040 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5.700 | ​ | ​
Eni USA Inc | ​ | ​ | ​ | ​ | 356 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 356 | ​ | ​ | ​ | ​ | ​ | USD | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2027 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7.300 | ​ | ​
​ | ​ | ​ | ​ | ​ | 3,739 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 3,749 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 18,635 | ​ | ​ | ​ | ​ | ​ | 144 | ​ | ​ | ​ | ​ | ​ | 18,779 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

As of December 31, 2019, ordinary bonds maturing within 18 months amounted to €2,611 million. During 2019, new bonds 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, 2019:

(€ million) | ​ | ​ | Amount | ​ | ​ | Discount on bond issue and accrued expense | ​ | ​ | Total | ​ | ​ | Currency | ​ | ​ | Maturity | ​ | ​ | Rate % | ​
Eni SpA | ​ | ​ | ​ | ​ | 400 | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | ​ | ​ | ​ | 393 | ​ | ​ | ​ | ​ | ​ | EUR | ​ | ​ | ​ | ​ | ​ | 2022 | ​ | ​ | ​ | ​ | ​ | 0.000 | ​ | ​

The non-dilutive equity-linked bond provides for a redemption value linked to the market price of Eni’s shares. The bondholders have “conversion” rights at certain times and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, to hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The bond conversion price is equal €17.62 and includes a 35% premium with respect to the Eni’s share reference price at the date of issuance. The convertible bond is measured at amortized cost. The conversion option, embedded in the financial instrument issued, and the call option on Eni’s shares acquired are valued at fair value with effects recognized through profit and loss.
Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €14.9 billion were drawn as of December 31, 2019.
The following table provides a breakdown by currency of finance debt and 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 undrawn 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 marketplace. As of December 31, 2019, Eni was in compliance with covenants and other contractual provisions in relation to borrowing facilities.
Fair value of long-term debt, including the current portion of long-term debt is described below:

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
Ordinary bonds | ​ | ​ | ​ | ​ | 19,173 | ​ | ​ | ​ | ​ | ​ | 20,257 | ​ | ​
Convertible bonds | ​ | ​ | ​ | ​ | 402 | ​ | ​ | ​ | ​ | ​ | 399 | ​ | ​
Banks | ​ | ​ | ​ | ​ | 2,904 | ​ | ​ | ​ | ​ | ​ | 3,445 | ​ | ​
Other financial institutions | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 111 | ​ | ​
​ | ​ | ​ | ​ | ​ | 22,528 | ​ | ​ | ​ | ​ | ​ | 24,212 | ​ | ​

Fair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from -0.3% to 2.0% (-0.2% and 2.9% at December 31, 2018).
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 less: cash and cash equivalents, held-for-trading securities and certain highly-liquid investments not related to operations including, among others, non-operating financing receivables. Held-for-trading securities are part of a strategic reserve of liquidity that management has established by reinvesting proceeds from the Group disposal plans and is intended to provide a certain degree of financial flexibility in case of a prolonged price downturn, tight financial markets or in view of other Company’s purposes. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.
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Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed.

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

Cash and cash equivalent are disclosed in note 5 — Cash and cash equivalent.
Financial assets held for trading are disclosed in note 6 — Financial assets held for trading.
Financing receivables are disclosed in note 16 — Other financial assets.
Finance debts are disclosed in note 18 — Finance debts.
Liabilities for leased assets related for €1,976 million to the share of joint operators in upstream projects operated by Eni which will be recovered through a partner cash-call billing process. More information is reported in note 12 — Right-of-use assets and lease liabilities.
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 | ​ | ​

Provisions for site restoration, abandonment and social projects include the present value of the estimated costs that the Company expects to incur for 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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Exploration & Production segment for €8,411 million. Initial recognitions and changes in estimates of €2,074 million were mainly driven by a decrease in the discount rate curve and to a lesser extent by the recognition of new decommissioning obligations due to the activity of the year. The unwinding of discount recognized through profit and loss for €247 million was determined based on discount rates ranging from -0.1% to 6.1% (from -0.2% to 6.1% at December 31, 2018). Main expenditures associated with decommissioning operations are expected to be incurred over a 45-year period.
Provisions for environmental risks included the estimated costs for environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. The provision was accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out environmental clean-up and remediation and the expected costs can be estimated reliably. The provision included the expected charges associated with strict liability related to obligations of cleaning up and remediating polluted areas that met the parameters set by the law at the time when the pollution occurred but presently are no more in compliance with current environmental laws and regulations, or because Eni assumed the liability borne by other operators when the Company acquired or otherwise took over site operations. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to performing certain cleaning-up and restoration projects and a reliable cost estimation is available. At December 31, 2019, environmental provision primarily related to Eni Rewind SpA (former Syndial SpA) for €1,930 million and to the Refining & Marketing business line for €416 million which includes the costs of restoration and environmental remediation as a part of the Memorandum of Understanding signed between Eni and the Ministry for the Environment in December 2019.
Litigation provisions comprised expected liabilities associated with legal proceedings and other matters arising from contractual claims, including arbitrations, fines and penalties due to antitrust proceedings and administrative matters. These provisions represent the Company’s best estimate of the expected and probable liabilities associated with ongoing litigation and related to the Exploration & Production segment for €723 million.
Provisions for taxes other than income taxes related to the estimated losses that the Company expects to incur to settle uncertain tax matters and tax claims pending with tax authorities in relation to uncertainties in applying rules in force for foreign subsidiaries of the Exploration & Production segment for €169 million.
Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC represented the estimated liabilities accrued on the basis for third party claims. Against such liability was recorded receivables of €162 million recognized towards insurance companies for reinsurance contracts.
Provisions for losses on investments included provisions relating to investments whose loss exceeds the equity and primarily related to Industria Siciliana Acido Fosforico — ISAF — SpA (in liquidation) for €131 million.
Provisions for the OIL mutual insurance scheme included the estimated future increase of insurance premiums which will be charged to Eni in the next five years and that were accrued at the reporting date because of the effective accident rate occurred in past reporting periods.
Provisions for redundancy incentives were recognized mainly due to a restructuring program involving the Italian personnel related to past reporting periods.
21 Provisions for employee benefits​

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
Italian defined benefit plans | ​ | ​ | ​ | ​ | 269 | ​ | ​ | ​ | ​ | ​ | 275 | ​ | ​
Foreign defined benefit plans | ​ | ​ | ​ | ​ | 412 | ​ | ​ | ​ | ​ | ​ | 385 | ​ | ​
FISDE, foreign medical plans and other | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​
Defined benefit plans | ​ | ​ | ​ | ​ | 858 | ​ | ​ | ​ | ​ | ​ | 808 | ​ | ​
Other benefit plans | ​ | ​ | ​ | ​ | 278 | ​ | ​ | ​ | ​ | ​ | 309 | ​ | ​
Provision for employee benefits | ​ | ​ | ​ | ​ | 1,136 | ​ | ​ | ​ | ​ | ​ | 1,117 | ​ | ​
​

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The liability relating to Eni’s commitment to cover the healthcare costs of personnel is determined on the basis of the contributions paid by the Company.
Other employee benefit plans related to deferred monetary incentive plans for €132 million, the isopensione plans (a post retirement benefit plan applicable to a specific category of employees) of Eni gas e luce SpA for €107 million, jubilee awards for €25 million and other long-term plans for €14 million.
Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Defined benefit plans | ​ | ​ | Other benefit plans | ​ | ​ | Total | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Defined benefit plans | ​ | ​ | Other benefit plans | ​ | ​ | Total | ​
Present value of benefit liabilities at beginning of year | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 925 | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 1,348 | ​ | ​ | ​ | ​ | ​ | 309 | ​ | ​ | ​ | ​ | ​ | 1,657 | ​ | ​ | ​ | ​ | ​ | 284 | ​ | ​ | ​ | ​ | ​ | 997 | ​ | ​ | ​ | ​ | ​ | 135 | ​ | ​ | ​ | ​ | ​ | 1,416 | ​ | ​ | ​ | ​ | ​ | 194 | ​ | ​ | ​ | ​ | ​ | 1,610 | ​ | ​
Current cost | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 76 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 27 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 42 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​
Interest cost | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 44 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 45 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 31 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​
Remeasurements: | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 41 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 70 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | (25) | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | (11) | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​
- actuarial (gains) losses due to changes in financial assumptions | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 61 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | (30) | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​
- experience (gains) losses | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | (9) | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​
Past service cost and (gains) losses settlements | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 118 | ​ | ​
Plan contributions: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- employee contributions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
Benefits paid | ​ | ​ | ​ | ​ | (15) | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​ | ​ | ​ | ​ | (9) | ​ | ​ | ​ | ​ | ​ | (52) | ​ | ​ | ​ | ​ | ​ | (88) | ​ | ​ | ​ | ​ | ​ | (140) | ​ | ​ | ​ | ​ | ​ | (15) | ​ | ​ | ​ | ​ | ​ | (35) | ​ | ​ | ​ | ​ | ​ | (9) | ​ | ​ | ​ | ​ | ​ | (59) | ​ | ​ | ​ | ​ | ​ | (74) | ​ | ​ | ​ | ​ | ​ | (133) | ​ | ​
Reclassification to liabilities directly associated with asset held for sale | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​
Changes in the scope of consolidation | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (90) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (90) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | (92) | ​ | ​
Currency translation differences and other changes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 51 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 33 | ​ | ​
Present value of benefit liabilities at end of year (a) | ​ | ​ | ​ | ​ | 269 | ​ | ​ | ​ | ​ | ​ | 1,044 | ​ | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | 1,490 | ​ | ​ | ​ | ​ | ​ | 278 | ​ | ​ | ​ | ​ | ​ | 1,768 | ​ | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 925 | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 1,348 | ​ | ​ | ​ | ​ | ​ | 309 | ​ | ​ | ​ | ​ | ​ | 1,657 | ​ | ​
Plan assets at beginning of year | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 588 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 588 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 588 | ​ | ​
Interest income | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​
Return on plan assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​
Plan contributions: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​
- employee contributions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- employer contributions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​
Benefits paid | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​
Changes in the scope of consolidation | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (64) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (64) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (64) | ​ | ​
Currency translation differences and other changes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 26 | ​ | ​
Plan assets at end of year (b) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 632 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 632 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 632 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​
Asset ceiling at beginning of year | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Change in asset ceiling | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​
Asset ceiling at end of year (c) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​
Net liability recognized at end of year (a-b+c) | ​ | ​ | ​ | ​ | 269 | ​ | ​ | ​ | ​ | ​ | 412 | ​ | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | 858 | ​ | ​ | ​ | ​ | ​ | 278 | ​ | ​ | ​ | ​ | ​ | 1,136 | ​ | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 385 | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 808 | ​ | ​ | ​ | ​ | ​ | 309 | ​ | ​ | ​ | ​ | ​ | 1,117 | ​ | ​

Employee benefit plans included the liability attributable to partners operating in exploration and production activities of €175 million (€181 million at December 31, 2018). Eni recorded a receivable for an amount equivalent to such liability.
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Costs charged to the profit and loss account consisted of the following:

(€ million) | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Defined benefit plans | ​ | ​ | Other benefit plans | ​ | ​ | Total | ​
2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Current cost | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 76 | ​ | ​
Past service cost and (gains) losses on settlements | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​
Interest cost (income), net: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- interest cost on liabilities | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 44 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 45 | ​ | ​
- interest income on plan assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (20) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (20) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (20) | ​ | ​
Total interest cost (income), net | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​
- of which recognized in “Payroll and related cost” | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- of which recognized in “Financial income (expense)” | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​
Remeasurements for long-term plans | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
Total | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 54 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 109 | ​ | ​
- of which recognized in “Payroll and related cost” | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 85 | ​ | ​
- of which recognized in “Financial income (expense)” | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Current cost | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 27 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 42 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​
Past service cost and (gains) losses on settlements | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 118 | ​ | ​
Interest cost (income), net: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- interest cost on liabilities | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 31 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​
- interest income on plan assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (17) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (17) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (17) | ​ | ​
Total interest cost (income), net | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​
- of which recognized in “Payroll and related cost” | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- of which recognized in “Financial income (expense)” | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​
Remeasurements for long-term plans | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​
Total | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | 188 | ​ | ​ | ​ | ​ | ​ | 240 | ​ | ​
- of which recognized in “Payroll and related cost” | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 188 | ​ | ​ | ​ | ​ | ​ | 220 | ​ | ​
- of which recognized in “Financial income (expense)” | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​

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

​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Total | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Total | ​
Remeasurements | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Actuarial (gains)/losses due to changes in financial assumptions | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | (30) | ​ | ​
Experience (gains) losses | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | (9) | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​
Return on plan assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (23) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (23) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​
Change in asset ceiling | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​
​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 42 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​

Plan assets consisted of the following:

(€ million) | ​ | ​ | Cash and cash equivalents | ​ | ​ | Equity securities | ​ | ​ | Debt securities | ​ | ​ | Real estate | ​ | ​ | Derivatives | ​ | ​ | Investment funds | ​ | ​ | Assets held by insurance company | ​ | ​ | Other | ​ | ​ | Total | ​
December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Plan assets with a quoted market price | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 79 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 65 | ​ | ​ | ​ | ​ | ​ | 629 | ​ | ​
Plan assets without a quoted market price | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​
​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 388 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 79 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 65 | ​ | ​ | ​ | ​ | ​ | 632 | ​ | ​
December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Plan assets with a quoted market price | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 238 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 70 | ​ | ​ | ​ | ​ | ​ | 542 | ​ | ​
Plan assets without a quoted market price | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​
​ | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | 238 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 70 | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​
​

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The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2020 consisted of the following:

​ | ​ | ​ | ​ | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Other benefit plans | ​
2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Discount rate | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 0.7 | ​ | ​ | ​ | ​ | ​ | 0.0-13.7 | ​ | ​ | ​ | ​ | ​ | 0.7 | ​ | ​ | ​ | ​ | ​ | 0.0-0.7 | ​ | ​
Rate of compensation increase | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.7 | ​ | ​ | ​ | ​ | ​ | 1.3-12.5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Rate of price inflation | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 0.7 | ​ | ​ | ​ | ​ | ​ | 0.8-11.3 | ​ | ​ | ​ | ​ | ​ | 0.7 | ​ | ​ | ​ | ​ | ​ | 0.7 | ​ | ​
Life expectations on retirement at age 65 | ​ | ​ | (years)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13-25 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Discount rate | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.5 | ​ | ​ | ​ | ​ | ​ | 0.8-18.0 | ​ | ​ | ​ | ​ | ​ | 1.5 | ​ | ​ | ​ | ​ | ​ | 0.2-1.5 | ​ | ​
Rate of compensation increase | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 2.5 | ​ | ​ | ​ | ​ | ​ | 1.5-16.5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Rate of price inflation | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.5 | ​ | ​ | ​ | ​ | ​ | 0.8-16.0 | ​ | ​ | ​ | ​ | ​ | 1.5 | ​ | ​ | ​ | ​ | ​ | 1.5 | ​ | ​
Life expectations on retirement at age 65 | ​ | ​ | (years)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13-25 | ​ | ​ | ​ | ​ | ​ | 24.0 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans:

​ | ​ | ​ | ​ | ​ | ​ | Euro area | ​ | ​ | Rest of Europe | ​ | ​ | Africa | ​ | ​ | Other areas | ​ | ​ | Foreign defined benefit plans | ​
2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Discount rate | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 0.8-1.0 | ​ | ​ | ​ | ​ | ​ | 0.0-2.0 | ​ | ​ | ​ | ​ | ​ | 2.6-13.7 | ​ | ​ | ​ | ​ | ​ | 7.3-11.3 | ​ | ​ | ​ | ​ | ​ | 0.0-13.7 | ​ | ​
Rate of compensation increase | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.3-3.0 | ​ | ​ | ​ | ​ | ​ | 2.5-3.6 | ​ | ​ | ​ | ​ | ​ | 2.0-12.5 | ​ | ​ | ​ | ​ | ​ | 10.0-11.3 | ​ | ​ | ​ | ​ | ​ | 1.3-12.5 | ​ | ​
Rate of price inflation | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.3-2.0 | ​ | ​ | ​ | ​ | ​ | 0.8-3.1 | ​ | ​ | ​ | ​ | ​ | 2.6-11.3 | ​ | ​ | ​ | ​ | ​ | 3.3-5.0 | ​ | ​ | ​ | ​ | ​ | 0.8-11.3 | ​ | ​
Life expectations on retirement at age 65 | ​ | ​ | (years)​ | ​ | ​ | ​ | ​ | 21-22 | ​ | ​ | ​ | ​ | ​ | 24-25 | ​ | ​ | ​ | ​ | ​ | 13-17 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13-25 | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Discount rate | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.5-1.9 | ​ | ​ | ​ | ​ | ​ | 0.8-2.9 | ​ | ​ | ​ | ​ | ​ | 3.7-18.0 | ​ | ​ | ​ | ​ | ​ | 8.0-13.3 | ​ | ​ | ​ | ​ | ​ | 0.8-18.0 | ​ | ​
Rate of compensation increase | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.5-3.0 | ​ | ​ | ​ | ​ | ​ | 2.5-3.8 | ​ | ​ | ​ | ​ | ​ | 5.0-16.5 | ​ | ​ | ​ | ​ | ​ | 10.0-13.3 | ​ | ​ | ​ | ​ | ​ | 1.5-16.5 | ​ | ​
Rate of price inflation | ​ | ​ | (%)​ | ​ | ​ | ​ | ​ | 1.5-2.0 | ​ | ​ | ​ | ​ | ​ | 0.8-3.3 | ​ | ​ | ​ | ​ | ​ | 3.7-16.0 | ​ | ​ | ​ | ​ | ​ | 3.5-5.0 | ​ | ​ | ​ | ​ | ​ | 0.8-16.0 | ​ | ​
Life expectations on retirement at age 65 | ​ | ​ | (years)​ | ​ | ​ | ​ | ​ | 21-22 | ​ | ​ | ​ | ​ | ​ | 23-25 | ​ | ​ | ​ | ​ | ​ | 13-17 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13-25 | ​ | ​

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, 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.
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The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €130 million, of which €57 million related to defined benefit plans.
The following is an analysis by maturity date of the liabilities for employee benefit plans and their relative weighted average duration:

(€ million) | ​ | ​ | Italian defined benefit plans | ​ | ​ | Foreign defined benefit plans | ​ | ​ | FISDE, foreign medical plans and other | ​ | ​ | Other benefit plans | ​
December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
2020 | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 33 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | 73 | ​ | ​
2021 | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | 35 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 68 | ​ | ​
2022 | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 61 | ​ | ​
2023 | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​
2024 | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​
2025 and thereafter | ​ | ​ | ​ | ​ | 199 | ​ | ​ | ​ | ​ | ​ | 224 | ​ | ​ | ​ | ​ | ​ | 139 | ​ | ​ | ​ | ​ | ​ | 45 | ​ | ​
Weighted average duration (years) | ​ | ​ | ​ | ​ | 9.4 | ​ | ​ | ​ | ​ | ​ | 18.1 | ​ | ​ | ​ | ​ | ​ | 13.3 | ​ | ​ | ​ | ​ | ​ | 3.0 | ​ | ​
December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
2019 | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | 54 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | 81 | ​ | ​
2020 | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 72 | ​ | ​
2021 | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 67 | ​ | ​
2022 | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 64 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​
2023 | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​
2024 and thereafter | ​ | ​ | ​ | ​ | 201 | ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​ | ​ | ​ | ​ | 114 | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​
Weighted average duration (years) | ​ | ​ | ​ | ​ | 10.1 | ​ | ​ | ​ | ​ | ​ | 17.4 | ​ | ​ | ​ | ​ | ​ | 12.8 | ​ | ​ | ​ | ​ | ​ | 2.6 | ​ | ​

22 Deferred tax assets and liabilities

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

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The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below:

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

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. 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 33.6%.
Accumulated write-downs of deferred tax assets related to Italian companies for €5,329 million and non-Italian companies for €1,415 million.
Taxes are also described in note 32 — Income taxes.
23 Derivative financial instruments and hedge accounting

​ | ​ | ​ | 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 | ​
Non-hedging derivatives | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives on exchange rate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Currency swap | ​ | ​ | ​ | ​ | 97 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 99 | ​ | ​ | ​ | ​ | ​ | 46 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- Interest currency swap | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- Outright | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
​ | ​ | ​ | ​ | ​ | 131 | ​ | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 116 | ​ | ​ | ​ | ​ | ​ | 122 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives on interest rate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Interest rate swap | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives on commodities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Future | ​ | ​ | ​ | ​ | 192 | ​ | ​ | ​ | ​ | ​ | 181 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1,060 | ​ | ​ | ​ | ​ | ​ | 1,107 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- Over the counter | ​ | ​ | ​ | ​ | 89 | ​ | ​ | ​ | ​ | ​ | 58 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 306 | ​ | ​ | ​ | ​ | ​ | 284 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- Other | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
​ | ​ | ​ | ​ | ​ | 293 | ​ | ​ | ​ | ​ | ​ | 239 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,367 | ​ | ​ | ​ | ​ | ​ | 1,396 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 437 | ​ | ​ | ​ | ​ | ​ | 321 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,501 | ​ | ​ | ​ | ​ | ​ | 1,524 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Trading derivatives | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives on commodities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Over the counter | ​ | ​ | ​ | ​ | 2,387 | ​ | ​ | ​ | ​ | ​ | 1,953 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 992 | ​ | ​ | ​ | ​ | ​ | 1,031 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- Future | ​ | ​ | ​ | ​ | 348 | ​ | ​ | ​ | ​ | ​ | 313 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 367 | ​ | ​ | ​ | ​ | ​ | 263 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- Options | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 80 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
​ | ​ | ​ | ​ | ​ | 2,756 | ​ | ​ | ​ | ​ | ​ | 2,288 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,439 | ​ | ​ | ​ | ​ | ​ | 1,365 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flow hedge derivatives | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives on commodities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Over the counter | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 596 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 311 | ​ | ​ | ​ | ​ | ​ | 196 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- Future | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Options | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | ​ | ​ | ​ | ​ | 35 | ​ | ​ | ​ | ​ | ​ | 746 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 337 | ​ | ​ | ​ | ​ | ​ | 211 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Option embedded in convertible bonds | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
Gross amount | ​ | ​ | ​ | ​ | 3,239 | ​ | ​ | ​ | ​ | ​ | 3,366 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3,298 | ​ | ​ | ​ | ​ | ​ | 3,121 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Offsetting | ​ | ​ | ​ | ​ | (612) | ​ | ​ | ​ | ​ | ​ | (612) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,636) | ​ | ​ | ​ | ​ | ​ | (1,636) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net amount | ​ | ​ | ​ | ​ | 2,627 | ​ | ​ | ​ | ​ | ​ | 2,754 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,662 | ​ | ​ | ​ | ​ | ​ | 1,485 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Of which: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- current | ​ | ​ | ​ | ​ | 2,573 | ​ | ​ | ​ | ​ | ​ | 2,704 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,594 | ​ | ​ | ​ | ​ | ​ | 1,445 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- non-current | ​ | ​ | ​ | ​ | 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.
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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 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 mechanisms of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 25 — Shareholders’ equity and in note 29 — Costs. Information on hedged risks and hedging policies is disclosed in note 27 — Guarantees, commitments and risks — Risk factors.
Options embedded in convertible bonds relate to equity-linked cash settled. More information is disclosed in note 18 — Finance debts.
The offsetting of financial derivatives related to the Gas & Power segment.
During 2019, there were no transfers between the different hierarchy levels of fair value.
Hedging derivative instruments are disclosed below:

​ | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
(€ million) | ​ | ​ | Nominal amount of the hedging instrument | ​ | ​ | Change in fair value (effective hedge) | ​ | ​ | Change in fair value (ineffective hedge) | ​ | ​ | Nominal amount of the hedging instrument | ​ | ​ | Change in fair value (effective hedge) | ​ | ​ | Change in fair value (ineffective hedge) | ​
Cash flow hedge derivatives | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives on commodity | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Over the counter | ​ | ​ | ​ | ​ | 2,179 | ​ | ​ | ​ | ​ | ​ | (1,357) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | 3,528 | ​ | ​ | ​ | ​ | ​ | 404 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
- Future | ​ | ​ | ​ | ​ | 1,245 | ​ | ​ | ​ | ​ | ​ | (61) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | (6) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​
​ | ​ | ​ | ​ | ​ | 3,424 | ​ | ​ | ​ | ​ | ​ | (1,418) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | 3,599 | ​ | ​ | ​ | ​ | ​ | 398 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

In 2019, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €1,902 million was hedged by using, in a fair value hedge relationship, negative exchange differences for €21 million resulting on a portion of bonds denominated in U.S. dollars amounting to €1,844 million.
The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge is provided below:

​ | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
(€ million) | ​ | ​ | Change of the underlying asset used for the calculation of hedging ineffectiveness | ​ | ​ | CFH reserve | ​ | ​ | Reclassification adjustments | ​ | ​ | Change of the underlying asset used for the calculation of hedging ineffectiveness | ​ | ​ | CFH reserve | ​ | ​ | Reclassification adjustments | ​
Cash flow hedge derivatives | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Commodity price risk | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Planned sales | ​ | ​ | ​ | ​ | 1,444 | ​ | ​ | ​ | ​ | ​ | (656) | ​ | ​ | ​ | ​ | ​ | (739) | ​ | ​ | ​ | ​ | ​ | (389) | ​ | ​ | ​ | ​ | ​ | (13) | ​ | ​ | ​ | ​ | ​ | 642 | ​ | ​
​ | ​ | ​ | ​ | ​ | 1,444 | ​ | ​ | ​ | ​ | ​ | (656) | ​ | ​ | ​ | ​ | ​ | (739) | ​ | ​ | ​ | ​ | ​ | (389) | ​ | ​ | ​ | ​ | ​ | (13) | ​ | ​ | ​ | ​ | ​ | 642 | ​ | ​

Eni’s results of operations are affected by fluctuations in the price of commodities. To that end, Eni enters into commodities derivatives traded on organized markets (like MTF and OTF) and commodities derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with underlying commodities being crude oil, gas, refined products, electricity or emission certificates that are not settled through physical delivery of the underlying commodity but are designated as hedging instruments in a cash flow hedge relation.
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The existence of a relationship between the hedged item and the hedging derivative is checked at inception to verify eligibility for hedge accounting by observing the offset in changes of the fair values at both the underlying commodity and the derivative. The hedging relationship is also stress-tested against the level of credit risk of the counterparty in the derivative transaction.
The hedge ratio is defined consistently with the Company’s risk management objectives, under a defined risk management strategy.
The hedging relationship is discontinued when it ceases to meet the qualifying criteria and the risk management objectives on the basis of which hedge accounting has initially been applied.
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 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 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 connection with the fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS, as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment.
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
As of December 31, 2019, assets held for sale related to sales of tangible assets for €18 million.
In the course of 2019, Eni finalized the sale of Agip Oil Ecuador BV, which retains a service contract for the development of Villano oil field, and of a minority investment.
25 Shareholders’ equity
Eni shareholders’ equity

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

Share capital
As of December 31, 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, 2018).
On May 14, 2019, Eni’s Shareholders’ Meeting resolved: (i) to distribute a dividend of €0.41 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2018 dividend of €0.83 per share, of which €0.42 per share was already paid as interim dividend in September 2018. The final amount was paid on 22 May 2019, to shareholders on the register on May 20, 2019, record date on May 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.
Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.
Reserve for treasury shares
The reserve for treasury shares represents the reserve that was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings.
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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 | ​
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 | ​ | ​

​
*
OCI for defined benefit plans at December 31, 2019 includes €7 million relating to equity-accounted investments.
​
Other reserves
Other reserves related to: (i) a reserve of €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 subsidiaries; (ii) a reserve of €63 million deriving from Eni SpA’s 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.
Treasury shares
A total of 61,635,679 of Eni’s ordinary shares (33,045,197 at December 31, 2018) were held in treasury for a total cost of €981 million (€581 million at December 31, 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 2019 amounted to €1,542 million corresponding to €0.43 per share, as resolved by the Board of Directors on 19 September 2019, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on 25 September 2019.
Distributable reserves
As of December 31, 2019, Eni shareholders’ equity included distributable reserves of approximately €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) | ​ | ​ | 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 | ​ | ​

26 Other information
Supplemental cash flow information

(€ 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 €4,323 million (€5,082 million at December 31, 2018) primarily consisted of guarantees given to third parties relating to bid bonds and performance bonds for €2,886 million (€2,576 million at December 31, 2018). In 2019 a bank guarantee of €1,010 million, issued on behalf of GasTerra to obtain the waiver to a temporary seizure of Eni’s investment in Eni International BV, which was ordered by a Netherlands Court in July 2016, was settled. In July 2019, the arbitration proceeding, initiated by the parties to settle the dispute, issued an award favourable to Eni and ruled the claim of GasTerra for a price adjustment to the gas supplies to be without merit, which in the first partial award was the basis whereby GasTerra obtained the seizure order. On July 24, 2019 upon Eni’s request and GasTerra’s consent, the bank guarantee was terminated. GasTerra has reserved its rights of appeal. At December 31, 2019, the underlying commitment issued on behalf of consolidated subsidiaries covered by such guarantees was €4,013 million (€5,000 million at December 31, 2018).
Guarantees issued on behalf of joint ventures and associates of €4,075 million (€4,056 million at December 31, 2018) primarily consisted of: (i) unsecured guarantees and other guarantees for €1,676 million issued towards banks and other lending institutions in relation to loans and lines of credit received (€1,664 million at December 31, 2018), of which €1,425 million (€1,397 million at December 31, 2018) related to guarantees issued as part of the Coral development project in Area 4 offshore Mozambique on behalf of Coral South FLNG DMCC with respect to the financing agreements of the project with Export Credit Agencies and banks; and (ii) guarantees given to third parties relating to bid
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bonds and performance bonds for €1,661 million (€1,644 million at December 31, 2018), of which €1,168 million (€1,147 million at December 31, 2018) related to guarantees issued towards the contractors who are building the FLNG vessel as part of the Coral development project offshore Mozambique; (iii) an unsecured guarantee of €499 million (€499 million at December 31, 2018) given by Eni SpA on behalf of the participated Saipem joint-venture to Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project for the construction of the Milan-Bologna fast track railway by the CEPAV (Consorzio Eni per l’Alta Velocità) Uno; (iv) a guarantee issued in favor of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni’s interest 13.60%) to cover contractual commitments of paying re-gasification fees for €181 million (€177 million at December 31, 2018). At December 31, 2019, the underlying commitment issued on behalf of joint ventures and associates covered by such guarantees was €2,109 million (€2,159 million at December 31, 2018).
Commitments and risks

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
Commitments | ​ | ​ | ​ | ​ | 74,338 | ​ | ​ | ​ | ​ | ​ | 54,611 | ​ | ​
Risks | ​ | ​ | ​ | ​ | 676 | ​ | ​ | ​ | ​ | ​ | 673 | ​ | ​
​ | ​ | ​ | ​ | ​ | 75,014 | ​ | ​ | ​ | ​ | ​ | 55,284 | ​ | ​

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 be €65,374 million (€52,397 million at December 31, 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 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 & Trading BV following the Share Purchase Agreement to acquire from ADNOC a 20% equity interest in ADNOC Refining and the set-up of ADNOC Global Trading Ltd dedicated to 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 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 will remain in force as long as the investment is maintained; (iii) commitments assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service Llc for the purchase of volumes of regasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031). The expected commitments were estimated at €1,978 million (€2,079 million at December 31, 2018) and have been included in off-balance sheet contractual commitments in the table “Future payments under contractual obligations” in the paragraph Liquidity risk. However, since the project has been abandoned by the partners, Eni does not expect to make any payment under those contractual obligations.
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In 2018, the contractual commitment signed in December 2007 between Eni USA Gas Marketing Llc and Gulf LNG Energy Llc (GLE) and Gulf LNG Pipeline Llc (GLP) for the purchase of long-term regasification and transport services (until 2031) amounting at December 31, 2017 to €948 million (undiscounted) ceased due to an arbitration ruling. The jurors established that the commitment was resolved by March 1, 2016 and recognized to the counterparties 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 €114 million (€116 million at December 31, 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 relate to potential risks associated with: (i) contractual assurances given to acquirers of certain investments and businesses of Eni for €248 million (€244 million at December 31, 2018); (ii) assets of third parties under the custody of Eni for €428 million (€429 million at December 31, 2018).
Other commitments and risks
A parent company guarantee was issued on behalf of Cardón IV SA (Eni’s interest 50%), a joint venture operating the Perla gas field located in Venezuela, for the supply to PDVSA GAS of the volumes of gas produced by the field until the end of the concession agreement (2036). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective due to a revision of the contractual terms. In case of failure on part of the operator to deliver the contractual gas volumes out of production, the claim under the guarantee will be determined by applying the local legislation. Eni’s share (50%) of the contractual volumes of gas to be delivered to PDVSA GAS amounted to a total of around €13 billion. Notwithstanding this amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued by PDVSA on behalf of Eni for the fulfillment of the purchase commitments of the gas volumes by PDVSA GAS.
Other commitments also include the agreements entered into for forestry initiatives, implemented within the low carbon strategy defined by the Company, and in particular concerning the commitments for the purchase, up to 2038, of carbon credits produced and certified according to international standards by subjects specialized in forest conservation programs.
Eni is liable for certain non-quantifiable risks related to contractual assurances 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.
Financial risks
Financial risks are managed in respect of guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the aim of the risk management, the valuation methodology, the structure of limits, the relationship model and the hedging and mitigation instruments.
Market risk
Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management transactions based on the
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Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Finance International SA, Eni Finance USA Inc and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni Corporate finance department, Eni Finance International SA and Eni Finance USA Inc manage subsidiaries’ financing requirements in and outside Italy and in the United States of America, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies different from commodities are managed by the parent company, while Eni Trading & Shipping SpA executes the negotiation of commodity derivatives over the market. Eni SpA and Eni Trading & Shipping SpA (also through its subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non-European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar and brokerage platforms (i.e. SEF), and over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into these transactions through Eni Trading & Shipping and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As proprietary trading is considered separately from the other activities in specific portfolios of Eni Trading & Shipping, its exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s policies and guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon; (ii) limits of revision strategy, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given; and (iii) VaR which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s guidelines define rules to manage the commodity risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of revision strategy, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools the requests for negotiating commodity derivatives and executes them in the marketplace. According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni decided to retain a cash reserve to face any extraordinary requirement. Eni’s finance department, with the aim of optimizing the efficiency and ensuring maximum protection of capital, manages such reserve and its immediate liquidity within the limits assigned. The management of strategic cash is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity.
The four different market risks, whose management and control have been summarized above, are described below.
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Market risk — Exchange rate
Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than euro (mainly U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rate fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than euro are translated from their functional currency into euro. Generally, an appreciation of U.S. dollar versus euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries, which prepare financial statements in a currency other than euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s finance departments, which pool Group companies’ positions, hedging the Group net exposure by using certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value based on market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss, as they do not meet the formal criteria to be recognized as hedges. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period.
Market risk — Interest rate
Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in management’s finance plans. The Group’s finance departments pool borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with management plans, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to manage effectively the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 20-day holding period.
Market risk — Commodity
Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil&gas prices generally, has a negative impact on Eni’s results of operations and vice versa, and may jeopardize the achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk. These exposures include those associated with the program for the production of proved and unproved oil&gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments, to the components related to the time horizon of the four-year plan and budget and the relevant activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not for the purpose of delivery, both within the commodity and financial markets, with the aim to obtain a profit upon the occurrence of a favorable result in the market, in accordance with specific limits of authorized risk (VaR, stop loss). Origination activities are included in the proprietary trading exposures, if not connected to contractual or physical assets.
Strategic risk is not subject to systematic activity of management/coverage that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging
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activities related to strategic risks are delegated to the top management. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable economic results. Eni manages the commodity risk through the trading unit of Eni Trading & Shipping and the exposure to commodity prices through the Group’s finance departments by using derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, power or emission certificates. Such derivatives are valued at fair value based on market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a 95% confidence level and a one-day holding period.
Market risk — Strategic liquidity
Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual funds) would affect the value of these instruments when valued at fair value. The setting up and maintenance of the liquidity reserve is mainly aimed to guarantee a proper financial flexibility. Liquidity should allow Eni to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions) and must be dimensioned to provide a coverage of short-term debts and a coverage of medium and long-term finance debts due within a time horizon of 24 months. In order to manage the investment activity of the strategic liquidity, Eni defined a specific investment policy with aims and constraints in terms of financial activities and operational boundaries, as well as governance guidelines regulating management and control systems. In particular, strategic liquidity management is regulated in terms of VaR (measured based on a parametrical methodology with a one-day holding period and a 99% confidence level), stop loss and other operating limits in terms of concentration, issuing entity, business segment, country of emission, duration, ratings and type of investing instruments in portfolio, aimed to minimize market and liquidity risks. Financial leverage or short selling is not allowed. Activities in terms of strategic liquidity management started in the second half of the year 2013 (Euro portfolio) and throughout the course of the year 2017 (U.S. dollar portfolio). In 2019, the Euro investment portfolio has maintained an average credit rating of A-/BBB+, whereas the USD investment portfolio has maintained an average credit rating of A+/A, both in line with the year 2018. The following tables show amounts in terms of VaR, recorded in 2019 (compared with 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 changes of interest rate is expressed by values of  “Dollar value per Basis Point” (DVBP).
(Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | High | ​ | ​ | Low | ​ | ​ | Average | ​ | ​ | At year end | ​ | ​ | High | ​ | ​ | Low | ​ | ​ | Average | ​ | ​ | At year end | ​
Interest rate(a) | ​ | ​ | ​ | ​ | 5.19 | ​ | ​ | ​ | ​ | ​ | 2.44 | ​ | ​ | ​ | ​ | ​ | 3.80 | ​ | ​ | ​ | ​ | ​ | 3.00 | ​ | ​ | ​ | ​ | ​ | 3.65 | ​ | ​ | ​ | ​ | ​ | 1.80 | ​ | ​ | ​ | ​ | ​ | 2.73 | ​ | ​ | ​ | ​ | ​ | 2.99 | ​ | ​
Exchange rate(a) | ​ | ​ | ​ | ​ | 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 departments: Eni Corporate Finance Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc.
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(Value at risk — Historic simulation method; holding period: 1 day; confidence level: 95%)

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | High | ​ | ​ | Low | ​ | ​ | Average | ​ | ​ | At year end | ​ | ​ | High | ​ | ​ | Low | ​ | ​ | Average | ​ | ​ | At year end | ​
Commercial exposures – Management Portfolio﻿(a) | ​ | ​ | ​ | ​ | 23.03 | ​ | ​ | ​ | ​ | ​ | 7.74 | ​ | ​ | ​ | ​ | ​ | 11.22 | ​ | ​ | ​ | ​ | ​ | 9.11 | ​ | ​ | ​ | ​ | ​ | 18.60 | ​ | ​ | ​ | ​ | ​ | 6.79 | ​ | ​ | ​ | ​ | ​ | 11.04 | ​ | ​ | ​ | ​ | ​ | 7.50 | ​ | ​
Trading(b) | ​ | ​ | ​ | ​ | 1.60 | ​ | ​ | ​ | ​ | ​ | 0.25 | ​ | ​ | ​ | ​ | ​ | 0.51 | ​ | ​ | ​ | ​ | ​ | 0.31 | ​ | ​ | ​ | ​ | ​ | 2.28 | ​ | ​ | ​ | ​ | ​ | 0.26 | ​ | ​ | ​ | ​ | ​ | 0.73 | ​ | ​ | ​ | ​ | ​ | 0.27 | ​ | ​

​
(a)
Refers to the LNG Marketing & Power business line (risk exposure from Refining & Marketing business line and Gas & Power Division), Eni Trading & Shipping commercial portfolio, operating branches outside Italy pertaining to the Divisions and from October 2016 the Gas e Luce business line. For the 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, during the year the VaR pertaining to 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)

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | High | ​ | ​ | Low | ​ | ​ | Average | ​ | ​ | At year end | ​ | ​ | High | ​ | ​ | Low | ​ | ​ | Average | ​ | ​ | At year end | ​
Strategic liquidity(a) | ​ | ​ | ​ | ​ | 0.37 | ​ | ​ | ​ | ​ | ​ | 0.31 | ​ | ​ | ​ | ​ | ​ | 0.35 | ​ | ​ | ​ | ​ | ​ | 0.33 | ​ | ​ | ​ | ​ | ​ | 0.35 | ​ | ​ | ​ | ​ | ​ | 0.25 | ​ | ​ | ​ | ​ | ​ | 0.29 | ​ | ​ | ​ | ​ | ​ | 0.25 | ​ | ​

​
(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. Eni defined credit risk 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 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 commercial counterparties is managed by the business units and 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 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
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premiums adopted for the purposes of the determination of the WACCs for the impairment of non-financial assets. Furthermore, for retail positions without specific ratings, risk is determined by distinguishing customers in homogeneous risk clusters based on historical series of data relating to payments, periodically updated.
Credit risk for financial exposures
With regard to credit risk arising from financial counterparties deriving from current and strategic use of liquidity, derivative contracts and transactions with underlying financial assets valued at fair value, Eni has established internal policies providing exposure control and concentration through maximum credit risk limits corresponding to different classes of financial counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Eni’s operating finance departments and Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and business units, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored by each counterpart and by group of belonging to check exposures against the limits assigned on a daily basis and the expected loss analysis and the concentration periodically.
Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets in the marketplace in order to meet short-term finance requirements and to settle obligations. Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. Eni’s risk management targets include the maintaining of an adequate level of liquidity readily available to deal with external shocks (drastic changes in the scenario, restrictions on access to capital markets, etc.) or to ensure an adequate level of operational flexibility for the development programs of the Company. The strategic liquidity reserve is employed in short-term marketable financial instruments, favouring 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 €14.9 billion were drawn as of December 31, 2019.
The Group has credit ratings of A- outlook stable and A-2, respectively, for long and short-term debt, assigned by Standard & Poor’s; Baa1 outlook stable and P-2, respectively, for long and short-term debt, assigned by Moody’s; A- outlook stable and F1, respectively for long and short-term debt, assigned by Fitch. Eni’s credit rating is linked in addition to the Company’s industrial fundamentals and trends in the trading environment to the sovereign credit rating of Italy. Based on the methodologies used by the credit rating agencies, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. During 2019, the rating of Eni remained unchanged.
In 2019, Eni issued bonds for €1,635 million, of which €746 million as part of the Euro Medium Term Notes program and €889 million through an issue amounting to $1 billion in the U.S. and international markets.
As of December 31, 2019, Eni maintained short-term unused borrowing facilities of €13,299 million. Long-term committed unused borrowing facilities amounted to €4,667 million, of which €450 million due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.
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Expected payments for finance debts and lease liabilities
The tables below summarize the Group main contractual obligations for finance debt and lease liability repayments, including expected payments for interest charges and derivatives.

​ | ​ | ​ | Maturity year | ​
(€ million) | ​ | ​ | 2020 | ​ | ​ | 2021 | ​ | ​ | 2022 | ​ | ​ | 2023 | ​ | ​ | 2024 | ​ | ​ | 2025 and thereafter | ​ | ​ | Total | ​
December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-current financial liabilities (including the current portion) | ​ | ​ | ​ | ​ | 2,908 | ​ | ​ | ​ | ​ | ​ | 1,704 | ​ | ​ | ​ | ​ | ​ | 1,259 | ​ | ​ | ​ | ​ | ​ | 2,743 | ​ | ​ | ​ | ​ | ​ | 1,785 | ​ | ​ | ​ | ​ | ​ | 11,521 | ​ | ​ | ​ | ​ | ​ | 21,920 | ​ | ​
Current financial liabilities | ​ | ​ | ​ | ​ | 2,452 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,452 | ​ | ​
Lease liabilities | ​ | ​ | ​ | ​ | 884 | ​ | ​ | ​ | ​ | ​ | 632 | ​ | ​ | ​ | ​ | ​ | 487 | ​ | ​ | ​ | ​ | ​ | 434 | ​ | ​ | ​ | ​ | ​ | 424 | ​ | ​ | ​ | ​ | ​ | 2,761 | ​ | ​ | ​ | ​ | ​ | 5,622 | ​ | ​
Fair value of derivative instruments | ​ | ​ | ​ | ​ | 2,704 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 2,754 | ​ | ​
​ | ​ | ​ | ​ | ​ | 8,948 | ​ | ​ | ​ | ​ | ​ | 2,338 | ​ | ​ | ​ | ​ | ​ | 1,760 | ​ | ​ | ​ | ​ | ​ | 3,177 | ​ | ​ | ​ | ​ | ​ | 2,209 | ​ | ​ | ​ | ​ | ​ | 14,316 | ​ | ​ | ​ | ​ | ​ | 32,748 | ​ | ​
Interest on finance debt | ​ | ​ | ​ | ​ | 594 | ​ | ​ | ​ | ​ | ​ | 452 | ​ | ​ | ​ | ​ | ​ | 353 | ​ | ​ | ​ | ​ | ​ | 342 | ​ | ​ | ​ | ​ | ​ | 269 | ​ | ​ | ​ | ​ | ​ | 1,667 | ​ | ​ | ​ | ​ | ​ | 3,677 | ​ | ​
Interest on lease liabilities | ​ | ​ | ​ | ​ | 341 | ​ | ​ | ​ | ​ | ​ | 302 | ​ | ​ | ​ | ​ | ​ | 263 | ​ | ​ | ​ | ​ | ​ | 233 | ​ | ​ | ​ | ​ | ​ | 206 | ​ | ​ | ​ | ​ | ​ | 1,015 | ​ | ​ | ​ | ​ | ​ | 2,360 | ​ | ​
​ | ​ | ​ | ​ | ​ | 935 | ​ | ​ | ​ | ​ | ​ | 754 | ​ | ​ | ​ | ​ | ​ | 616 | ​ | ​ | ​ | ​ | ​ | 575 | ​ | ​ | ​ | ​ | ​ | 475 | ​ | ​ | ​ | ​ | ​ | 2,682 | ​ | ​ | ​ | ​ | ​ | 6,037 | ​ | ​
Financial guarantees | ​ | ​ | ​ | ​ | 926 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 926 | ​ | ​
​

​ | ​ | ​ | Maturity year | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2020 | ​ | ​ | 2021 | ​ | ​ | 2022 | ​ | ​ | 2023 | ​ | ​ | 2024 and thereafter | ​ | ​ | Total | ​
December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-current financial liabilities (including the current portion) | ​ | ​ | ​ | ​ | 3,301 | ​ | ​ | ​ | ​ | ​ | 2,958 | ​ | ​ | ​ | ​ | ​ | 1,541 | ​ | ​ | ​ | ​ | ​ | 1,253 | ​ | ​ | ​ | ​ | ​ | 2,714 | ​ | ​ | ​ | ​ | ​ | 11,723 | ​ | ​ | ​ | ​ | ​ | 23,490 | ​ | ​
Current financial liabilities | ​ | ​ | ​ | ​ | 2,182 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,182 | ​ | ​
Fair value of derivative instruments | ​ | ​ | ​ | ​ | 1,445 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 1,485 | ​ | ​
​ | ​ | ​ | ​ | ​ | 6,928 | ​ | ​ | ​ | ​ | ​ | 2,971 | ​ | ​ | ​ | ​ | ​ | 1,542 | ​ | ​ | ​ | ​ | ​ | 1,274 | ​ | ​ | ​ | ​ | ​ | 2,714 | ​ | ​ | ​ | ​ | ​ | 11,728 | ​ | ​ | ​ | ​ | ​ | 27,157 | ​ | ​
Interest on finance debt | ​ | ​ | ​ | ​ | 655 | ​ | ​ | ​ | ​ | ​ | 545 | ​ | ​ | ​ | ​ | ​ | 436 | ​ | ​ | ​ | ​ | ​ | 330 | ​ | ​ | ​ | ​ | ​ | 320 | ​ | ​ | ​ | ​ | ​ | 1,677 | ​ | ​ | ​ | ​ | ​ | 3,963 | ​ | ​
Financial guarantees | ​ | ​ | ​ | ​ | 668 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 668 | ​ | ​

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 | ​ | ​
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Expected payments under contractual obligations3 6
In addition to lease, financial, trade and other liabilities represented in the balance sheet, the company is subject to non-cancellable contractual obligations or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in future reporting periods. These liabilities are valued based on the net cost for the company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligation and the contractual compensation/penalty in the event of non-performance.
The Company’s main contractual obligations at the balance sheet date comprise take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors.
The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

​ | ​ | ​ | Maturity year | ​
(€ million) | ​ | ​ | 2020 | ​ | ​ | 2021 | ​ | ​ | 2022 | ​ | ​ | 2023 | ​ | ​ | 2024 | ​ | ​ | 2025 and thereafter | ​ | ​ | Total | ​
Decommissioning liabilities(a) | ​ | ​ | ​ | ​ | 331 | ​ | ​ | ​ | ​ | ​ | 325 | ​ | ​ | ​ | ​ | ​ | 163 | ​ | ​ | ​ | ​ | ​ | 179 | ​ | ​ | ​ | ​ | ​ | 424 | ​ | ​ | ​ | ​ | ​ | 12,052 | ​ | ​ | ​ | ​ | ​ | 13,474 | ​ | ​
Environmental liabilities | ​ | ​ | ​ | ​ | 403 | ​ | ​ | ​ | ​ | ​ | 368 | ​ | ​ | ​ | ​ | ​ | 319 | ​ | ​ | ​ | ​ | ​ | 238 | ​ | ​ | ​ | ​ | ​ | 198 | ​ | ​ | ​ | ​ | ​ | 1,065 | ​ | ​ | ​ | ​ | ​ | 2,591 | ​ | ​
Purchase obligations(b) | ​ | ​ | ​ | ​ | 9,938 | ​ | ​ | ​ | ​ | ​ | 9,912 | ​ | ​ | ​ | ​ | ​ | 9,467 | ​ | ​ | ​ | ​ | ​ | 9,530 | ​ | ​ | ​ | ​ | ​ | 9,722 | ​ | ​ | ​ | ​ | ​ | 77,914 | ​ | ​ | ​ | ​ | ​ | 126,483 | ​ | ​
- Gas | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- take-or-pay contracts | ​ | ​ | ​ | ​ | 7,117 | ​ | ​ | ​ | ​ | ​ | 9,140 | ​ | ​ | ​ | ​ | ​ | 8,912 | ​ | ​ | ​ | ​ | ​ | 9,100 | ​ | ​ | ​ | ​ | ​ | 9,410 | ​ | ​ | ​ | ​ | ​ | 77,239 | ​ | ​ | ​ | ​ | ​ | 120,918 | ​ | ​
- ship-or-pay contracts | ​ | ​ | ​ | ​ | 1,070 | ​ | ​ | ​ | ​ | ​ | 532 | ​ | ​ | ​ | ​ | ​ | 454 | ​ | ​ | ​ | ​ | ​ | 412 | ​ | ​ | ​ | ​ | ​ | 296 | ​ | ​ | ​ | ​ | ​ | 646 | ​ | ​ | ​ | ​ | ​ | 3,410 | ​ | ​
- Other purchase obligations | ​ | ​ | ​ | ​ | 1,751 | ​ | ​ | ​ | ​ | ​ | 240 | ​ | ​ | ​ | ​ | ​ | 101 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 2,155 | ​ | ​
Other obligations | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 106 | ​ | ​ | ​ | ​ | ​ | 114 | ​ | ​
- 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)
Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
​
(b)
Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
​
Capital investment and capital expenditure commitments
In the next four years, Eni expects capital investments and capital expenditures of €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.
The amounts shown in the table below include committed expenditures to execute certain environmental projects.

​ | ​ | ​ | Maturity year | ​
(€ million) | ​ | ​ | 2020 | ​ | ​ | 2021 | ​ | ​ | 2022 | ​ | ​ | 2023 | ​ | ​ | 2024 and thereafter | ​ | ​ | Total | ​
Committed projects | ​ | ​ | ​ | ​ | 5,570 | ​ | ​ | ​ | ​ | ​ | 4,054 | ​ | ​ | ​ | ​ | ​ | 2,611 | ​ | ​ | ​ | ​ | ​ | 1,544 | ​ | ​ | ​ | ​ | ​ | 2,669 | ​ | ​ | ​ | ​ | ​ | 16,448 | ​ | ​

​
36
Contractual obligations related to employee benefits are indicated in note 21 — Provisions for employee benefits.
​
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Other information about financial instruments
The carrying amount of financial instruments and the relevant economic and equity effect consisted of the following:

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | Carrying amount | ​ | ​ | Finance income (expense) recognized in | ​ | ​ | Carrying amount | ​ | ​ | Finance income (expense) recognized in | ​
​ | Profit and loss account | ​ | ​ | Other comprehensive income | ​ | ​ | Profit and loss account | ​ | ​ | Other comprehensive income | ​
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) | ​ | ​ | ​ | ​ | (125) | ​ | ​ | ​ | ​ | ​ | 273 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | (178) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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) | ​ | ​ | ​ | ​ | 12,926 | ​ | ​ | ​ | ​ | ​ | (409) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14,145 | ​ | ​ | ​ | ​ | ​ | (343) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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 €287 million (income for €129 million in 2018) and as loss within “Finance income (expense)” for €14 million (loss for €307 million in 2018).
​
(c)
Income or expense were recognized in the profit and loss account within “Income (expense) from investments — Dividends”.
​
(d)
Income or expense were recognized in the profit and loss account as net impairment losses within “Net (impairment losses) reversal of trade and other receivables” for €432 million (net impairment losses for €415 million in 2018) and as income within “Finance income (expense)” for €23 million (income for €69 million in 2018), including interest income calculated on the basis of the effective interest rate of €26 million (interest income for €38 million in 2018).
​
(e)
In the profit and loss account, income or expense were recognized as income within “Finance income (expense)”, including interest income calculated on the basis of the effective interest rate of €99 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 “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”.
​
Disclosures about the offsetting of financial instruments

(€ million) | ​ | ​ | Gross amount of financial assets and liabilities | ​ | ​ | Gross amount of financial assets and liabilities subject to offsetting | ​ | ​ | Net amount of financial assets and liabilities | ​
December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Financial assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Trade and other receivables | ​ | ​ | ​ | ​ | 13,773 | ​ | ​ | ​ | ​ | ​ | 900 | ​ | ​ | ​ | ​ | ​ | 12,873 | ​ | ​
Other current assets | ​ | ​ | ​ | ​ | 4,584 | ​ | ​ | ​ | ​ | ​ | 612 | ​ | ​ | ​ | ​ | ​ | 3,972 | ​ | ​
Financial liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Trade and other liabilities | ​ | ​ | ​ | ​ | 16,445 | ​ | ​ | ​ | ​ | ​ | 900 | ​ | ​ | ​ | ​ | ​ | 15,545 | ​ | ​
Other current liabilities | ​ | ​ | ​ | ​ | 7,758 | ​ | ​ | ​ | ​ | ​ | 612 | ​ | ​ | ​ | ​ | ​ | 7,146 | ​ | ​
December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Financial assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Trade and other receivables | ​ | ​ | ​ | ​ | 15,634 | ​ | ​ | ​ | ​ | ​ | 1,533 | ​ | ​ | ​ | ​ | ​ | 14,101 | ​ | ​
Other current assets | ​ | ​ | ​ | ​ | 4,455 | ​ | ​ | ​ | ​ | ​ | 1,636 | ​ | ​ | ​ | ​ | ​ | 2,819 | ​ | ​
Financial liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Trade and other liabilities | ​ | ​ | ​ | ​ | 18,280 | ​ | ​ | ​ | ​ | ​ | 1,533 | ​ | ​ | ​ | ​ | ​ | 16,747 | ​ | ​
Other current liabilities | ​ | ​ | ​ | ​ | 7,048 | ​ | ​ | ​ | ​ | ​ | 1,636 | ​ | ​ | ​ | ​ | ​ | 5,412 | ​ | ​
​

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The offsetting of financial assets and liabilities related to the offsetting of: (i) receivables and payables pertaining to the Exploration & Production segment towards state entities for €713 million (€1,347 million at December 31, 2018) and trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €187 million (€186 million at December 31, 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 20 — Provisions and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements.
In addition to proceedings arising in the ordinary course of business referred to above, Eni is party to other proceedings, and a description of the most significant proceedings currently pending is provided in the following paragraphs. Unless 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) (company incorporating EniChem Agricoltura SpA — Agricoltura SpA in liquidation — EniChem Augusta Industriale Srl — Fosfotec Srl) — Proceeding about the industrial site of Crotone. In 2010 a criminal proceeding started before the Public Prosecutor of Crotone relating to allegations of environmental disaster, poisoning of substances used in the food chain and omitted clean-up due to the activity at a landfill site which was taken over by Eni in 1991. Subsequently to Eni’s takeover, any activity for waste conferral was stopped. The defendants are certain managers of Eni Group companies, that have managed the landfill since 1991. The Municipality of Crotone is acting as plaintiff. In March 2019, the public prosecutor requested the acquittal of all defendants. The proceeding is ongoing. In April 2017, the Public Prosecutor of Crotone started another criminal proceeding concerning the clean-up of the area called “Farina Trappeto”. The Company presented a new clean-up program already deemed approvable by the Ministry for the Environment. Clean-up remediation activities have started. The Company has requested the dismissal of the second proceeding.
(ii) Eni Rewind SpA (former Syndial SpA) and Versalis SpA — Porto Torres — Prosecuting body: Public Prosecutor of Sassari. In 2011, the Public Prosecutor of Sassari (Sardinia) determined that a manager responsible for plant operations at the site of Porto Torres should stand trial for alleged environmental disaster and poisoning of water and substances destined for food. The Province of Sassari, the Municipality of Porto Torres and other entities have been involved in the proceedings as civil parties seeking damages. In 2013, the Prosecutor of Sassari requested a new indictment for negligent behavior, replacing the previous allegation of willful conduct. The Third Instance Court has denied a motion to terminate the proceedings. The Public Prosecutor has re-submitted request that the defendants stand trial. The proceeding is underway.
(iii) Eni Rewind SpA (former Syndial SpA) and Versalis SpA — Porto Torres dock. In 2012, following a request of the Public Prosecutor of Sassari, an Italian court ordered presentation of evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by Eni Rewind SpA) and its capacity to avoid the dispersion of contamination released by the site into the nearby sea. Eni Rewind SpA and Versalis SpA were notified that its chief executive officers and certain other managers were being investigated. The Public Prosecutor of the Municipality of Sassari requested that these individuals stand trial. The plaintiffs, the Ministry for Environment and the Sardinia Region claimed environmental damage in an amount of €1.5 billion. Other parties referred to the judge’s equitable assessment. At a hearing in July 2016, the court acquitted all defendants of Eni Rewind and Versalis with respect to the crimes of environmental disaster. Three Eni Rewind managers were found guilty of environmental disaster relating to the period limited to August 2010 – January 2011 and sentenced to one-year prison, with a suspended sentence. Eni Rewind filed an appeal against this decision. The proceeding is underway.
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(iv) Eni Rewind SpA (former Syndial SpA) — The illegal landfill in Minciaredda area, Porto Torres site. The Court of Sassari, on request of the Public Prosecutor, seized the Minciaredda landfill area, near the western border of the Porto Torres site (Minciaredda area). All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure order involved also Eni Rewind pursuant to Legislative Decree No. 231/01, whereby companies are liable for the crimes committed by their employees when performing their duties. The court determined that Eni Rewind can be sued for civil liability and resolved that all defendants and the Eni subsidiary be put on trial before the Court of Sassari.
(v) Eni Rewind SpA (former Syndial SpA) — The Phosphate deposit at Porto Torres site (1). In 2015, the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, seized — as a preventive measure — the area of  “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster, carrying out of unauthorized disposal of hazardous wastes and other environmental crimes. Eni Rewind SpA is being investigated pursuant to Legislative Decree No. 231/01. In November 2019, a request for referral to trial was served on the Eni subsidiary.
(vi) Eni Rewind SpA (former Syndial SpA) — Phosphate deposit at Porto Torres site (2). In 2015, the Public Prosecutor at the Court of Sassari seized — as a probative measure — the containment systems for the meteoric waters in the area “Palte Fosfatiche” (phosphates deposit), located on the territory of Porto Torres site. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up and management of radioactive waste. This investigation has been combined into the abovementioned one.
(vii) Eni Rewind SpA (former Syndial SpA) — Proceeding relating to the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna relating to the crimes of culpable manslaughter, injuries and environmental disaster, which have been allegedly committed by former Eni Rewind employees at the site of Ravenna. The site was acquired by Eni Rewind following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are 75 alleged victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. Eni Rewind asserted the statute of limitation as a defense to the instance of environmental disaster for certain instances of diseases and deaths. The court at Ravenna decided that all defendants would stand trial and held that the statute of limitation only applied with reference to certain instances of crime of culpable injury. Eni Rewind reached some settlements. In November 2016, the Judge acquitted the defendants in all the contested cases except for one, an asbestos case, for which a conviction was handed down. The defendants, the prosecutor 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 proceedings, and appointed three experts. The proceeding is ongoing before the appeals Court.
(viii) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA — Alleged environmental disaster. A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Raffineria di Gela SpA and EniMed SpA relating to environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. The Gela Refinery has been prosecuted for administrative offence pursuant to Legislative Decree No. 231/01. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, and pollution of the sea water near the coastal area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. At the closing of the preliminary investigation, the Public Prosecutor of Gela merged into this proceeding the other investigations related to the pollution that occurred at the other sites of the Gela refinery as well as hydrocarbon spills at facilities of EniMed. The proceeding is ongoing.
(ix) Val d’Agri. In March 2016, the Public Prosecutors of Potenza started a criminal investigation into alleged illegal handling of waste material produced at the Viggiano oil center (COVA), part of the Eni-operated Val d’Agri oil complex. After a two-year investigation, the Prosecutors ordered the house arrest of 5 Eni employees and the seizure of certain plants functional to the production activity of the Val d’Agri complex which, consequently, was shut down (loss of 60 KBOE/d net to Eni). From the commencement of the investigation, Eni has carried out several technical and environmental surveys, with the support of independent experts of international standing, who found a full compliance of the plant and the industrial process with the requirements of the applicable laws, as well as with best available
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technologies and international best practices. The Company implemented certain corrective measures to upgrade plants which were intended to address the claims made by the public prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those corrective measures were favorably reviewed by the Public Prosecutor. The Company restarted the plant in August 2016. In relation to the criminal proceeding, the Public Prosecutor’s Office requested the indictment of all the defendants and the Company. The Prosecutor requested Eni 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 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 ascertain whether there had been illegal environmental pollution by the former COVA officers, the Operation Managers in charge since 2011 and the HSE Manager in charge at the time of the accident, and also against Eni in relation to the same offense pursuant to Legislative Decree No. 231/01 as communicated in December 2018 following the notification of the extension of the terms for preliminary investigations and of some public officials belonging to local administrations for official misconduct, false and fraudulent public statements committed in 2014 and of the crime for environmental disaster and of culpable conduct committed in February 2017. Investigations are ongoing. The Company has paid damages of an immaterial amount 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 Fire Department stating that it does not consider itself obliged to carry out the integration required, considering that the data acquired in the area affected by the event indicate, according to Eni’s assessments, that the loss was promptly and efficiently controlled and there were no situations of serious danger to human health and the environment. In April 2019, precautionary measures were ordered against three Eni employees at the COVA. 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 Eni Mediterranea Idrocarburi SpA — Waste management of the landfill Camastra. In June 2018, the Public Prosecutor of Palermo (Sicily) notified Eni’s subsidiaries Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA of a criminal proceeding relating to allegations of unlawful disposal of industrial waste resulting from the reclaiming activities of soil, which were discharged at a landfill owned by a third party. The Prosecutor charged the then chief executive officers of the two subsidiaries, and the legal entities have been charged with the liability pursuant to Legislative Decree No. 231/01. The alleged wrongdoing related to the willful falsification of the waste certification for purpose of discharging at the landfill. The charge 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 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 and his consultants. Based on this, an appeal was filed against the measure of precautionary seizure of the plant before a review court, which revoked the seizure of the plants on March 26, 2019.
(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 crimes committed by employees in a number of matters, including the violations of laws about safety of the 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 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) — Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore. In May 2003, the Ministry for the Environment claimed compensation from Eni Rewind for alleged environmental damage caused by the activity at the Pieve Vergonte plant in the years 1990 through 1996. In July 2008, the District Court of Turin ordered Eni Rewind to pay environmental damages amounting to €1,833.5 million, plus interests accrued from the filing of the
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decision. Eni and its subsidiary deemed the amount of the environmental damage to be absolutely groundless as the sentence lacked sufficient elements to support such a material amount of the liability from the volume of pollutants ascertained by the Italian Environmental Minister. In July 2009, Eni Rewind filed an appeal and consequently the proceeding continued before a Second Instance Court of Turin that requested a technical appraisal on the matter. The consultants that undertook this appraisal concluded that: (i) no further measure for environmental restoration is required; (ii) there was no significant and measurable impact on the environment of the ecosystem, therefore no restoration or damage compensation should be claimed; the only impact seen concerned fishing activity, with an estimated damage of €7 million which could be already restored through the measures proposed by Eni Rewind, and; (iii) the necessity and convenience of dredging should be excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the Eni Rewind’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. In March 2017, the Second Instance Court: (i) excluded the application of compensation for monetary equivalent; (ii) annulled the monetary compensation of €1.8 billion requesting Eni Rewind to perform the already approved clean-up project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The value of these compensatory works required by the Court, in case of Eni Rewind failure or misperformance, is estimated at €9.5 million. The clean-up project filed by Eni Rewind was ratified by the authorities and is currently being executed. Expenditures expected to be incurred have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were rejected by the court (including compensation for non-material damage). In April 2018, the Ministry for the Environment filed an appeal to the Third Instance Court. 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 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 companies contested these administrative actions, objecting in particular to the nature of the remediation works decided and the methods whereby information on the pollutants concentration has been gathered. A number of administrative proceedings started on this matter were subsequently merged before the Regional Administrative Court. In October 2012, the Court ruled in favor of Eni’s subsidiaries against the Ministry’s requirements for the removal of the pollutants and the construction of a physical barrier. In September 2017, the Ministry notified all the companies involved of a formal notice for the start of remediation and environmental restoration of the Augusta harbor within 90 days. The act, contested by the co-owner companies in December 2017, constitutes a formal notice for environmental damage. The Administrative Council of the Sicilian Region ruled on the appeals pending against various decisions of the Regional Administrative Court and essentially confirmed the cancellation of all administrative provisions subject to the dispute. The annulment of the provisions had, inter alia, retroactive effect to the time of their adoption and therefore excludes the risk of claims of any possible breach of administrative provisions. In June 2019, the Italian Ministry for the Environment set up a permanent technical committee to review the matter of the clean-up and reclamation of the Augusta harbor. 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 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. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and Eni Rewind SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified of a claim issued by the parents of children with birth defects in the Municipality of Gela between 1992 and 2007. The claim called for an inquiry aimed at determining any causality between the birth defects suffered by these children and any environmental pollution caused by the Gela site, quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. The same issue was the subject of previous criminal proceedings, of which one closed without determining any illegal behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. In December 2015, the three companies involved were sued in relation to a total
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of 30 cases of compensation for damages in civil proceedings. In May 2018, the Court issued a first instance judgment concerning one case. The Judge rejected the claim for damages, acknowledging the arguments of the defendant companies in relation to the absence of evidence concerning the existence of a causal link between the birth defects and the alleged industrial pollution. The judgement has been appealed.
(iv) Environmental claim relating to the Municipality of Cengio. Since 2008 a proceeding is pending by the Court of Genoa, brought by the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio. Those parties summoned Eni Rewind before a Civil Court and demanded Eni’s subsidiary compensate for the environmental damage relating to the site of Cengio. The request for environmental damage amounted to €250 million to which was to be added health damage to be quantified during the proceeding. The plaintiffs accused Eni Rewind of negligence in performing the clean-up and remediation of the site. In March 2019, the Ministry for the Environment presented a proposal to Syndial to settle the case. The Company responded with a counter-proposal in July 2019. The judge is verifying the progress and status of the negotiations.
(v) Eni Rewind SpA (former Syndial SpA) and Versalis SpA — Summon for alleged environmental damage caused by illegal waste disposal in the municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Eni Rewind and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff alleged Eni Rewind and Versalis were responsible because they produced the waste and commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001 – 2003 which would have allegedly traced the hazardous waste materials back to the Priolo and Gela industrial sites that are managed by the above-mentioned Eni’s subsidiaries (in particular, the waste with high mercury concentration and railway sleepers no longer in use). Such waste was allegedly handled and disposed illegally at an unauthorized landfill owned by a third party. Two subsidiaries of Eni and a third-party waste company were claimed to be jointly and severally liable for damage amounting to €500 million. The third-party company executed waste disposal at the site. In June 2017, the Judge accepted all the defensive instances of Eni Rewind and Versalis, judging the requests of the Municipality to be inadmissible for lacking right to sue, also considering the requests to be unfounded or unproved, and ordered the Municipality to refund the expenses of the proceeding. In April 2018, the First Instance Judge rejected the counterclaim filed by the Municipality. An appeal by the Municipality before a Third Instance Court is pending.
(vi) Val D’Agri — Eni / Vibac. In September 2019 a claim was brought in the Court of Potenza against Eni. The plaintiffs are eighty people, living in different municipalities of the Val d’Agri area, who are complaining of economic, non-economic, biological and moral damages, all deriving from the presence of Eni’s oil facilities in the territory. In particular, the claim refers to certain events which allegedly caused damage to the local community and the territory (such as a 2017 spill, flaring events since 2014, smelly and noisy emissions). The Judge has been asked to ascertain Eni’s responsibility for causing emissions of polluting substances into the atmosphere. The plaintiffs have also requested Eni be ordered to interrupt any polluting activity and to be allowed to resume industrial activities on condition that all the necessary remediation measures be implemented to eliminate all of the alleged dangerous situations. Finally, they are asking that Eni compensate all direct and indirect property damages, current and future, to an extent to be quantified during the proceedings.
(vii) Eni Spa — Climate change. In 2017 and 2018, local government authorities and a fishing association brought in the courts of the State of California seven proceedings against Eni Group companies and other oil companies. These proceedings claim compensation for the damages attributable to the increase in sea level and temperature, as well as to the hydrogeological instability. The cases have been transferred, by request of the defendants, from the State Courts to the Federal Courts. A specific request has been filed, highlighting the lack of jurisdiction of the State Courts. The proceedings are currently suspended and waiting for a jurisdictional competence.
2. Proceedings concerning criminal/administrative corporate responsibility
(i) EniPower SpA. In 2004, the Public Prosecutor of Milan commenced inquiries into contracts awarded by Eni’s subsidiary EniPower SpA and as to supplies provided by other companies to EniPower SpA. It emerged that illicit payments were made by EniPower SpA suppliers to a manager of EniPower SpA who was immediately fired. The Court served EniPower SpA (the commissioning entity) and
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Snamprogetti SpA, now Saipem SpA (contractor of engineering and procurement services), with notices of investigation pursuant to Legislative Decree No. 231/01. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers pursuant to Legislative Decree No. 231/01. Eni SpA, EniPower SpA and Snamprogetti SpA presented themselves as plaintiffs. In September 2011, the Court of Milan found that nine persons were guilty for the above-mentioned crimes. In addition, they were sentenced jointly and severally to the payment of all damages to be assessed through a specific proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations, while the trial ended with an acquittal of 15 defendants. In reference to the parts involved in the proceeding pursuant to Legislative Decree No. 231/01, the Court found that 7 companies are responsible for the administrative offenses ascribed to them, imposing a fine and the disgorgement of profit. The Court rejected the position as plaintiffs of the Eni Group companies, reversing the prior decision made by the Court. This decision may have been made based on a pronouncement made by a Third Instance Court that stated the illegitimacy of the constitution as plaintiffs against any legal entity, as indicted pursuant to Legislative Decree No. 231/01. The sentenced parties filed appeal against the above-mentioned decision. The Appeal Court issued a ruling that substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. The Third Instance Court successively annulled the judgment of the Second Instance Court ascribing the judgment to another section that, once more, confirmed the sentence of first instance, excepting the rulings of the previous appeal sentence not subject to annulment, including the statute of limitation. The grounds of the sentence have been filed confirming the motivations provided by the previous instance Courts. An appeal was filed at the Third Instance Court solely for the purposes of the civil proceeding.
(ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to Eni’s former subsidiary Saipem in Algeria. In 2011, Eni received from the Public Prosecutor of Milan an information request in accordance with the Italian Code of Criminal Procedure. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem SpA and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem SpA and Technip relating to the engineering of the ground section of a gas pipeline). The crime of international corruption is among the offenses pursuant to Legislative Decree No. 231/01, which provides for corporate liability for crimes committed by employees and prescribes punishments including fines and the disgorgement of profit. Eni also voluntarily provided to the Public Prosecutor documentation relating to the MLE project (in which Eni’s Exploration & Production Division participates), with respect to which investigations in Algeria are ongoing. In November 2012, the Public Prosecutor served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption pursuant to Legislative Decree No. 231/01. Furthermore, the Public Prosecutor requested the production of certain documents relating to certain activities in Algeria. Subsequently, the Public Prosecutor’s Office notified further measures and requests to Saipem, aimed at acquiring further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem SpA, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, the employment of whom was terminated at the beginning of 2013. In February 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced pursuant to Legislative Decree No. 231/01 with respect to Eni, Eni’s former CEO, Eni’s former CFO and another senior manager. Eni’s former CFO had previously served as Saipem’s CFO, including during the period in which alleged corruption took place and before being appointed as CFO of Eni on August 1, 2008. Following receipt of this notice, Eni conducted an internal investigation with the assistance of external consultants, in addition to the review activities performed by its audit and internal control departments and a team dedicated to the Algerian matters. The external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department did not find any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on the MLE project, the only project that Eni understands to be under the prosecutors’
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investigation where the client is an Eni Group company did not find evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling). Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal, accounting and administrative issues. The findings of that review confirmed the autonomy of Saipem from the parent company during the relevant periods. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. In January 2015, the Public Prosecutor notified the conclusion of preliminary investigations relating to Eni, Saipem and eight persons (including, the former CEO and CFO of Eni SpA and the Chief Upstream Officer of Eni SpA who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor issued a notice of alleged international corruption against all such persons (including Eni SpA and Saipem SpA pursuant to Legislative Decree No. 231/01) in connection with the entry into intermediary contracts by Saipem in Algeria. In February 2015, the Public Prosecutor requested the indictment of all the investigated persons for international corruption as well as for tax offenses. In 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni SpA, former Chief Executive Officer and Chief Upstream Officer for all the alleged offenses. In February 2016, the Third Instance Court, upholding an appeal presented by the Public Prosecutor, reversed the dismissal and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of a new preliminary hearing in July 2016, the Judge ordered the trial for all defendants, including Eni SpA. At a hearing in February, 2018, the Public Prosecutor, concluding his indictment, requested — among other things — the imposition on Eni SpA of 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 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 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.
In 2012, Eni contacted the U.S. Department of Justice (DoJ) and the U.S. SEC in order to voluntarily inform them about this matter, and has kept them informed about the developments in the Italian Prosecutors’ investigations and proceedings. Following Eni’s notification, both the U.S. SEC and the DoJ started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests. In September 2019, the 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) Block OPL 245 — Nigeria. A criminal case is pending before the Court of Milan alleging international corruption in connection with the acquisition in 2011 of the OPL 245 exploration block in Nigeria. In July 2014, the Public Prosecutor of Milan served Eni with a notice of investigation pursuant to Italian Legislative Decree No. 231/01. The proceeding was commenced following a claim filed by NGO ReCommon relating to alleged corruptive practices which, according to the Public Prosecutor, allegedly involved the Resolution Agreement made on April 29, 2011 relating to the so-called Oil Prospecting License of the offshore oilfield that was discovered in OPL 245. Eni fully cooperated with the Public Prosecutor and promptly filed the requested documentation. Furthermore, Eni voluntarily reported the matter to the U.S. Department of Justice and the U.S. SEC. In July 2014, Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage an independent, US-based law firm, expert in anticorruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. After reviewing the matter, the U.S. lawyers concluded that they detected no evidence of wrongdoing by Eni in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. In September 2014, the Public Prosecutor notified Eni of a restraining order issued by a British judge who ordered the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the Public Prosecutor. Since the act had also been notified to some persons, including the CEO of Eni and the former Chief Development, Operation & Technology Officer of Eni and the former CEO of Eni, it was assumed that the same had been registered in the register of suspects at the Milan Prosecutor’s office. During a hearing before a court in London in September 2014, Eni and its current executive officers stated their non-involvement in the matter regarding the seized bank account. Following the hearing, the Court
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reaffirmed the seizure. In December 2016, the Public Prosecutor of Milan notified Eni of the conclusion of the preliminary investigation and requested Eni’s CEO, the Chief Development, Operations and Technological Officer and the Executive Vice President for international negotiations to stand trial, as well as Eni’s former CEO and Eni SpA, pursuant to Italian Legislative Decree No. 231/01. Upon the notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor, the independent US-based law firm was requested to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the prior review. The U.S. law firm was also provided with the documentation filed in the Nigerian proceeding mentioned below. The independent U.S. law firm concluded that the reappraisal of the matter in light of the new documentation available did not alter the outcome of the prior review. In September 2019, the DoJ notified Eni that based on the information it currently possessed, the DoJ was closing its investigation of Eni in connection with OPL 245 without the filing of any charges.
In December 2017, the Judge for preliminary investigation ordered the indictment of all the parties mentioned above, and other parties under investigation by the Public Prosecutor, before the Court of Milan. The request of the Federal Government of Nigeria (FGN) for admission as a civil claimant in the proceedings was granted in July 2018. The first instance trial of the Milan Prosecutor’s OPL 245 charges began before the Court of Milan on June 20, 2018 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 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd (“NAE”) became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court upon request from the Nigerian Economic and Financial Crimes Commission (EFCC), attaching OPL 245 temporarily pending a proceeding in Nigeria relating to alleged corruption and money laundering. After making this application, Eni became aware of a formal filing of charges by the EFCC against NAE and other parties. In March 2017, the Nigerian Court revoked the Order. To NAE’s knowledge EFCC charges have not been dropped but none of the defendants were served nor arraigned. In November 2018, Eni SpA and its subsidiaries NAE, NAOC and AENR (as well as some companies of the Shell Group) were notified of the intention of the FGN to bring a civil claim before an English court to obtain compensation for damages allegedly deriving from the transaction that resulted in assignment of the OPL 245 to NAE and Shell subsidiary SNEPCO (Shell subsidiary). On April 15, 2019 the Nigerian subsidiaries NAE, NAOC and AENR received formal notification of the 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.
(iv) Congo. In March 2017, the Italian Finance Police served Eni with an information request in accordance with the Italian Code of Criminal Procedure in connection with an investigative file opened by the Public Prosecutor of Milan against unknown persons. The request related in particular to the agreements signed by Eni Congo SA with the Ministry of Hydrocarbons of the Republic of Congo in 2013, 2014 and 2015 in relation to exploration, development and production activities concerning certain permits held by Eni Congo SA for Congolese projects and Eni’s relationships with Congolese companies that hold stakes in those projects. In July 2017, the Italian Financial Police, on behalf of the Public Prosecutor of Milan, served Eni with another information request and a notice of investigation pursuant to Legislative Decree No. 231/01 for alleged international corruption. The request expressly stated that it was based in part on the March 2017 information request and concerned the relationship of Eni and its subsidiaries with certain third-party companies from 2012 to the present. Eni produced all of the documentation requested in March and July 2017 and voluntarily disclosed this matter to the relevant U.S. authorities (SEC and DoJ). In April 2018, the Public Prosecutor of Milan served Eni SpA with a further request for documentation and notified an Eni employee, who was the then Chief Development, Operation & Technology Officer, of a search order stating that he and another Eni employee had been placed under investigation.
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In December 2018 and subsequently in May and September 2019, Eni was notified by the Public Prosecutor of Milan for documents in accordance with the Italian Code of Criminal Procedure, concerning some economic transactions between Eni Group companies and certain third-party companies. All the required documentation has been produced to the Judge.
In April 2018, the Board of Statutory Auditors, the Watch Structure and the Control and Risk Committee of Eni jointly appointed an independent law firm and a professional consulting company, knowledgeable in the matter of anti-corruption, to carry out a forensic review of facts relating to Eni’s work in Congo. Such review did not find any factual evidence as to the involvement of Eni, nor of any Eni employees and key managers, in the alleged crimes. The report resulting from this review was brought to the attention of the Public Prosecutor and the relevant US authorities (SEC and DoJ).
In September 2019, the Company was informed that the Company’s CEO was served with a search decree and an investigation decree in connection with an alleged violation of article 2629 bis of the Italian Civil Code which penalizes directors of listed companies that fail to communicate conflicts of interest. The alleged omission relates to the supply of logistics and transportation services to certain Eni’s subsidiaries operating in Africa, among which Eni Congo SA, by third-party companies owned by Petroserve Holding BV, in the period 2007-2018. The accusation is based on the allegations that the wife of the Company’s CEO retained a shareholding of the above-mentioned holding company over part of the period of time under investigation. The Board of Directors of Eni spa has never been involved in any resolution concerning the suppliers under investigation.
In November 2019, following the notification of further investigative documents, the Board of Statutory Auditors, the Control and Risk Committee and the Watch Structure of Eni asked the consultants, which had been engaged in 2018, also to review the conclusions reached, in the light of the documentation made available following the decree notified to the CEO in September 2019. The second report of the consultants, which was delivered in February 2020, still of a preliminary nature and subject to modifications and follow-up, updates the conclusions reached by the first report and indicated that: (i) it is probable that the CEO’s wife held a shareholding in the Petroserve Group for a few years starting from 2009 until 2012 and in any case no later than the date the CEO was appointed Board member; (ii) there is an absence of evidence to contradict the statements made by the CEO as to his lack of knowledge of his wife’s interests in the ownership of Petroserve Group.
3. Other proceedings concerning criminal matters
(i) Eni SpA (R&M) — Criminal proceedings on fuel excise tax. A criminal proceeding is currently pending, relating to alleged evasion of excise taxes in the context of retail sales in the fuel market. In particular, the claim states that the quantity of oil products marketed by Eni was larger than the quantity subjected to the excise tax. This proceeding (No. 7320/2014 RGNR) concerns the combination of three distinct investigations: (i) A first proceeding, opened by the Public Prosecutor’s Office of Frosinone involved a company (Turrizziani Petroli) purchaser of Eni’s fuel. This investigation was subsequently extended to Eni. The Company fully cooperated and provided all data and information concerning the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. On June 24, 2019, a settlement agreement was signed between Eni and the Customs Agency, involving the determination of the excise tax of €73 thousand and the reimbursement to Eni of the exceeding amounts paid while the judgment was pending. Consequently, an application to cease the dispute was presented to the Tax Commission. (ii) A second proceeding, concerning an investigation by the Public Prosecutor’s Office of Prato, commenced in regard to the deposit of Calenzano and relates to abduction of fuel through manipulation of the fuel dispensers, subsequently extended also to the Refinery of Stagno (Livorno); (iii) A third proceeding, opened by the Public Prosecutor’s Office of Rome, concerns alleged missing payment of excise tax on the surplus of the unloading products, as the quantity of such products was larger than the quantity reported in the supporting fiscal documents. This proceeding represents a development of the first proceeding mentioned above and substantially concerns similar facts presenting, however, some differences with regard to the nature of the alleged crimes and the responsibility.
The Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at habitual abduction of oil products at all of the 22 storage sites which are operated by Eni in Italy. Eni is cooperating with the Prosecutor in order to defend the correctness of its operation. In September 2014, a
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search was conducted at the office of the former chief of the R&M Division in Rome. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also relate to a period of time when the officer was in charge at Eni’s R&M Division. In March 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer at the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. The proceeding was then extended to a large number of employees and former employees of the Company. Eni has continued to provide full cooperation to the authorities.
During the course of 2018, as part of the general proceeding no. 7320/2014, the Public Prosecutor of Rome notified the conclusion of the preliminary investigations in relation to the criminal proceeding concerning the Calenzano, Pomezia, Naples, Gaeta and Ortona storage sites and the Livorno and Sannazzaro refineries. Based on the outcome of the investigations, as far as Eni is concerned, the proceeding involves former managers and directors of the logistic sites and refineries indicated above concerning alleged aggravated and continuous non-payment of excise duties, alteration and removal of seals, use and possession of false measures and weights instruments. In addition for the Calenzano site, three employees and their manager of the storage site were accused of alleged procedural fraud.
In September 2018, Eni received, as injured party, the notification of the schedule of hearing issued by the Court of Rome, in relation to criminal association and other minor claims, against numerous persons under investigation — including over forty Eni employees — subject of a separated proceeding (No. 22066/17 RGNR), for which, in May 2017, the Public Prosecutor’s Office had requested the dismissal. At the end of the hearing in December 2018, the Judge accepted the request for dismissal for several persons under investigation, including thirteen Eni employees. The Judge also initially rejected the request of indictment for criminal association relating twenty-eight Eni employees (including the former managers of the R&M Division).
As part of the separate proceeding no. 22066/2017 RGNR, following the re-filing by the Public Prosecutor of the indictment for criminal association, following a preliminary hearing, the judge resolved to dismiss the case against all of the defendants because allegations were found to be groundless.
In April 2018 as part of the administrative proceeding intended to collect taxes allegedly unpaid by Eni, the tax police of Rome based on the findings of the investigations performed by the prosecutors of Frosinone, Prato and Rome issued a statement of objection against the Company claiming the missed payment of excise taxes due for the years 2008 up to 2017 for €34 million, as well as the related higher corporate profits before income taxes leading to the claim of additional taxes for €22 million related to income taxes and VAT. The Custom Agency that is in charge of issuing the notice of payment may also impose a fine and the recognition of interest expense. A part of the disputed amounts for excise taxes and other related taxes concerned the same litigation, which was successfully challenged by the Company following a recourse filed with the Tax Commission of Rome and in relation to which the Company agreed upon an extrajudicial transaction with the Tax Authorities.
Following the documentation presented by the company, the Customs Agency determined the excise tax due in the amount of €8 million by issuing the payment notices in July 2019. Furthermore, the Agency estimated €6 million of other related taxes. The Company has paid the amounts determined by the Agency.
(ii) Eni SpA — Public Prosecutor of Milan — Criminal proceeding no. 12333/2017. In February 2018, Eni was notified of a search and seizure decree in relation to allegations of associative crime aimed at slander and at reporting false information to a Public Prosecutor. In the decree, the Prosecutor of Milan included, among the other persons under investigation, a former external lawyer and a former Eni manager, at the time of the facts holding strategic positions in the Company. According to the decree, the association is allegedly aimed at interfering with the judicial activity in certain criminal proceedings that are involving, among others, Eni and some of its directors and managers. Afterwards, the Control and Risks Committee, having consulted the Board of Statutory Auditors, and together with the Watch Structure, agreed to engage an auditing firm to perform an internal audit of all relevant facts and circumstances and all records and documentation relating to the matter with respect to the events of the aforementioned proceeding,
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including a forensic review. The final report, submitted to the Control and Risk Committee, the Watch Structure and the Board of Statutory Auditors on September 12, 2018, concluded that following the review carried out with respect to the allegations made by the Public Prosecutor of Milan, there was not sufficient factual evidence to prove the involvement of the aforementioned former manager of Eni in the alleged crimes. On April 19, 2018, the Board of Directors appointed two external consultants, a criminal lawyer and a civil lawyer to provide independent legal advice in relation to the facts under investigation. Their report, dated November 22, 2018, did not find facts which could suggest any involvement of any Eni employees in the crimes alleged by the Public Prosecutor. On June 4, 2018, Consob, the Italian market regulator, requested to be informed about the above mentioned proceeding. The request was addressed to the Company and to its Board of Statutory Auditors.
Specifically, Consob asked for the outcome of the forensic review and to be updated about any other audit action taken in relation to the matter by the Company and by its Board of Statutory Auditors. The Board of Statutory Auditors was also requested to report about the findings of the additional audit program agreed with an external auditor regarding the matter and to keep Consob updated about any further initiatives adopted. The Company answered the request on June 11, 2018. Subsequently, the Company finalized its response by sending further documentation including the final report of the independent third party and the reports of the consultants of the Board of Directors. The Board of Statutory Auditors has periodically updated Consob of the initiatives taken as part of the Board’s monitoring responsibilities with several communications. On June 13, 2018, Eni was notified of a request from the Prosecutor Office to transmit certain documentation in accordance with the Italian Code of Criminal Procedure. The request targeted evidence and documents relating to the internal audit performed by the Company and any possible external review concerning certain tasks that had been assigned to the former external lawyer with respect to Eni. This lawyer appears to be investigated as part of this proceeding. The reports of the independent third party and of the consultant of the Board of directors were also sent to the Public Prosecutor.
In May and June 2019, in the context of the same proceeding, the Court of Milan notified Eni and three of its subsidiaries (ETS Spa, Versalis Spa, Ecofuel Spa) of various requests for documentation in accordance with the Italian Code of Criminal Procedure. At the same time, on May 23, 2019, Eni was served a notice that the Company is being investigated pursuant to Legislative Decree No. 231/01, with reference to the crime sanctioned by the Italian Penal Code concerning “inducement not to make statements or to make false statements to the judicial authority”.
The object of the aforementioned requests particularly concerns the relations with two business partners, access to Eni offices of certain third parties, also on behalf of one of the above-mentioned business partners, the mailbox of some employees and former employees, the documentation concerning the relations (and the interruption of those relations) with the former external lawyer investigated in the proceeding, the internal audit reports and the reports of the Company’s bodies that dealt with assessing these relationships. Following internal audits, on June 21, 2019, the Company sued for fraud a former employee at its subsidiary ETS, who was fired on May 28, 2019, and also filed a complaint before the Judicial Authority to ascertain possible complicity in fraud of other third parties.
On August 14, 2019, the Italian tax police sent a new request for information to Eni, concerning the economic relations between Eni Group companies and an external professional.
In November 2019, Eni received a notice to extend the preliminary investigations. The notice also covered the investigations of the alleged breach of certain provisions of Italian Law Decree 231/01 on part of Eni. Furthermore, it was ascertained that certain former Eni employees have been charged with various criminal allegations. Those employees were a former manager of Eni’s legal department, the former Chief Upstream Officer of Eni and an employee that was fired in 2013. A number of third parties have also been indicted, among them, two former legal consultants of Eni. On January 23, 2020, a search decree and an indictment were notified to the Company’s Chief Services & Stakeholder Relations Officer, the Senior Vice President for Security and to a manager of the legal department. Moreover, further procedural documentation became available following requests to review the aforementioned decree. The Board of Statutory Auditors, the Control Committee and the Watch Structure have instructed the same consultants appointed in 2018 to examine the aforementioned documentation, in order to review and summarize the facts underlying those allegations, as well as other factual elements and conduct to be examined in depth relating to the existence of any substantial issue or possible deficiency in the internal control and risk management system and in the organization and risk management model pursuant to Legislative Decree No. 231/01. The consultant’s activities are ongoing.
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(iii) Eni SpA — Public Prosecutor of Milan — Insider trading. In March 2019, a request for extending certain investigations was notified to Eni’s Chief Upstream Officer by the public prosecutor office of Milan. The commencement of those investigation was otherwise not notified. The investigations related to an alleged breach of Italian provisions that regulate insider trading and access to market-sensitive information. The breach was allegedly made from November 1 to December 1, 2016. There were no more informative details about the alleged breach in the notified document.
4. Tax proceedings
(i) Dispute for omitted payment of a property tax for some oil offshore platforms located in territorial waters. A Third Instance Court in Italy with a ruling issued in 2016 established that oil&gas offshore platforms located within territorial boundaries were subject to a property tax, resolving a dispute that has been in progress for about a decade in favor of local authorities. Eni was a party to many of these disputes and has entered into settlement transactions with various local authorities. Currently, a risk provision €17 million has been set aside in the consolidated financial statements for the remaining pending litigations.
The Third Instance Court ruling applied to the legislation in force until 2015. Since 2016 the regulatory framework has changed due to enactment of law no. 208/2015, which excluded from the scope of the property tax the value of plants instrumental to specific production processes. To clarify the effects of this scope limitation of the property tax relating to above-mentioned offshore platforms, in 2016 the Italian association of oil&gas producers submitted a question to the Italian Finance Department. The Department recognized that offshore platforms met the requirements for classification as instrumental plants and consequently are excluded from the scope of the property tax (resolution no. 3/DF of June 1, 2016).
The ruling of the Department of Finance, however, is not binding for local authorities with taxing powers and three of these have issued assessment notices for 2016 and subsequent years. The Company has challenged these notices in legal proceedings. To date two first instance judgments have been issued, one in favor of the Company and one against. A second instance judgement has also been issued with results unfavorable to the Company. Of the two unfavorable outcomes, only one applies penalties. One of the two unfavorable judgements concerns the dispute with the municipality of Ravenna for the years 2016 and 2017, that judgement confirmed the assessment made by the municipality for a total tax of €19 million, in addition to the penalties applicable by law.
Based on the resolution of the Department of Finance in 2016, Eni believes that the scope limitation of the tax property enacted in 2016 applies to offshore platforms located within territorial boundaries and based on this the Company intends to continue to contest the assessment. No risk provisions have been accrued in the consolidated financial statements.
Law Decree 124/2019 (enacted with Law 157/2019) has established, starting from 2020, that marine platforms are subject to a new property tax that will replace and supersede any other ordinary local property tax eventually levied on these plants up to 2019. This rule has therefore sanctioned, starting from 2020, the existence of the tax requirement for these plants.
5. Settled Proceedings
(i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. In January 2013, the Italian airline company Alitalia summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to seek a compensation for alleged damages caused by alleged anti-competitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a decision rendered by the Italian Antitrust Authority in June 2006. The antitrust decision accused Eni and another five petroleum companies of anti-competitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. In June 2019 the lawsuit was settled between all the involved parties. The amount transacted by Eni was previously accrued in the financial statements.
(ii) Eni SpA — Public Prosecutor’s Office of Rome — Criminal Procedure No. 2711/2019 — VAT returns. On September 16, 2019, a notice of extension of the preliminary investigations was notified to the former CEO and the current CEO of Eni, in relation to the tax crime referred to in art. 4 of Legislative
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Decree 74/2000 (unfaithful tax statement). From the first investigations carried out by the defense attorney, the allegations referred to the criminal proceedings on fuel excise taxes, disclosed in the previous section and derived from the alleged taxes due on the higher profit before taxation ascertained as a result of evading the owed amounts of excise taxes for fiscal years from 2011 to 2014. As a result of the defensive activities carried out and due to the transaction carried out with the Customs and Revenue Agency, in November 2019 the Prosecutor filed a request to dismiss the proceedings and on December 2, 2019 the Court of Rome issued an order of dismissal.
(iii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for the gas supplied in the 2012 – 2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. The arbitration award dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considered that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra claimed an additional amount to be paid by Eni which corresponded to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, did not agree with GasTerra’s interpretation and considered GasTerra’s claim groundless. However, GasTerra, based on its own interpretation, commenced an arbitration and obtained from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV for the alleged receivable due by Eni (equal to €1.01 billion). With respect to the interim seizure measure obtained by GasTerra, Eni offered to GasTerra, who in turn accepted, a bank guarantee of the same amount of the GasTerra claim. On July 8, 2019, the Tribunal issued an award concluding the first phase of the procedure by which it decided, in particular, that the provisional price mentioned above continued to apply in the 2012 – 2015 period, and that therefore GasTerra was not entitled to any price adjustment, so the invoices issued after the rendering of the award in 2016 were invalid. The Tribunal referred to the second phase of the arbitral procedure the quantification of Eni’s claims for damages against GasTerra. On July 24, 2019, upon Eni’s request and GasTerra consent, the bank guarantee for €1.01 billion was terminated. GasTerra has reserved its rights of appeal.
Assets under concession arrangements
Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing business line. In the Exploration & Production segment, contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. Pursuant to the assignment of mineral concessions, Eni sustains all the operational risks and costs related to the exploration and development activities and it is entitled to the productions realized. As a compensation for mineral 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 quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration.
Environmental regulations
In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management
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does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.
Emission trading
From 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The new phase marked a significant change in the method of awarding emission allowance from a no-consideration scheme based on historical emissions to allocation through auctioning. For the period 2013 – 2020, the award of free emission allowances is performed based on European benchmarks specific to each industrial segment, except for the thermoelectric sector that is not eligible for allocations for no consideration. This regulatory scheme implies for Eni’s plants subjected 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 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 19.30 million tonnes, Eni was awarded free emission allowances of 7.73 million tonnes, determining a deficit of 11.57 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market.
28 Revenues and other income
Sales from operations

​ | ​ | ​ | ​ | ​
(€ 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 | ​ | ​

Sales from operations by industry segment and geographical area of destination are disclosed in note 35 — Segment information and information by geographic area.
Sales from operations with related parties are disclosed in note 36 — Transactions with related parties.
Other income and revenues

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Gains from sale of assets and businesses | ​ | ​ | ​ | ​ | 152 | ​ | ​ | ​ | ​ | ​ | 454 | ​ | ​ | ​ | ​ | ​ | 3,288 | ​ | ​
Other proceeds | ​ | ​ | ​ | ​ | 1,008 | ​ | ​ | ​ | ​ | ​ | 662 | ​ | ​ | ​ | ​ | ​ | 770 | ​ | ​
​ | ​ | ​ | ​ | ​ | 1,160 | ​ | ​ | ​ | ​ | ​ | 1,116 | ​ | ​ | ​ | ​ | ​ | 4,058 | ​ | ​

In 2019, gains from the sale of assets and businesses related for €146 million to assets of the Exploration & Production segment.
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In 2018, gains from the sale of assets and businesses related to the divestment of a 10% stake in the Zohr project for €428 million. In 2017, the amount related to the divestment of a 25% stake in natural gas-rich Area 4 offshore Mozambique (€1,985 million) and of a 40% stake in the Zohr project (€1,281 million).
Other proceeds include €368 million related to the recovery of the cost share of right-of-use assets pertaining to partners of non-incorporated joint operations operated by Eni.
Other income and revenues with related parties are disclosed in note 36 — Transactions with related parties.
29 Costs
Purchase, services and other charges

​ | ​ | ​ | ​ | ​
(€ 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 | ​ | ​

Purchase, services and other charges include geological and geophysical costs of exploration activities for €275 million (€287 million and €273 million in 2018 and 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 activities expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €194 million (€197 million and €185 million in 2018 and 2017, respectively).
Royalties on the extraction of hydrocarbons amounted to €1,183 million (€1,043 million and €674 million in 2018 and 2017, respectively).
Additions to provisions net of reversal of unused provisions 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 €329 million (net provisions of €266 million and €200 million in 2018 and 2017, respectively). More information is provided in note 20 — Provisions. Net additions to provisions by segment are disclosed in note 35 — Segment information and information by geographic area.
Information about leases is disclosed in note 12 — Right-of-use assets and lease liabilities.
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Payroll and related costs

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Wages and salaries | ​ | ​ | ​ | ​ | 2,417 | ​ | ​ | ​ | ​ | ​ | 2,409 | ​ | ​ | ​ | ​ | ​ | 2,447 | ​ | ​
Social security contributions | ​ | ​ | ​ | ​ | 449 | ​ | ​ | ​ | ​ | ​ | 448 | ​ | ​ | ​ | ​ | ​ | 441 | ​ | ​
Cost related to employee benefit plans | ​ | ​ | ​ | ​ | 85 | ​ | ​ | ​ | ​ | ​ | 220 | ​ | ​ | ​ | ​ | ​ | 113 | ​ | ​
Other costs | ​ | ​ | ​ | ​ | 213 | ​ | ​ | ​ | ​ | ​ | 170 | ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​
​ | ​ | ​ | ​ | ​ | 3,164 | ​ | ​ | ​ | ​ | ​ | 3,247 | ​ | ​ | ​ | ​ | ​ | 3,163 | ​ | ​
less: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- capitalized direct costs associated with self-constructed assets - tangible assets | ​ | ​ | ​ | ​ | (152) | ​ | ​ | ​ | ​ | ​ | (142) | ​ | ​ | ​ | ​ | ​ | (202) | ​ | ​
- capitalized direct costs associated with self-constructed assets - intangible assets | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | (12) | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​
​ | ​ | ​ | ​ | ​ | 2,996 | ​ | ​ | ​ | ​ | ​ | 3,093 | ​ | ​ | ​ | ​ | ​ | 2,951 | ​ | ​

Other costs comprised provisions for redundancy incentives of €45 million (€37 million and €18 million in 2018 and 2017, respectively) and costs for defined contribution plans of €99 million (€95 million and €90 million in 2018 and 2017, respectively).
Cost related to employee benefit plans are described in note 21 — Provisions for employee benefits.
Costs with related parties are disclosed in note 36 — Transactions with related parties.
Average number of employees
The Group average number and breakdown of employees by category is reported below:

​ | ​ | ​ | ​ | ​
(number) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
​ | 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 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”)3 7 and the TSR of their corresponding stock exchange market3 8; (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 consisted of the following:

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Wages and salaries | ​ | ​ | ​ | ​ | 28 | ​ | ​ | ​ | ​ | ​ | 27 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​
Post-employment benefits | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
Other long-term benefits | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​
Indemnities upon termination of employment | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​
​ | ​ | ​ | ​ | ​ | 54 | ​ | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to €9.2 million, €9.6 million and €14.5 million for 2019, 2018 and 2017, respectively. Compensation of Statutory Auditors amounted to €0.613 million, €0.604 million and €0.760 million in 2019, 2018 and 2017, respectively.
Compensation included emoluments and social security benefits due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group, even if not subject to personal income tax.
​
3 7
The group consists of the following oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and Total.
​
3 8
The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition.
​
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30 Finance income (expense)

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Finance income (expense) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Finance income | ​ | ​ | ​ | ​ | 3,087 | ​ | ​ | ​ | ​ | ​ | 3,967 | ​ | ​ | ​ | ​ | ​ | 3,924 | ​ | ​
Finance expense | ​ | ​ | ​ | ​ | (4,079) | ​ | ​ | ​ | ​ | ​ | (4,663) | ​ | ​ | ​ | ​ | ​ | (5,886) | ​ | ​
Net finance income (expense) from financial assets held for trading | ​ | ​ | ​ | ​ | 127 | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | (111) | ​ | ​
Income (expense) from derivative financial instruments | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | (307) | ​ | ​ | ​ | ​ | ​ | 837 | ​ | ​
​ | ​ | ​ | ​ | ​ | (879) | ​ | ​ | ​ | ​ | ​ | (971) | ​ | ​ | ​ | ​ | ​ | (1,236) | ​ | ​

The analysis of finance income (expense) was as follows:

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Finance income (expense) related to net borrowings | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest and other finance expense on ordinary bonds | ​ | ​ | ​ | ​ | (618) | ​ | ​ | ​ | ​ | ​ | (565) | ​ | ​ | ​ | ​ | ​ | (638) | ​ | ​
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 | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​
Interest and other income on financial receivables and securities held for non-operating purposes | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​
​ | ​ | ​ | ​ | ​ | (962) | ​ | ​ | ​ | ​ | ​ | (627) | ​ | ​ | ​ | ​ | ​ | (834) | ​ | ​
Exchange differences | ​ | ​ | ​ | ​ | 250 | ​ | ​ | ​ | ​ | ​ | 341 | ​ | ​ | ​ | ​ | ​ | (905) | ​ | ​
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 | ​ | ​ | ​ | ​ | 93 | ​ | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | 73 | ​ | ​
Finance expense due to the passage of time (accretion discount)﻿(a) | ​ | ​ | ​ | ​ | (255) | ​ | ​ | ​ | ​ | ​ | (249) | ​ | ​ | ​ | ​ | ​ | (264) | ​ | ​
Other finance income (expense) | ​ | ​ | ​ | ​ | (103) | ​ | ​ | ​ | ​ | ​ | (313) | ​ | ​ | ​ | ​ | ​ | (271) | ​ | ​
​ | ​ | ​ | ​ | ​ | (153) | ​ | ​ | ​ | ​ | ​ | (378) | ​ | ​ | ​ | ​ | ​ | (334) | ​ | ​
​ | ​ | ​ | ​ | ​ | (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.
​
Information about leases is disclosed in note 12 — Right-of-use assets and lease liabilities.
The analysis of income (expense) from derivative financial instruments is disclosed in note 23 — Derivative financial instruments and hedge accounting.
Operating expenses with related parties are disclosed in note 36 — Transactions with related parties.
31 Income (expense) from investments
Share of profit (loss) of equity-accounted investments
More information is provided in note 15 — Investments.
Share of profit or loss of equity accounted investments by industry segment is disclosed in note 35 — Segment information and information by geographic area.
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Other gain (loss) from investments

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Dividends | ​ | ​ | ​ | ​ | 247 | ​ | ​ | ​ | ​ | ​ | 231 | ​ | ​ | ​ | ​ | ​ | 205 | ​ | ​
Net gain (loss) on disposals | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​ | ​ | ​ | ​ | 163 | ​ | ​
Other net income (expense) | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | 910 | ​ | ​ | ​ | ​ | ​ | (33) | ​ | ​
​ | ​ | ​ | ​ | ​ | 281 | ​ | ​ | ​ | ​ | ​ | 1,163 | ​ | ​ | ​ | ​ | ​ | 335 | ​ | ​

Dividend income primarily related to Nigeria LNG Ltd for €186 million and to Saudi European Petrochemical Co for €46 million (€187 million and €35 million in 2018 and €167 million and €21 million in 2017, respectively).
In 2018, other net income included a gain of €889 million deriving from the business combination between Eni Norge AS and Point Resources AS, with the establishment of joint venture the Vår Energi AS, determined by the difference between the book value of the investment corresponding to the fair value of the combined net assets and the book value of the net assets sold.
32 Income taxes

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Current taxes: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Italian subsidiaries | ​ | ​ | ​ | ​ | 347 | ​ | ​ | ​ | ​ | ​ | 301 | ​ | ​ | ​ | ​ | ​ | 712 | ​ | ​
- subsidiaries of the Exploration & Production segment - outside Italy | ​ | ​ | ​ | ​ | 4,729 | ​ | ​ | ​ | ​ | ​ | 4,906 | ​ | ​ | ​ | ​ | ​ | 3,167 | ​ | ​
- other subsidiaries - outside Italy | ​ | ​ | ​ | ​ | 152 | ​ | ​ | ​ | ​ | ​ | 163 | ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​
​ | ​ | ​ | ​ | ​ | 5,228 | ​ | ​ | ​ | ​ | ​ | 5,370 | ​ | ​ | ​ | ​ | ​ | 4,021 | ​ | ​
Net deferred taxes: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- Italian subsidiaries | ​ | ​ | ​ | ​ | 599 | ​ | ​ | ​ | ​ | ​ | 130 | ​ | ​ | ​ | ​ | ​ | (464) | ​ | ​
- subsidiaries of the Exploration & Production segment - outside Italy | ​ | ​ | ​ | ​ | (172) | ​ | ​ | ​ | ​ | ​ | 497 | ​ | ​ | ​ | ​ | ​ | (162) | ​ | ​
- other subsidiaries - outside Italy | ​ | ​ | ​ | ​ | (64) | ​ | ​ | ​ | ​ | ​ | (27) | ​ | ​ | ​ | ​ | ​ | 72 | ​ | ​
​ | ​ | ​ | ​ | ​ | 363 | ​ | ​ | ​ | ​ | ​ | 600 | ​ | ​ | ​ | ​ | ​ | (554) | ​ | ​
​ | ​ | ​ | ​ | ​ | 5,591 | ​ | ​ | ​ | ​ | ​ | 5,970 | ​ | ​ | ​ | ​ | ​ | 3,467 | ​ | ​

Current income taxes payable by Italian subsidiaries referred to foreign taxes for €137 million.
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The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (same amount in 2018 and 2017) and the effective tax charge is the following:

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Profit (loss) before taxation | ​ | ​ | ​ | ​ | 5,746 | ​ | ​ | ​ | ​ | ​ | 10,107 | ​ | ​ | ​ | ​ | ​ | 6,844 | ​ | ​
Tax rate (IRES) (%) | ​ | ​ | ​ | ​ | 24.0 | ​ | ​ | ​ | ​ | ​ | 24.0 | ​ | ​ | ​ | ​ | ​ | 24.0 | ​ | ​
Statutory corporation tax charge (credit) on profit or loss | ​ | ​ | ​ | ​ | 1,379 | ​ | ​ | ​ | ​ | ​ | 2,426 | ​ | ​ | ​ | ​ | ​ | 1,643 | ​ | ​
Increase (decrease) resulting from: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- higher tax charges related to subsidiaries outside Italy | ​ | ​ | ​ | ​ | 2,934 | ​ | ​ | ​ | ​ | ​ | 3,096 | ​ | ​ | ​ | ​ | ​ | 1,882 | ​ | ​
- 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 | ​ | ​ | ​ | ​ | 65 | ​ | ​ | ​ | ​ | ​ | 47 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
- Italian regional income tax (IRAP) | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 61 | ​ | ​
- effect due to non-taxable gains/losses on sales of investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (177) | ​ | ​
- other adjustments | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | 69 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​
​ | ​ | ​ | ​ | ​ | 4,212 | ​ | ​ | ​ | ​ | ​ | 3,544 | ​ | ​ | ​ | ​ | ​ | 1,824 | ​ | ​
Effective tax charge | ​ | ​ | ​ | ​ | 5,591 | ​ | ​ | ​ | ​ | ​ | 5,970 | ​ | ​ | ​ | ​ | ​ | 3,467 | ​ | ​

The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €2,934 million (€3,014 million and €1,811 million in 2018 and in 2017, respectively).
33 Earnings per share
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.
The average number of ordinary shares used for the calculation of the basic earnings per share 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, 2019, the shares that could be potentially issued related the estimation of new shares that 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 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 for evaluation of oil&gas resources

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Revenues related to exploration activity and evaluation | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​
Exploration activity and evaluation costs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- write-off of exploration and evaluation costs | ​ | ​ | ​ | ​ | 214 | ​ | ​ | ​ | ​ | ​ | 93 | ​ | ​ | ​ | ​ | ​ | 252 | ​ | ​
- costs of geological and geophysical studies | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 287 | ​ | ​ | ​ | ​ | ​ | 273 | ​ | ​
Exploration expense for the year | ​ | ​ | ​ | ​ | 489 | ​ | ​ | ​ | ​ | ​ | 380 | ​ | ​ | ​ | ​ | ​ | 525 | ​ | ​
Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs | ​ | ​ | ​ | ​ | 1,031 | ​ | ​ | ​ | ​ | ​ | 1,081 | ​ | ​ | ​ | ​ | ​ | 995 | ​ | ​
Tangible assets: capitalized exploration and evaluation costs | ​ | ​ | ​ | ​ | 1,563 | ​ | ​ | ​ | ​ | ​ | 1,267 | ​ | ​ | ​ | ​ | ​ | 1,371 | ​ | ​
Total tangible and intangible assets | ​ | ​ | ​ | ​ | 2,594 | ​ | ​ | ​ | ​ | ​ | 2,348 | ​ | ​ | ​ | ​ | ​ | 2,366 | ​ | ​
Provision for decommissioning related to exploration activity and evaluation | ​ | ​ | ​ | ​ | 109 | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​ | ​ | ​ | ​ | 81 | ​ | ​
Exploration expenditure (net cash used in investing activivties) | ​ | ​ | ​ | ​ | 586 | ​ | ​ | ​ | ​ | ​ | 463 | ​ | ​ | ​ | ​ | ​ | 442 | ​ | ​
Geological and geophysical costs (cash flow from operating activities) | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 287 | ​ | ​ | ​ | ​ | ​ | 273 | ​ | ​
Total exploration effort | ​ | ​ | ​ | ​ | 861 | ​ | ​ | ​ | ​ | ​ | 750 | ​ | ​ | ​ | ​ | ​ | 715 | ​ | ​

35 Segment information and information by geographic area
Segment information
Eni’s segmental reporting reflects the Group’s operating segments, whose results are regularly reviewed by the chief operating decision maker (the CEO) to 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.
As of December 31, 2019, Eni had the following reportable segments:
•
Exploration & Production: engages in the research, development and production of crude oil and natural gas, including projects to build and operate liquefaction plants of LNG;
​
•
Gas & Power: engages in supply and marketing of natural gas at wholesale and retail markets, supply and marketing of LNG and supply, production and marketing of power at retail and wholesale markets. Gas & Power 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’s industrial and commercial margins according to an integrated view and to optimize margins.
​
•
Refining & Marketing and Chemical: engages in the manufacturing, supply and distribution and marketing activities of oil products and chemical products. The results of the Chemicals business have been aggregated to those of the Refining & Marketing business in a single reportable segment, because these two operating segments exhibit similar economic characteristics.
​
•
Corporate and Other activities: include the costs of the Group HQ functions which provide services to the operating subsidiaries, comprising holding, financing and treasury, IT, HR, real estate, legal assistance, captive insurance, as well as the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind SpA (former Syndial SpA). The Energy Solutions Department, which engages in developing the renewable energy business, is an operating segment, which is reported within Corporate and Other activities because it does not meet the materiality threshold set by IFRS 8 for separate segment reporting.
​
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Information by segment is as follows:

(€ million) | ​ | ​ | Exploration & Production | ​ | ​ | Gas & Power | ​ | ​ | Refining & Marketing and Chemical | ​ | ​ | Corporate and Other activities | ​ | ​ | Adjustments of intragroup profits | ​ | ​ | Total | ​
2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations including intersegment sales | ​ | ​ | ​ | ​ | 23,572 | ​ | ​ | ​ | ​ | ​ | 50,015 | ​ | ​ | ​ | ​ | ​ | 23,334 | ​ | ​ | ​ | ​ | ​ | 1,681 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Less: intersegment sales | ​ | ​ | ​ | ​ | (13,073) | ​ | ​ | ​ | ​ | ​ | (11,855) | ​ | ​ | ​ | ​ | ​ | (2,317) | ​ | ​ | ​ | ​ | ​ | (1,476) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations | ​ | ​ | ​ | ​ | 10,499 | ​ | ​ | ​ | ​ | ​ | 38,160 | ​ | ​ | ​ | ​ | ​ | 21,017 | ​ | ​ | ​ | ​ | ​ | 205 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 69,881 | ​ | ​
Operating profit | ​ | ​ | ​ | ​ | 7,417 | ​ | ​ | ​ | ​ | ​ | 699 | ​ | ​ | ​ | ​ | ​ | (854) | ​ | ​ | ​ | ​ | ​ | (710) | ​ | ​ | ​ | ​ | ​ | (120) | ​ | ​ | ​ | ​ | ​ | 6,432 | ​ | ​
Net provisions for contingencies | ​ | ​ | ​ | ​ | 97 | ​ | ​ | ​ | ​ | ​ | 232 | ​ | ​ | ​ | ​ | ​ | 273 | ​ | ​ | ​ | ​ | ​ | 307 | ​ | ​ | ​ | ​ | ​ | (51) | ​ | ​ | ​ | ​ | ​ | 858 | ​ | ​
Depreciation and amortization | ​ | ​ | ​ | ​ | (7,060) | ​ | ​ | ​ | ​ | ​ | (447) | ​ | ​ | ​ | ​ | ​ | (485) | ​ | ​ | ​ | ​ | ​ | (146) | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | (8,106) | ​ | ​
Impairments of tangible and intangible assets and right-of-use assets | ​ | ​ | ​ | ​ | (1,347) | ​ | ​ | ​ | ​ | ​ | (83) | ​ | ​ | ​ | ​ | ​ | (1,127) | ​ | ​ | ​ | ​ | ​ | (13) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (2,570) | ​ | ​
Reversals of tangible and intangible assets | ​ | ​ | ​ | ​ | 130 | ​ | ​ | ​ | ​ | ​ | 46 | ​ | ​ | ​ | ​ | ​ | 205 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 382 | ​ | ​
Write-off of tangible and intangible assets | ​ | ​ | ​ | ​ | (292) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (6) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (300) | ​ | ​
Share of profit (loss) of equity-accounted investments | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | (11) | ​ | ​ | ​ | ​ | ​ | (63) | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (88) | ​ | ​
Identifiable assets(a) | ​ | ​ | ​ | ​ | 68,915 | ​ | ​ | ​ | ​ | ​ | 9,176 | ​ | ​ | ​ | ​ | ​ | 12,336 | ​ | ​ | ​ | ​ | ​ | 1,860 | ​ | ​ | ​ | ​ | ​ | (492) | ​ | ​ | ​ | ​ | ​ | 91,795 | ​ | ​
Unallocated assets(b) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 31,645 | ​ | ​
Equity-accounted investments | ​ | ​ | ​ | ​ | 4,108 | ​ | ​ | ​ | ​ | ​ | 487 | ​ | ​ | ​ | ​ | ​ | 3,107 | ​ | ​ | ​ | ​ | ​ | 1,333 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 9,035 | ​ | ​
Identifiable liabilities(c)​ | ​ | ​ | ​ | ​ | 20,164 | ​ | ​ | ​ | ​ | ​ | 7,852 | ​ | ​ | ​ | ​ | ​ | 4,599 | ​ | ​ | ​ | ​ | ​ | 3,927 | ​ | ​ | ​ | ​ | ​ | (141) | ​ | ​ | ​ | ​ | ​ | 36,401 | ​ | ​
Unallocated liabilities(d)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 39,139 | ​ | ​
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets | ​ | ​ | ​ | ​ | 6,996 | ​ | ​ | ​ | ​ | ​ | 230 | ​ | ​ | ​ | ​ | ​ | 933 | ​ | ​ | ​ | ​ | ​ | 231 | ​ | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | 8,376 | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations including intersegment sales | ​ | ​ | ​ | ​ | 25,744 | ​ | ​ | ​ | ​ | ​ | 55,690 | ​ | ​ | ​ | ​ | ​ | 25,216 | ​ | ​ | ​ | ​ | ​ | 1,589 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Less: intersegment sales | ​ | ​ | ​ | ​ | (15,801) | ​ | ​ | ​ | ​ | ​ | (12,581) | ​ | ​ | ​ | ​ | ​ | (2,622) | ​ | ​ | ​ | ​ | ​ | (1,413) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations | ​ | ​ | ​ | ​ | 9,943 | ​ | ​ | ​ | ​ | ​ | 43,109 | ​ | ​ | ​ | ​ | ​ | 22,594 | ​ | ​ | ​ | ​ | ​ | 176 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 75,822 | ​ | ​
Operating profit | ​ | ​ | ​ | ​ | 10,214 | ​ | ​ | ​ | ​ | ​ | 629 | ​ | ​ | ​ | ​ | ​ | (380) | ​ | ​ | ​ | ​ | ​ | (691) | ​ | ​ | ​ | ​ | ​ | 211 | ​ | ​ | ​ | ​ | ​ | 9,983 | ​ | ​
Net provisions for contingencies | ​ | ​ | ​ | ​ | 235 | ​ | ​ | ​ | ​ | ​ | 53 | ​ | ​ | ​ | ​ | ​ | 274 | ​ | ​ | ​ | ​ | ​ | 579 | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​ | ​ | ​ | ​ | 1,120 | ​ | ​
Depreciation and amortization | ​ | ​ | ​ | ​ | (6,152) | ​ | ​ | ​ | ​ | ​ | (408) | ​ | ​ | ​ | ​ | ​ | (399) | ​ | ​ | ​ | ​ | ​ | (59) | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | (6,988) | ​ | ​
Impairments of tangible and intangible assets | ​ | ​ | ​ | ​ | (1,025) | ​ | ​ | ​ | ​ | ​ | (56) | ​ | ​ | ​ | ​ | ​ | (193) | ​ | ​ | ​ | ​ | ​ | (18) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,292) | ​ | ​
Reversals of tangible and intangible assets | ​ | ​ | ​ | ​ | 299 | ​ | ​ | ​ | ​ | ​ | 127 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 426 | ​ | ​
Write-off of tangible and intangible assets | ​ | ​ | ​ | ​ | (97) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (100) | ​ | ​
Share of profit (loss) of equity-accounted investments | ​ | ​ | ​ | ​ | 158 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | (67) | ​ | ​ | ​ | ​ | ​ | (168) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (68) | ​ | ​
Identifiable assets(a) | ​ | ​ | ​ | ​ | 63,051 | ​ | ​ | ​ | ​ | ​ | 9,989 | ​ | ​ | ​ | ​ | ​ | 11,692 | ​ | ​ | ​ | ​ | ​ | 1,171 | ​ | ​ | ​ | ​ | ​ | (420) | ​ | ​ | ​ | ​ | ​ | 85,483 | ​ | ​
Unallocated assets(b) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32,890 | ​ | ​
Equity-accounted investments | ​ | ​ | ​ | ​ | 4,972 | ​ | ​ | ​ | ​ | ​ | 494 | ​ | ​ | ​ | ​ | ​ | 275 | ​ | ​ | ​ | ​ | ​ | 1,303 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7,044 | ​ | ​
Identifiable liabilities(c)​ | ​ | ​ | ​ | ​ | 18,110 | ​ | ​ | ​ | ​ | ​ | 8,314 | ​ | ​ | ​ | ​ | ​ | 4,319 | ​ | ​ | ​ | ​ | ​ | 4,072 | ​ | ​ | ​ | ​ | ​ | (275) | ​ | ​ | ​ | ​ | ​ | 34,540 | ​ | ​
Unallocated liabilities(d)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32,760 | ​ | ​
Capital expenditure in tangible and intangible assets | ​ | ​ | ​ | ​ | 7,901 | ​ | ​ | ​ | ​ | ​ | 215 | ​ | ​ | ​ | ​ | ​ | 877 | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | (17) | ​ | ​ | ​ | ​ | ​ | 9,119 | ​ | ​
2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations including intersegment sales | ​ | ​ | ​ | ​ | 19,525 | ​ | ​ | ​ | ​ | ​ | 50,623 | ​ | ​ | ​ | ​ | ​ | 22,107 | ​ | ​ | ​ | ​ | ​ | 1,462 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Less: intersegment sales | ​ | ​ | ​ | ​ | (12,394) | ​ | ​ | ​ | ​ | ​ | (10,777) | ​ | ​ | ​ | ​ | ​ | (2,336) | ​ | ​ | ​ | ​ | ​ | (1,291) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sales from operations | ​ | ​ | ​ | ​ | 7,131 | ​ | ​ | ​ | ​ | ​ | 39,846 | ​ | ​ | ​ | ​ | ​ | 19,771 | ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 66,919 | ​ | ​
Operating profit | ​ | ​ | ​ | ​ | 7,651 | ​ | ​ | ​ | ​ | ​ | 75 | ​ | ​ | ​ | ​ | ​ | 981 | ​ | ​ | ​ | ​ | ​ | (668) | ​ | ​ | ​ | ​ | ​ | (27) | ​ | ​ | ​ | ​ | ​ | 8,012 | ​ | ​
Net provisions for contingencies | ​ | ​ | ​ | ​ | 479 | ​ | ​ | ​ | ​ | ​ | (20) | ​ | ​ | ​ | ​ | ​ | 182 | ​ | ​ | ​ | ​ | ​ | 245 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 886 | ​ | ​
Depreciation and amortization | ​ | ​ | ​ | ​ | (6,747) | ​ | ​ | ​ | ​ | ​ | (345) | ​ | ​ | ​ | ​ | ​ | (360) | ​ | ​ | ​ | ​ | ​ | (60) | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | (7,483) | ​ | ​
Impairments of tangible and intangible assets | ​ | ​ | ​ | ​ | (650) | ​ | ​ | ​ | ​ | ​ | (56) | ​ | ​ | ​ | ​ | ​ | (131) | ​ | ​ | ​ | ​ | ​ | (25) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (862) | ​ | ​
Reversals of tangible and intangible assets | ​ | ​ | ​ | ​ | 808 | ​ | ​ | ​ | ​ | ​ | 202 | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,087 | ​ | ​
Write-off of tangible and intangible assets | ​ | ​ | ​ | ​ | (260) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (263) | ​ | ​
Share of profit (loss) of equity-accounted investments | ​ | ​ | ​ | ​ | (99) | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​ | ​ | ​ | ​ | (57) | ​ | ​ | ​ | ​ | ​ | (101) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (267) | ​ | ​
Identifiable assets(a) | ​ | ​ | ​ | ​ | 66,661 | ​ | ​ | ​ | ​ | ​ | 11,058 | ​ | ​ | ​ | ​ | ​ | 11,599 | ​ | ​ | ​ | ​ | ​ | 1,108 | ​ | ​ | ​ | ​ | ​ | (610) | ​ | ​ | ​ | ​ | ​ | 89,816 | ​ | ​
Unallocated assets(b) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25,112 | ​ | ​
Equity-accounted investments | ​ | ​ | ​ | ​ | 1,234 | ​ | ​ | ​ | ​ | ​ | 509 | ​ | ​ | ​ | ​ | ​ | 321 | ​ | ​ | ​ | ​ | ​ | 1,447 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3,511 | ​ | ​
Identifiable liabilities(c)​ | ​ | ​ | ​ | ​ | 17,273 | ​ | ​ | ​ | ​ | ​ | 8,851 | ​ | ​ | ​ | ​ | ​ | 4,005 | ​ | ​ | ​ | ​ | ​ | 4,053 | ​ | ​ | ​ | ​ | ​ | (306) | ​ | ​ | ​ | ​ | ​ | 33,876 | ​ | ​
Unallocated liabilities(d)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32,973 | ​ | ​
Capital expenditure in tangible and intangible assets | ​ | ​ | ​ | ​ | 7,739 | ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​ | ​ | ​ | ​ | 729 | ​ | ​ | ​ | ​ | ​ | 87 | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | 8,681 | ​ | ​

​
(a)
Include assets directly associated with the generation of operating profit.
​
(b)
Include assets not directly associated with the generation of operating profit.
​
(c)
Include liabilities directly associated with the generation of operating profit.
​
(d)
Include liabilities not directly associated with the generation of operating profit.
​
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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 | ​
2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Identifiable assets(a) | ​ | ​ | ​ | ​ | 19,346 | ​ | ​ | ​ | ​ | ​ | 7,237 | ​ | ​ | ​ | ​ | ​ | 1,151 | ​ | ​ | ​ | ​ | ​ | 5,230 | ​ | ​ | ​ | ​ | ​ | 17,898 | ​ | ​ | ​ | ​ | ​ | 40,021 | ​ | ​ | ​ | ​ | ​ | 912 | ​ | ​ | ​ | ​ | ​ | 91,795 | ​ | ​
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets | ​ | ​ | ​ | ​ | 1,402 | ​ | ​ | ​ | ​ | ​ | 306 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | 1,017 | ​ | ​ | ​ | ​ | ​ | 1,685 | ​ | ​ | ​ | ​ | ​ | 3,902 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​ | ​ | ​ | ​ | 8,376 | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Identifiable assets(a) | ​ | ​ | ​ | ​ | 18,646 | ​ | ​ | ​ | ​ | ​ | 7,086 | ​ | ​ | ​ | ​ | ​ | 1,031 | ​ | ​ | ​ | ​ | ​ | 4,546 | ​ | ​ | ​ | ​ | ​ | 16,910 | ​ | ​ | ​ | ​ | ​ | 36,155 | ​ | ​ | ​ | ​ | ​ | 1,109 | ​ | ​ | ​ | ​ | ​ | 85,483 | ​ | ​
Capital expenditure in tangible and intangible assets | ​ | ​ | ​ | ​ | 1,424 | ​ | ​ | ​ | ​ | ​ | 267 | ​ | ​ | ​ | ​ | ​ | 538 | ​ | ​ | ​ | ​ | ​ | 534 | ​ | ​ | ​ | ​ | ​ | 1,782 | ​ | ​ | ​ | ​ | ​ | 4,533 | ​ | ​ | ​ | ​ | ​ | 41 | ​ | ​ | ​ | ​ | ​ | 9,119 | ​ | ​
2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Identifiable assets(a) | ​ | ​ | ​ | ​ | 18,449 | ​ | ​ | ​ | ​ | ​ | 7,706 | ​ | ​ | ​ | ​ | ​ | 6,160 | ​ | ​ | ​ | ​ | ​ | 4,406 | ​ | ​ | ​ | ​ | ​ | 16,527 | ​ | ​ | ​ | ​ | ​ | 35,385 | ​ | ​ | ​ | ​ | ​ | 1,183 | ​ | ​ | ​ | ​ | ​ | 89,816 | ​ | ​
Capital expenditure in tangible and intangible assets | ​ | ​ | ​ | ​ | 1,090 | ​ | ​ | ​ | ​ | ​ | 316 | ​ | ​ | ​ | ​ | ​ | 387 | ​ | ​ | ​ | ​ | ​ | 278 | ​ | ​ | ​ | ​ | ​ | 898 | ​ | ​ | ​ | ​ | ​ | 5,699 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 8,681 | ​ | ​

​
(a)
Include assets directly associated with the generation of operating profit.
​
Sales from operations by geographical area of destination

​ | ​ | ​ | ​ | ​
(€ million) | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
Italy | ​ | ​ | ​ | ​ | 23,312 | ​ | ​ | ​ | ​ | ​ | 25,279 | ​ | ​ | ​ | ​ | ​ | 21,925 | ​ | ​
Other European Union | ​ | ​ | ​ | ​ | 18,567 | ​ | ​ | ​ | ​ | ​ | 20,408 | ​ | ​ | ​ | ​ | ​ | 19,791 | ​ | ​
Rest of Europe | ​ | ​ | ​ | ​ | 6,931 | ​ | ​ | ​ | ​ | ​ | 7,052 | ​ | ​ | ​ | ​ | ​ | 5,911 | ​ | ​
Americas | ​ | ​ | ​ | ​ | 3,842 | ​ | ​ | ​ | ​ | ​ | 5,051 | ​ | ​ | ​ | ​ | ​ | 5,154 | ​ | ​
Asia | ​ | ​ | ​ | ​ | 8,102 | ​ | ​ | ​ | ​ | ​ | 9,585 | ​ | ​ | ​ | ​ | ​ | 7,523 | ​ | ​
Africa | ​ | ​ | ​ | ​ | 8,998 | ​ | ​ | ​ | ​ | ​ | 8,246 | ​ | ​ | ​ | ​ | ​ | 6,428 | ​ | ​
Other areas | ​ | ​ | ​ | ​ | 129 | ​ | ​ | ​ | ​ | ​ | 201 | ​ | ​ | ​ | ​ | ​ | 187 | ​ | ​
​ | ​ | ​ | ​ | ​ | 69,881 | ​ | ​ | ​ | ​ | ​ | 75,822 | ​ | ​ | ​ | ​ | ​ | 66,919 | ​ | ​

36 Transactions with related parties
In the ordinary course of its business, Eni enters into transactions regarding:
(a)
Purchase/supply of goods and services and the provision of financing to joint ventures, associates and non-consolidated subsidiaries;
​
(b)
Purchase/supply of goods and services to entities controlled by the Italian Government;
​
(c)
Purchase/supply of goods and services to companies related to Eni SpA through members of the Board of Directors. Most of these transactions are exempt from the application of the Eni internal procedure “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or standard conditions, or because they fall below the materiality threshold provided for by the procedure. The solely non-exempted transaction, that was positively examined and valued in application of the procedure, concerned the remote monitoring of cars in the “enjoy” initiative (for an amount of about €1 million) conducted with Vodafone Italia SpA related to Eni SpA through of a member of the Board of Directors; and
​
(d)
contributions to non-profit entities correlated to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation, established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as scientific and technological research; and (ii) Eni Enrico Mattei Foundation, established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge enrichment in the fields of economics, energy and environment, both at the national and international level.
​
Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business.
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Transactions and balances with related parties

(€ million) | ​ | ​ | December 31, 2019 | ​ | ​ | 2019 | ​
Name | ​ | ​ | Receivables and other assets | ​ | ​ | Payables and other liabilities | ​ | ​ | Guarantees | ​ | ​ | Revenues | ​ | ​ | Costs | ​ | ​ | Other operating (expense) income | ​
Joint ventures and associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Agiba Petroleum Co | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 229 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Angola LNG Supply Services Llc | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 181 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral FLNG SA | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,168 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gas Distribution Company of Thessaloniki - Thessaly SA | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 53 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Saipem Group | ​ | ​ | ​ | ​ | 75 | ​ | ​ | ​ | ​ | ​ | 227 | ​ | ​ | ​ | ​ | ​ | 510 | ​ | ​ | ​ | ​ | ​ | 27 | ​ | ​ | ​ | ​ | ​ | 503 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Karachaganak Petroleum Operating BV | ​ | ​ | ​ | ​ | 33 | ​ | ​ | ​ | ​ | ​ | 198 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1,134 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Mellitah Oil & Gas BV | ​ | ​ | ​ | ​ | 57 | ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 365 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Petrobel Belayim Petroleum Co | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 1,130 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 1,590 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unión Fenosa Gas SA | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​
Vår Energi AS | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | 482 | ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​ | ​ | ​ | ​ | 1,481 | ​ | ​ | ​ | ​ | ​ | (64) | ​ | ​
Other(*) | ​ | ​ | ​ | ​ | 106 | ​ | ​ | ​ | ​ | ​ | 29 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 112 | ​ | ​ | ​ | ​ | ​ | 87 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 379 | ​ | ​ | ​ | ​ | ​ | 1,983 | ​ | ​ | ​ | ​ | ​ | 2,399 | ​ | ​ | ​ | ​ | ​ | 285 | ​ | ​ | ​ | ​ | ​ | 5,448 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​
Unconsolidated entities controlled by Eni | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni BTC Ltd | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 180 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | ​ | ​ | ​ | ​ | 101 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 106 | ​ | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | 197 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 485 | ​ | ​ | ​ | ​ | ​ | 2,009 | ​ | ​ | ​ | ​ | ​ | 2,596 | ​ | ​ | ​ | ​ | ​ | 305 | ​ | ​ | ​ | ​ | ​ | 5,466 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​
Entities controlled by the Government | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Enel Group | ​ | ​ | ​ | ​ | 185 | ​ | ​ | ​ | ​ | ​ | 284 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 105 | ​ | ​ | ​ | ​ | ​ | 602 | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​
Italgas Group | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 154 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 677 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Snam Group | ​ | ​ | ​ | ​ | 278 | ​ | ​ | ​ | ​ | ​ | 229 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | 1,208 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Terna Group | ​ | ​ | ​ | ​ | 40 | ​ | ​ | ​ | ​ | ​ | 45 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​ | ​ | ​ | ​ | 223 | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​
GSE - Gestore Servizi Energetici | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 549 | ​ | ​ | ​ | ​ | ​ | 468 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​
Other | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 35 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 542 | ​ | ​ | ​ | ​ | ​ | 755 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 909 | ​ | ​ | ​ | ​ | ​ | 3,213 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​
Other related parties | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» | ​ | ​ | ​ | ​ | 75 | ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 33 | ​ | ​ | ​ | ​ | ​ | 457 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 1,104 | ​ | ​ | ​ | ​ | ​ | 2,841 | ​ | ​ | ​ | ​ | ​ | 2,596 | ​ | ​ | ​ | ​ | ​ | 1,252 | ​ | ​ | ​ | ​ | ​ | 9,173 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​

​
(*)
Each individual amount included herein was lower than €50 million.
​

(€ million) | ​ | ​ | December 31, 2018 | ​ | ​ | 2018 | ​
Name | ​ | ​ | Receivables and other assets | ​ | ​ | Payables and other liabilities | ​ | ​ | Guarantees | ​ | ​ | Revenues | ​ | ​ | Costs | ​ | ​ | Other operating (expense) income | ​
Joint ventures and associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Agiba Petroleum Co | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 96 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 156 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Angola LNG Supply Services Llc | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral FLNG SA | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,147 | ​ | ​ | ​ | ​ | ​ | 62 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gas Distribution Company of Thessaloniki - Thessaly SA | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 51 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Saipem Group | ​ | ​ | ​ | ​ | 75 | ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​ | ​ | ​ | ​ | 793 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 420 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Karachaganak Petroleum Operating BV | ​ | ​ | ​ | ​ | 27 | ​ | ​ | ​ | ​ | ​ | 134 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 998 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Mellitah Oil & Gas BV | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 268 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 502 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Petrobel Belayim Petroleum Co | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 2,029 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 2,282 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unión Fenosa Gas SA | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​ | ​ | ​ | ​ | 123 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​
Vår Energi AS | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | ​ | ​ | 218 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other(*) | ​ | ​ | ​ | ​ | 44 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 111 | ​ | ​ | ​ | ​ | ​ | 104 | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​
​ | ​ | ​ | ​ | ​ | 236 | ​ | ​ | ​ | ​ | ​ | 2,848 | ​ | ​ | ​ | ​ | ​ | 2,392 | ​ | ​ | ​ | ​ | ​ | 335 | ​ | ​ | ​ | ​ | ​ | 4,513 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​
Unconsolidated entities controlled by Eni | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni BTC Ltd | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 177 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | ​ | ​ | ​ | ​ | 87 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 93 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 196 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 329 | ​ | ​ | ​ | ​ | ​ | 2,872 | ​ | ​ | ​ | ​ | ​ | 2,588 | ​ | ​ | ​ | ​ | ​ | 353 | ​ | ​ | ​ | ​ | ​ | 4,526 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​
Entities controlled by the Government | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Enel Group | ​ | ​ | ​ | ​ | 134 | ​ | ​ | ​ | ​ | ​ | 151 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 118 | ​ | ​ | ​ | ​ | ​ | 514 | ​ | ​ | ​ | ​ | ​ | 227 | ​ | ​
Italgas Group | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 146 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 667 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Snam Group | ​ | ​ | ​ | ​ | 237 | ​ | ​ | ​ | ​ | ​ | 289 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 109 | ​ | ​ | ​ | ​ | ​ | 1,184 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​
Terna Group | ​ | ​ | ​ | ​ | 26 | ​ | ​ | ​ | ​ | ​ | 47 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 150 | ​ | ​ | ​ | ​ | ​ | 231 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​
GSE - Gestore Servizi Energetici | ​ | ​ | ​ | ​ | 67 | ​ | ​ | ​ | ​ | ​ | 85 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 555 | ​ | ​ | ​ | ​ | ​ | 588 | ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​
Other | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 45 | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 494 | ​ | ​ | ​ | ​ | ​ | 736 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | ​ | ​ | 3,218 | ​ | ​ | ​ | ​ | ​ | 308 | ​ | ​
Other related parties | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» | ​ | ​ | ​ | ​ | 40 | ​ | ​ | ​ | ​ | ​ | 140 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 229 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 864 | ​ | ​ | ​ | ​ | ​ | 3,750 | ​ | ​ | ​ | ​ | ​ | 2,588 | ​ | ​ | ​ | ​ | ​ | 1,391 | ​ | ​ | ​ | ​ | ​ | 8,005 | ​ | ​ | ​ | ​ | ​ | 319 | ​ | ​

​
(*)
Each individual amount included herein was lower than €50 million.
​
F-115

TABLE OF CONTENTS

(€ million) | ​ | ​ | December 31, 2017 | ​ | ​ | 2017 | ​
Name | ​ | ​ | Receivables and other assets | ​ | ​ | Payables and other liabilities | ​ | ​ | Guarantees | ​ | ​ | Revenues | ​ | ​ | Costs | ​ | ​ | Other operating (expense) income | ​
Joint ventures and associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Agiba Petroleum Co | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 83 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 142 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral FLNG SA | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 1,094 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Karachaganak Petroleum Operating BV | ​ | ​ | ​ | ​ | 36 | ​ | ​ | ​ | ​ | ​ | 121 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 951 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Mellitah Oil & Gas BV | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 220 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 495 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Petrobel Belayim Petroleum Co | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | 1,205 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 3,168 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Saipem Group | ​ | ​ | ​ | ​ | 63 | ​ | ​ | ​ | ​ | ​ | 76 | ​ | ​ | ​ | ​ | ​ | 7,270 | ​ | ​ | ​ | ​ | ​ | 44 | ​ | ​ | ​ | ​ | ​ | 450 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unión Fenosa Gas SA | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​ | ​ | ​ | ​ | 202 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​
Other(*) | ​ | ​ | ​ | ​ | 84 | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 128 | ​ | ​ | ​ | ​ | ​ | 140 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 295 | ​ | ​ | ​ | ​ | ​ | 1,731 | ​ | ​ | ​ | ​ | ​ | 8,421 | ​ | ​ | ​ | ​ | ​ | 412 | ​ | ​ | ​ | ​ | ​ | 5,349 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​
Unconsolidated entities controlled by Eni | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni BTC Ltd | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 169 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | ​ | ​ | ​ | ​ | 77 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 97 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 181 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 392 | ​ | ​ | ​ | ​ | ​ | 1,755 | ​ | ​ | ​ | ​ | ​ | 8,602 | ​ | ​ | ​ | ​ | ​ | 426 | ​ | ​ | ​ | ​ | ​ | 5,363 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​
Entities controlled by the Government | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Enel Group | ​ | ​ | ​ | ​ | 123 | ​ | ​ | ​ | ​ | ​ | 187 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 164 | ​ | ​ | ​ | ​ | ​ | 622 | ​ | ​ | ​ | ​ | ​ | 285 | ​ | ​
GSE - Gestore Servizi Energetici | ​ | ​ | ​ | ​ | 69 | ​ | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 702 | ​ | ​ | ​ | ​ | ​ | 506 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
Italgas Group | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 180 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 681 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Snam Group | ​ | ​ | ​ | ​ | 187 | ​ | ​ | ​ | ​ | ​ | 351 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 85 | ​ | ​ | ​ | ​ | ​ | 1,221 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Terna Group | ​ | ​ | ​ | ​ | 35 | ​ | ​ | ​ | ​ | ​ | 31 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 154 | ​ | ​ | ​ | ​ | ​ | 212 | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​
Other(*) | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | ​ | ​ | ​ | ​ | 478 | ​ | ​ | ​ | ​ | ​ | 989 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 1,139 | ​ | ​ | ​ | ​ | ​ | 3,280 | ​ | ​ | ​ | ​ | ​ | 303 | ​ | ​
Other related parties | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» | ​ | ​ | ​ | ​ | 39 | ​ | ​ | ​ | ​ | ​ | 145 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 42 | ​ | ​ | ​ | ​ | ​ | 530 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 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 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 guarantee given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and fair value of 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 fuel, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group;
​
•
acquisition of natural gas transportation, distribution and storage services with Snam Group and Italgas Group on the basis of tariffs set by the Italian Regulatory Authority for Energy, Networks and Environment and purchase and sale with Snam Group of natural gas for granting the system balancing on the basis of prices referred to the quotations of the main energy commodities;
​
•
acquisition of domestic electricity transmission service and sale and purchase of electricity for granting the system balancing on the basis of prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with Terna Group;
​
•
sale and purchase of electricity, gas, environmental certificates, fair value of derivative financial instruments, sale of oil products and storage capacity with GSE — Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/2012.
​
Transactions with other related parties concerned:
•
provisions to pension funds of €30 million; and
​
•
contributions and service provisions to Eni Enrico Mattei Foundation for €6 million and to Eni Foundation for €1 million.
​
Financing transactions and balances with related parties

(€ million) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | December 31, 2019 | ​ | ​ | 2019 | ​
Name | ​ | ​ | Receivables | ​ | ​ | Payables | ​ | ​ | Guarantees | ​ | ​ | Gains | ​ | ​ | Charges | ​ | ​
Joint ventures and associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Angola LNG Ltd | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 249 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cardón IV SA | ​ | ​ | ​ | ​ | 563 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral FLNG SA | ​ | ​ | ​ | ​ | 253 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​
Coral South FLNG DMCC | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,425 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Société Centrale Electrique du Congo SA | ​ | ​ | ​ | ​ | 85 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 919 | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 1,676 | ​ | ​ | ​ | ​ | ​ | 95 | ​ | ​ | ​ | ​ | ​ | 36 | ​ | ​ | ​
Unconsolidated entities controlled by Eni | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Entities controlled by the Government | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 971 | ​ | ​ | ​ | ​ | ​ | 59 | ​ | ​ | ​ | ​ | ​ | 1,676 | ​ | ​ | ​ | ​ | ​ | 96 | ​ | ​ | ​ | ​ | ​ | 36 | ​ | ​ | ​
​

(€ million) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | December 31, 2018 | ​ | ​ | 2018 | ​
Name | ​ | ​ | Receivables | ​ | ​ | Payables | ​ | ​ | Guarantees | ​ | ​ | Gains | ​ | ​ | Charges | ​
Joint ventures and associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Angola LNG Ltd | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 245 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cardón IV SA | ​ | ​ | ​ | ​ | 705 | ​ | ​ | ​ | ​ | ​ | 36 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 95 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral FLNG SA | ​ | ​ | ​ | ​ | 108 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral South FLNG DMCC | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,397 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Shatskmorneftegaz Sàrl | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 267 | ​ | ​
Société Centrale Electrique du Congo SA | ​ | ​ | ​ | ​ | 64 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​
Vår Energi AS | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 494 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 38 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​
​ | ​ | ​ | ​ | ​ | 915 | ​ | ​ | ​ | ​ | ​ | 564 | ​ | ​ | ​ | ​ | ​ | 1,664 | ​ | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 281 | ​ | ​
Unconsolidated entities controlled by Eni | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Entities controlled by the Government | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Enel Group | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 64 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 72 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​
​ | ​ | ​ | ​ | ​ | 964 | ​ | ​ | ​ | ​ | ​ | 661 | ​ | ​ | ​ | ​ | ​ | 1,664 | ​ | ​ | ​ | ​ | ​ | 115 | ​ | ​ | ​ | ​ | ​ | 283 | ​ | ​
​

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(€ million) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | December 31, 2017 | ​ | ​ | 2017 | ​
Name | ​ | ​ | Receivables | ​ | ​ | Payables | ​ | ​ | Guarantees | ​ | ​ | Gains | ​ | ​ | Charges | ​
Joint ventures and associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Angola LNG Ltd | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 233 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral South FLNG D MCC | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,334 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cardón IV SA | ​ | ​ | ​ | ​ | 955 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Shatskmorneftegaz Sarl | ​ | ​ | ​ | ​ | 101 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Société Centrale Electrique du Congo SA | ​ | ​ | ​ | ​ | 66 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Saipem Group | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Coral FLNG SA | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
​ | ​ | ​ | ​ | ​ | 1,226 | ​ | ​ | ​ | ​ | ​ | 95 | ​ | ​ | ​ | ​ | ​ | 1,625 | ​ | ​ | ​ | ​ | ​ | 190 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​
Unconsolidated entities controlled by Eni | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Servizi Fondo Bombole Metano SpA | ​ | ​ | ​ | ​ | 60 | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other(*) | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | 61 | ​ | ​ | ​ | ​ | ​ | 61 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Entities controlled by the Government | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​
​ | ​ | ​ | ​ | ​ | 1,287 | ​ | ​ | ​ | ​ | ​ | 164 | ​ | ​ | ​ | ​ | ​ | 1,625 | ​ | ​ | ​ | ​ | ​ | 191 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​

​
(*)
Each individual amount included herein was lower than €50 million.
​
The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:
•
bank debt guarantees issued on behalf of Angola LNG Ltd;
​
•
the financing loan granted to Cardón IV SA for the exploration and development activities of a gas field in Venezuela;
​
•
the financing loan granted to Coral FLNG SA for the construction of a floating gas liquefaction plant in Area 4 offshore Mozambique (for more information see note 27 — Guarantees, commitments and risks);
​
•
a bank debt guarantee issued on behalf of Coral South FLNG DMCC as part of the project financing of the Coral FLNG development project (for more information see note 27 — Guarantees, commitments and risks);
​
•
the loan granted to Société Centrale Electrique du Congo SA for the construction of a power plant in Congo.
​
Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows
The impact of transactions and positions with related parties on the balance sheet accounts consisted of the following:

(€ million) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | December 31, 2019 | ​ | ​ | December 31, 2018 | ​
​ | ​ | ​ | Total | ​ | ​ | Related parties | ​ | ​ | Impact % | ​ | ​ | Total | ​ | ​ | Related parties | ​ | ​ | Impact % | ​
Other current financial assets | ​ | ​ | ​ | ​ | 384 | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​ | ​ | ​ | ​ | 15.63 | ​ | ​ | ​ | ​ | ​ | 300 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 16.33 | ​ | ​
Trade and other receivables | ​ | ​ | ​ | ​ | 12,873 | ​ | ​ | ​ | ​ | ​ | 704 | ​ | ​ | ​ | ​ | ​ | 5.47 | ​ | ​ | ​ | ​ | ​ | 14,101 | ​ | ​ | ​ | ​ | ​ | 633 | ​ | ​ | ​ | ​ | ​ | 4.49 | ​ | ​
Other current assets | ​ | ​ | ​ | ​ | 3,972 | ​ | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | 5.51 | ​ | ​ | ​ | ​ | ​ | 2,819 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | 2.52 | ​ | ​
Other non-current financial assets | ​ | ​ | ​ | ​ | 1,174 | ​ | ​ | ​ | ​ | ​ | 911 | ​ | ​ | ​ | ​ | ​ | 77.60 | ​ | ​ | ​ | ​ | ​ | 1,253 | ​ | ​ | ​ | ​ | ​ | 915 | ​ | ​ | ​ | ​ | ​ | 73.02 | ​ | ​
Other non-current assets | ​ | ​ | ​ | ​ | 871 | ​ | ​ | ​ | ​ | ​ | 181 | ​ | ​ | ​ | ​ | ​ | 20.78 | ​ | ​ | ​ | ​ | ​ | 624 | ​ | ​ | ​ | ​ | ​ | 160 | ​ | ​ | ​ | ​ | ​ | 25.64 | ​ | ​
Short-term debt | ​ | ​ | ​ | ​ | 2,452 | ​ | ​ | ​ | ​ | ​ | 46 | ​ | ​ | ​ | ​ | ​ | 1.88 | ​ | ​ | ​ | ​ | ​ | 2,182 | ​ | ​ | ​ | ​ | ​ | 661 | ​ | ​ | ​ | ​ | ​ | 30.29 | ​ | ​
Current portion of long-term lease liabilities | ​ | ​ | ​ | ​ | 889 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 0.56 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Trade and other payables | ​ | ​ | ​ | ​ | 15,545 | ​ | ​ | ​ | ​ | ​ | 2,663 | ​ | ​ | ​ | ​ | ​ | 17.13 | ​ | ​ | ​ | ​ | ​ | 16,747 | ​ | ​ | ​ | ​ | ​ | 3,664 | ​ | ​ | ​ | ​ | ​ | 21.88 | ​ | ​
Other current liabilities | ​ | ​ | ​ | ​ | 7,146 | ​ | ​ | ​ | ​ | ​ | 155 | ​ | ​ | ​ | ​ | ​ | 2.17 | ​ | ​ | ​ | ​ | ​ | 5,412 | ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​ | ​ | ​ | ​ | 1.16 | ​ | ​
Long-term lease liabilities | ​ | ​ | ​ | ​ | 4,759 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 0.17 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other non-current liabilities | ​ | ​ | ​ | ​ | 1,611 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 1.43 | ​ | ​ | ​ | ​ | ​ | 1,475 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 1.56 | ​ | ​

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The impact of transactions with related parties on the profit and loss accounts consisted of the following:

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 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) | ​ | ​ | 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:

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​ | ​ | 2018 | ​ | ​ | 2017 | ​
(€ million) | ​ | ​ | Total | ​ | ​ | Related parties | ​ | ​ | Impact % | ​ | ​ | Total | ​ | ​ | Related parties | ​ | ​ | Impact % | ​ | ​ | Total | ​ | ​ | Related parties | ​ | ​ | Impact % | ​
Net cash provided by operating activities | ​ | ​ | ​ | ​ | 12,392 | ​ | ​ | ​ | ​ | ​ | (6,356) | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | ​ | ​ | ​ | 13,647 | ​ | ​ | ​ | ​ | ​ | (2,707) | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | ​ | ​ | ​ | 10,117 | ​ | ​ | ​ | ​ | ​ | (2,843) | ​ | ​ | ​ | ​ | ​ | — | ​ | ​
Net cash used in investing activities | ​ | ​ | ​ | ​ | (11,413) | ​ | ​ | ​ | ​ | ​ | (2,912) | ​ | ​ | ​ | ​ | ​ | 25.51 | ​ | ​ | ​ | ​ | ​ | (7,536) | ​ | ​ | ​ | ​ | ​ | (3,314) | ​ | ​ | ​ | ​ | ​ | 43.98 | ​ | ​ | ​ | ​ | ​ | (3,768) | ​ | ​ | ​ | ​ | ​ | (3,115) | ​ | ​ | ​ | ​ | ​ | 82.67 | ​ | ​
Net cash used in financing activities | ​ | ​ | ​ | ​ | (5,841) | ​ | ​ | ​ | ​ | ​ | (817) | ​ | ​ | ​ | ​ | ​ | 13.99 | ​ | ​ | ​ | ​ | ​ | (2,637) | ​ | ​ | ​ | ​ | ​ | 16 | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | ​ | ​ | ​ | (4,595) | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | 0.35 | ​ | ​

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37 Other information about investments
Information on Eni’s investments as of December 31, 2019
The following section provides information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 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 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(*) | ​
Eni Angola SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Angola | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,200,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Mediterranea Idrocarburi SpA | ​ | ​ | Gela (CL) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 5,200,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Mozambico SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Mozambique | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 200,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Timor Leste SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | East Timor | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 6,841,517 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni West Africa SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Angola | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 10,000,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
EniProgetti SpA | ​ | ​ | Venezia Marghera (VE) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 2,064,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Floaters SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 200,120,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Ieoc SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Egypt | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 7,518,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Società Petrolifera Italiana SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 13,877,600 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 99.96​ 0.04​ | ​ | ​ | ​ | ​ | 99.96 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
(#)
Company with shares quoted in the regulated market of Italy or of other EU countries
​
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Outside Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Agip Caspian Sea BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Kazakhstan | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,005 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Agip Energy and Natural Resources (Nigeria) Ltd | ​ | ​ | Abuja (Nigeria) | ​ | ​ | Nigeria | ​ | ​ | NGN | ​ | ​ | ​ | ​ | 5,000,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 95.00 5.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Agip Karachaganak BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Kazakhstan | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,005 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Agip Oleoducto de Crudos Pesados BV (in liquidation) | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Ecuador | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Burren Energy (Bermuda) Ltd | ​ | ​ | Hamilton (Bermuda) | ​ | ​ | United Kingdom | ​ | ​ | USD | ​ | ​ | ​ | ​ | 12,002 | ​ | ​ | ​ | Burren Energy Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Burren Energy (Egypt) Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Egypt | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | Burren Energy Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Burren Energy Congo Ltd | ​ | ​ | Tortola (British Virgin Islands) | ​ | ​ | Republic of the Congo | ​ | ​ | USD | ​ | ​ | ​ | ​ | 50,000 | ​ | ​ | ​ | Burren En.(Berm)Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Burren Energy India Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | Burren Energy Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Burren Energy Plc | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 28,819,023 | ​ | ​ | ​ | Eni UK Holding Plc Eni UK Ltd | ​ | ​ | 99.99 (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Burren Shakti Ltd | ​ | ​ | Hamilton (Bermuda) | ​ | ​ | United Kingdom | ​ | ​ | USD | ​ | ​ | ​ | ​ | 213,138 | ​ | ​ | ​ | Burren En. India Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Abu Dhabi BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | United Arab Emirates | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni AEP Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Pakistan | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 13,471,000 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Albania BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Algeria Exploration BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Algeria | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Algeria Ltd Sàrl | ​ | ​ | Luxembourg (Luxembourg) | ​ | ​ | Algeria | ​ | ​ | USD | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni Oil Holdings BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Algeria Production BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Algeria | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ambalat Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni America Ltd | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 72,000 | ​ | ​ | ​ | Eni UHL Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Angola Exploration BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Angola | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Angola Production BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Angola | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Argentina Exploración y Explotación SA | ​ | ​ | Buenos Aires (Argentina) | ​ | ​ | Argentina | ​ | ​ | ARS | ​ | ​ | ​ | ​ | 24,136,336 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 95.00 5.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
F-121

TABLE OF CONTENTS

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | %Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Eni Arguni I Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Australia BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Australia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Australia Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Australia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 20,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Bahrain BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Bahrain | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni BB Petroleum Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni Petroleum Co Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni BTC Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Bukat Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Bulungan BV (in liquidation) | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Indonesia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Eni Canada Holding Ltd | ​ | ​ | Calgary (Canada) | ​ | ​ | Canada | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,453,200,001 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni CBM Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | USD | ​ | ​ | ​ | ​ | 2,210,728 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni China BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | China | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Congo SA | ​ | ​ | Pointe - Noire (Republic of the Congo) | ​ | ​ | Republic of the Congo | ​ | ​ | USD | ​ | ​ | ​ | ​ | 17,000,000 | ​ | ​ | ​ | Eni E&P Holding BV Eni Int. NA NV Sàrl Eni International BV | ​ | ​ | 99.99​ (..)​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Côte d’Ivoire Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Ivory Coast | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Cyprus Ltd | ​ | ​ | Nicosia (Cyprus) | ​ | ​ | Cyprus | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 2,006 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Denmark BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Greenland | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda | ​ | ​ | Rio de Janeiro (Brazil) | ​ | ​ | Brazil | ​ | ​ | BRL | ​ | ​ | ​ | ​ | 1,593,415,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni East Ganal Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni East Sepinggan Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Elgin/Franklin Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Energy Russia BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Exploration & Production Holding BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 29,832,777.12 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Gabon SA | ​ | ​ | Libreville (Gabon) | ​ | ​ | Gabon | ​ | ​ | XAF | ​ | ​ | ​ | ​ | 13,132,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ganal Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
F-122

TABLE OF CONTENTS

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Eni Gas & Power LNG Australia BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Australia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 10,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ghana Exploration and Production Ltd | ​ | ​ | Accra (Ghana) | ​ | ​ | Ghana | ​ | ​ | GHS | ​ | ​ | ​ | ​ | 21,412,500 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Hewett Ltd | ​ | ​ | Aberdeen (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 3,036,000 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Hydrocarbons Venezuela Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Venezuela | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 8,050,500 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni India Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | India | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 44,000,000 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Indonesia Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | Eni ULX Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Indonesia Ots 1 Ltd | ​ | ​ | Grand Cayman (Cayman Islands) | ​ | ​ | Indonesia | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1.01 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni International NA NV Sàrl | ​ | ​ | Luxembourg (Luxembourg) | ​ | ​ | United Kingdom | ​ | ​ | USD | ​ | ​ | ​ | ​ | 25,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Investments Plc | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 750,050,000 | ​ | ​ | ​ | Eni SpA Eni UK Ltd | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Iran BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Iran | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Iraq BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Iraq | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ireland BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Ireland | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Isatay BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Kazakhstan | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni JPDA 03-13 Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Australia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 250,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni JPDA 06-105 Pty Ltd | ​ | ​ | Perth (Australia) | ​ | ​ | Australia | ​ | ​ | AUD | ​ | ​ | ​ | ​ | 80,830,576 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni JPDA 11-106 BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Australia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 50,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Kenya BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Kenya | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Krueng Mane Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Lasmo Plc | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 337,638,724.25 | ​ | ​ | ​ | Eni Investments Plc Eni UK Ltd | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Lebanon BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Lebanon | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Liberia BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Liberia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Liverpool Bay Operating Co Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni LNS Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 80,400,000 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Marketing Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni Petroleum Co Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Maroc BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Morocco | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
F-123

TABLE OF CONTENTS

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Eni México S. de RL de CV | ​ | ​ | Lomas De Chapultepec, Mexico City (Mexico) | ​ | ​ | Mexico | ​ | ​ | MXN | ​ | ​ | ​ | ​ | 3,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.90 0.10​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Middle East Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni ULT Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni MOG Ltd (in liquidation) | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 220,711,147.50 | ​ | ​ | ​ | Eni Lasmo Plc Eni LNS Ltd | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Montenegro BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Montenegro | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Mozambique Engineering Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Mozambique LNG Holding BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Muara Bakau BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Indonesia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Myanmar BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Myanmar | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni North Africa BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Libya | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni North Ganal Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Oil & Gas Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 100,800 | ​ | ​ | ​ | Eni America Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Oil Algeria Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Algeria | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Oil Holdings BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 450,000 | ​ | ​ | ​ | Eni ULX Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Oman BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Oman | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Pakistan Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Pakistan | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 90,087 | ​ | ​ | ​ | Eni ULX Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Pakistan (M) Ltd Sàrl | ​ | ​ | Luxembourg (Luxembourg) | ​ | ​ | Pakistan | ​ | ​ | USD | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni Oil Holdings BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Petroleum Co Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 156,600,000 | ​ | ​ | ​ | Eni SpA Eni International BV | ​ | ​ | 63.86 36.14​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Petroleum US Llc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni BB Petroleum Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Portugal BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Portugal | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni RAK BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Rapak Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni RD Congo SA | ​ | ​ | Kinshasa (Democratic Republic of the Congo) | ​ | ​ | Democratic Republic of the Congo | ​ | ​ | CDF | ​ | ​ | ​ | ​ | 750,000,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Rovuma Basin BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Mozambique | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni Mozambique LNG H. BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Sharjah BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | United Arab Emirates | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni South Africa BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Republic of South Africa | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Eni South China Sea Ltd Sàrl | ​ | ​ | Luxembourg (Luxembourg) | ​ | ​ | China | ​ | ​ | USD | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni TNS Ltd | ​ | ​ | Aberdeen (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Tunisia BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Tunisia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Turkmenistan Ltd | ​ | ​ | Hamilton (Bermuda) | ​ | ​ | Turkmenistan | ​ | ​ | USD | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Burren En.(Berm)Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni UHL Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni ULT Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni UK Holding Plc | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 424,050,000 | ​ | ​ | ​ | Eni Lasmo Plc Eni UK Ltd | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni UK Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 250,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni UKCS Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | Eni UK Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ukraine Holdings BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ukraine Llc | ​ | ​ | Kiev (Ukraine) | ​ | ​ | Ukraine | ​ | ​ | UAH | ​ | ​ | ​ | ​ | 42,004,757.64 | ​ | ​ | ​ | Eni Ukraine Hold.BV Eni International BV | ​ | ​ | 99.99 0.01​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Ukraine Shallow Waters BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Ukraine | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni Ukraine Hold.BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni ULT Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 93,215,492.25 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni ULX Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 200,010,000 | ​ | ​ | ​ | Eni ULT Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni US Operating Co Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni Petroleum Co Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni USA Gas Marketing Llc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 10,000 | ​ | ​ | ​ | Eni Marketing Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni USA Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni Oil & Gas Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Venezuela BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Venezuela | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni Venezuela E&P Holding | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Venezuela E&P Holding SA | ​ | ​ | Bruxelles (Belgium) | ​ | ​ | Belgium | ​ | ​ | USD | ​ | ​ | ​ | ​ | 254,443,200 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ventures Plc (in liquidation) | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 278,050,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Eni Vietnam BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Vietnam | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni West Ganal Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni West Timor Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Indonesia Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Yemen Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Burren Energy Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
EniProgetti Egypt Ltd | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 50,000 | ​ | ​ | ​ | EniProgetti SpA Eni SpA | ​ | ​ | 99.00 1.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eurl Eni Algérie | ​ | ​ | Algiers (Algeria) | ​ | ​ | Algeria | ​ | ​ | DZD | ​ | ​ | ​ | ​ | 1,000,000 | ​ | ​ | ​ | Eni Algeria Ltd Sàrl | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
First Calgary Petroleums LP | ​ | ​ | Wilmington (USA) | ​ | ​ | Algeria | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni Canada Hold. Ltd FCP Partner Co ULC | ​ | ​ | 99.99 0.01​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
First Calgary Petroleums Partner Co ULC | ​ | ​ | Calgary (Canada) | ​ | ​ | Canada | ​ | ​ | CAD | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | Eni Canada Hold. Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Ieoc Exploration BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Egypt | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Ieoc Production BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Egypt | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Lasmo Sanga Sanga Ltd | ​ | ​ | Hamilton (Bermuda) | ​ | ​ | Indonesia | ​ | ​ | USD | ​ | ​ | ​ | ​ | 12,000 | ​ | ​ | ​ | Eni Lasmo Plc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Liverpool Bay Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | Eni ULX Ltd | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Mizamtec Operating Company S. de RL de CV | ​ | ​ | Mexico City (Mexico) | ​ | ​ | Mexico | ​ | ​ | MXN | ​ | ​ | ​ | ​ | 3,000 | ​ | ​ | ​ | Eni US Op. Co Inc Eni Petroleum Co Inc | ​ | ​ | 99.90 0.10​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Nigerian Agip CPFA Ltd | ​ | ​ | Lagos (Nigeria) | ​ | ​ | Nigeria | ​ | ​ | NGN | ​ | ​ | ​ | ​ | 1,262,500 | ​ | ​ | ​ | NAOC Ltd Agip En Nat Res.Ltd Nigerian Agip E. Ltd | ​ | ​ | 98.02 0.99 0.99​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Nigerian Agip Exploration Ltd | ​ | ​ | Abuja (Nigeria) | ​ | ​ | Nigeria | ​ | ​ | NGN | ​ | ​ | ​ | ​ | 5,000,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.99 0.01​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Nigerian Agip Oil Co Ltd | ​ | ​ | Abuja (Nigeria) | ​ | ​ | Nigeria | ​ | ​ | NGN | ​ | ​ | ​ | ​ | 1,800,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.89 0.11​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
OOO ‘Eni Energhia’ | ​ | ​ | Moscow (Russia) | ​ | ​ | Russia | ​ | ​ | RUB | ​ | ​ | ​ | ​ | 2,000,000 | ​ | ​ | ​ | Eni Energy Russia BV Eni Oil Holdings BV | ​ | ​ | 99.90 0.10​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Zetah Congo Ltd | ​ | ​ | Nassau (Bahamas) | ​ | ​ | Republic of the Congo | ​ | ​ | USD | ​ | ​ | ​ | ​ | 300 | ​ | ​ | ​ | Eni Congo SA Burren En.Congo Ltd | ​ | ​ | 66.67 33.33​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Zetah Kouilou Ltd | ​ | ​ | Nassau (Bahamas) | ​ | ​ | Republic of the Congo | ​ | ​ | USD | ​ | ​ | ​ | ​ | 2,000 | ​ | ​ | ​ | Eni Congo SA Burren En.Congo Ltd Third parties | ​ | ​ | 54.50 37.00 8.50​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS
Gas & Power

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
In Italy | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni gas e luce SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 750,000,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Gas Transport Services Srl | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 120,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Eni Trading & Shipping SpA | ​ | ​ | Rome | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 60,036,650 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
EniPower Mantova SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 144,000,000 | ​ | ​ | ​ | EniPower SpA Third parties | ​ | ​ | 86.50​ 13.50​ | ​ | ​ | ​ | ​ | 86.50 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
EniPower SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 944,947,849 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
LNG Shipping SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 240,900,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
SEA SpA | ​ | ​ | L’Aquila (AQ) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 100,000 | ​ | ​ | ​ | Eni gas e luce SpA Third parties | ​ | ​ | 60.00​ 40.00​ | ​ | ​ | ​ | ​ | 60.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Trans Tunisian Pipeline Co SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Tunisia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 1,098,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Outside Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana | ​ | ​ | Ljubljana (Slovenia) | ​ | ​ | Slovenia | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 12,956,935 | ​ | ​ | ​ | Eni gas e luce SpA Third parties | ​ | ​ | 51.00​ 49.00​ | ​ | ​ | ​ | ​ | 51.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni G&P Trading BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Turkey | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 70,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Gas & Power France SA | ​ | ​ | Levallois Perret (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 29,937,600 | ​ | ​ | ​ | Eni gas e luce SpA Third parties | ​ | ​ | 99.87​ 0.13​ | ​ | ​ | ​ | ​ | 99.87 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Trading & Shipping Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 36,000,000 | ​ | ​ | ​ | ETS SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Transporte y Suministro México, S. de RL de CV | ​ | ​ | Mexico City (Mexico) | ​ | ​ | Mexico | ​ | ​ | MXN | ​ | ​ | ​ | ​ | 3,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.90​ 0.10​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Gas Supply Company Thessaloniki – Thessalia SA | ​ | ​ | Thessaloniki (Greece) | ​ | ​ | Greece | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 13,761,788 | ​ | ​ | ​ | Eni gas e luce SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Société de Service du Gazoduc Transtunisien SA – Sergaz SA | ​ | ​ | Tunisi (Tunisia) | ​ | ​ | Tunisia | ​ | ​ | TND | ​ | ​ | ​ | ​ | 99,000 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 66.67​ 33.33​ | ​ | ​ | ​ | ​ | 66.67 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Société pour la Construction du Gazoduc Transtunisien SA – Scogat SA | ​ | ​ | Tunisi (Tunisia) | ​ | ​ | Tunisia | ​ | ​ | TND | ​ | ​ | ​ | ​ | 200,000 | ​ | ​ | ​ | Eni International BV Eni SpA LNG Shipping SpA Trans Tunis.P.Co SpA | ​ | ​ | 99.85​ 0.05​ 0.05​ 0.05​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS
Refining & Marketing and Chemical
Refining & Marketing
In Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Ecofuel SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 52,000,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Fuel SpA | ​ | ​ | Rome | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 58,944,310 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Petroven Srl | ​ | ​ | Genova | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 918,520 | ​ | ​ | ​ | Ecofuel SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Raffineria di Gela SpA | ​ | ​ | Gela (CL) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 15,000,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
SeaPad SpA | ​ | ​ | Genova | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 12,400,000 | ​ | ​ | ​ | Ecofuel SpA Third parties | ​ | ​ | 80.00​ 20.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Servizi Fondo Bombole Metano SpA | ​ | ​ | Rome | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 13,580,000.20 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Outside Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni Abu Dhabi Refining & Trading BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Abu Dhabi Refining & Trading Services BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni Abu Dhabi R&T BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Austria GmbH | ​ | ​ | Wien (Austria) | ​ | ​ | Austria | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 78,500,000 | ​ | ​ | ​ | Eni International BV Eni Deutsch.GmbH | ​ | ​ | 75.00​ 25.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Benelux BV | ​ | ​ | Rotterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 1,934,040 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Deutschland GmbH | ​ | ​ | Munich (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 90,000,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 89.00​ 11.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Ecuador SA | ​ | ​ | Quito (Ecuador) | ​ | ​ | Ecuador | ​ | ​ | USD | ​ | ​ | ​ | ​ | 103,142.08 | ​ | ​ | ​ | Eni International BV Esain SA | ​ | ​ | 99.93​ 0.07​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni France Sàrl | ​ | ​ | Lyon (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 56,800,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Iberia SLU | ​ | ​ | Alcobendas (Spain) | ​ | ​ | Spain | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 17,299,100 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Lubricants Trading (Shanghai) Co Ltd | ​ | ​ | Shanghai (China) | ​ | ​ | China | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 5,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Marketing Austria GmbH | ​ | ​ | Wien (Austria) | ​ | ​ | Austria | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 19,621,665.23 | ​ | ​ | ​ | Eni Mineralölh.GmbH Eni International BV | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Mineralölhandel GmbH | ​ | ​ | Wien (Austria) | ​ | ​ | Austria | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 34,156,232.06 | ​ | ​ | ​ | Eni Austria GmbH | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Schmiertechnik GmbH | ​ | ​ | Wurzburg (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 2,000,000 | ​ | ​ | ​ | Eni Deutsch.GmbH | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Suisse SA | ​ | ​ | Lausanne (Switzerland) | ​ | ​ | Switzerland | ​ | ​ | CHF | ​ | ​ | ​ | ​ | 102,500,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni USA R&M Co Inc | ​ | ​ | Wilmington (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 11,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Esacontrol SA | ​ | ​ | Quito (Ecuador) | ​ | ​ | Ecuador | ​ | ​ | USD | ​ | ​ | ​ | ​ | 60,000 | ​ | ​ | ​ | Eni Ecuador SA Third parties | ​ | ​ | 87.00​ 13.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Esain SA | ​ | ​ | Quito (Ecuador) | ​ | ​ | Ecuador | ​ | ​ | USD | ​ | ​ | ​ | ​ | 30,000 | ​ | ​ | ​ | Eni Ecuador SA Tecnoesa SA | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Oléoduc du Rhône SA | ​ | ​ | Valais (Switzerland) | ​ | ​ | Switzerland | ​ | ​ | CHF | ​ | ​ | ​ | ​ | 7,000,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
OOO “Eni-Nefto” | ​ | ​ | Moscow (Russia) | ​ | ​ | Russia | ​ | ​ | RUB | ​ | ​ | ​ | ​ | 1,010,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.01​ 0.99​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Tecnoesa SA | ​ | ​ | Quito (Ecuador) | ​ | ​ | Ecuador | ​ | ​ | USD | ​ | ​ | ​ | ​ | 36,000 | ​ | ​ | ​ | Eni Ecuador SA Esain SA | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS
Chemical

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
In Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Versalis SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 1,364,790,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Outside Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság | ​ | ​ | Budapest (Hungary) | ​ | ​ | Hungary | ​ | ​ | HUF | ​ | ​ | ​ | ​ | 8,092,160,000 | ​ | ​ | ​ | Versalis SpA Versalis Deutsc.GmbH Versalis Int.SA | ​ | ​ | 96.34​ 1.83​ 1.83​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis Americas Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 100,000 | ​ | ​ | ​ | Versalis International SA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis Congo Sarlu | ​ | ​ | Pointe-Noire (Republic of the Congo) | ​ | ​ | Republic of the Congo | ​ | ​ | XAF | ​ | ​ | ​ | ​ | 1,000,000 | ​ | ​ | ​ | Versalis International SA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis Deutschland GmbH | ​ | ​ | Eschborn (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 100,000 | ​ | ​ | ​ | Versalis SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis France SAS | ​ | ​ | Mardyck (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 126,115,582.90 | ​ | ​ | ​ | Versalis SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis International SA | ​ | ​ | Bruxelles (Belgium) | ​ | ​ | Belgium | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 15,449,173.88 | ​ | ​ | ​ | Versalis SpA Versalis Deutsc.GmbH Dunastyr Zrt Versalis France | ​ | ​ | 59.00​ 23.71​ 14.43​ 2.86​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis Kimya Ticaret Limited Sirketi | ​ | ​ | Istanbul (Turkey) | ​ | ​ | Turkey | ​ | ​ | TRY | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Versalis Int.SA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Versalis México S. de R.L. de CV | ​ | ​ | Mexico City (Mexico) | ​ | ​ | Mexico | ​ | ​ | MXN | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Versalis Int. SA Versalis SpA | ​ | ​ | 99.00​ 1.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Versalis Pacific (India) Private Ltd | ​ | ​ | Mumbai (India) | ​ | ​ | India | ​ | ​ | INR | ​ | ​ | ​ | ​ | 238,700 | ​ | ​ | ​ | Versalis Sing. P. Ltd Third parties | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Versalis Pacific Trading (Shanghai) Co Ltd | ​ | ​ | Shanghai (China) | ​ | ​ | China | ​ | ​ | CNY | ​ | ​ | ​ | ​ | 1,000,000 | ​ | ​ | ​ | Versalis SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis Singapore Pte Ltd | ​ | ​ | Singapore (Singapore) | ​ | ​ | Singapore | ​ | ​ | SGD | ​ | ​ | ​ | ​ | 80,000 | ​ | ​ | ​ | Versalis SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Versalis UK Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 4,004,042 | ​ | ​ | ​ | Versalis SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS
Corporate and Other activities
Corporate and financial companies

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
In Italy​ | ​
Agenzia Giornalistica Italia SpA | ​ | ​ | Rome | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 2,000,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
D-Service Media Srl (in liquidation) | ​ | ​ | Milan | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 75,000 | ​ | ​ | ​ | D-Share SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
D-Share SpA | ​ | ​ | Milan | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 121,719.25 | ​ | ​ | ​ | Agi SpA Third parties | ​ | ​ | 55.21​ 44.79​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Eni Corporate University SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 3,360,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
EniServizi SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 13,427,419.08 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Serfactoring SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 5,160,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 49.00​ 51.00​ | ​ | ​ | ​ | ​ | 49.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Servizi Aerei SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 79,817,238 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Outside Italy​ | ​
Banque Eni SA | ​ | ​ | Bruxelles (Belgium) | ​ | ​ | Belgium | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 50,000,000 | ​ | ​ | ​ | Eni International BV Eni Oil Holdings BV | ​ | ​ | 99.90​ 0.10​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
D-Share USA Corp. | ​ | ​ | New York (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 0(a) | ​ | ​ | ​ | D-Share SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Eni Finance International SA | ​ | ​ | Bruxelles (Belgium) | ​ | ​ | Belgium | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,480,365,336 | ​ | ​ | ​ | Eni International BV Eni SpA | ​ | ​ | 66.39​ 33.61​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Finance USA Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 15,000,000 | ​ | ​ | ​ | Eni Petroleum Co Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Insurance DAC | ​ | ​ | Dublin (Ireland) | ​ | ​ | Ireland | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 500,000,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni International BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 641,683,425 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni International Resources Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 50,000 | ​ | ​ | ​ | Eni SpA Eni UK Ltd | ​ | ​ | 99.99​ (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Next Llc | ​ | ​ | Houston (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | Eni Petroleum Co Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
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.
​
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TABLE OF CONTENTS
Other activities

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
In Italy​ | ​
Anic Partecipazioni SpA (in liquidation) | ​ | ​ | Gela (CL) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 23,519,847.16 | ​ | ​ | ​ | Eni Rewind SpA Third parties | ​ | ​ | 99.97 0.03​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Energia Srl | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 10,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Eni Energy Activities Srl | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 50,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Eni New Energy SpA | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 9,296,000 | ​ | ​ | ​ | Eni SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Rewind SpA (former Syndial Servizi Ambientali SpA) | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 425,343,731.50 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 99.99 (..)​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Industria Siciliana Acido Fosforico-ISAF-SpA (in liquidation) | ​ | ​ | Gela (CL) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 1,300,000 | ​ | ​ | ​ | Eni Rewind SpA Third parties | ​ | ​ | 52.00 48.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Ing. Luigi Conti Vecchi SpA | ​ | ​ | Assemini (CA) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 5,518,620.64 | ​ | ​ | ​ | Eni Rewind SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Outside Italy​ | ​
Arm Wind Llp | ​ | ​ | Nur-Sultan (Kazakhstan) | ​ | ​ | Kazakhstan | ​ | ​ | KZT | ​ | ​ | ​ | ​ | 7,963,200,000 | ​ | ​ | ​ | Windirect BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni Energy Solutions BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni New Energy Egypt SAE | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 250,000 | ​ | ​ | ​ | Eni International BV Ieoc Exploration BV Ieoc Production BV | ​ | ​ | 99.98 0.01 0.01​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni New Energy Pakistan (Private) Ltd | ​ | ​ | Saddar Town-Karachi (Pakistan) | ​ | ​ | Pakistan | ​ | ​ | PKR | ​ | ​ | ​ | ​ | 136,000,000 | ​ | ​ | ​ | Eni International BV Eni Oil Hold. BV Eni Pakistan Ltd (M) | ​ | ​ | 99.98 0.01 0.01​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​
Eni New Energy US Inc | ​ | ​ | Dover, Delaware (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 100 | ​ | ​ | ​ | Eni Petroleum Co Inc | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Eni Rewind International BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Oleodotto del Reno SA | ​ | ​ | Coira (Switzerland) | ​ | ​ | Switzerland | ​ | ​ | CHF | ​ | ​ | ​ | ​ | 1,550,000 | ​ | ​ | ​ | Eni Rewind SpA | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Windirect BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Netherlands | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 10,000 | ​ | ​ | ​ | Eni International BV | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | 100.00 | ​ | ​ | ​ | ​ | ​ | F.C. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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TABLE OF CONTENTS
Joint arrangements and associates
Exploration & Production
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-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 Co | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc SpA Third parties | ​ | ​ | 25.00 75.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Petrobel Belayim Petroleum Co (†) | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
PetroBicentenario SA (†)​ | ​ | ​ | Caracas (Venezuela) | ​ | ​ | Venezuela | ​ | ​ | VES | ​ | ​ | ​ | ​ | 3,790 | ​ | ​ | ​ | Eni Lasmo Plc Third parties | ​ | ​ | 40.00 60.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
PetroJunín SA (†) | ​ | ​ | Caracas (Venezuela) | ​ | ​ | Venezuela | ​ | ​ | VES | ​ | ​ | ​ | ​ | 24,021 | ​ | ​ | ​ | Eni Lasmo Plc Third parties | ​ | ​ | 40.00 60.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
PetroSucre SA | ​ | ​ | Caracas (Venezuela) | ​ | ​ | Venezuela | ​ | ​ | VES | ​ | ​ | ​ | ​ | 2,203 | ​ | ​ | ​ | Eni Venezuela BV Third parties | ​ | ​ | 26.00 74.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Pharaonic Petroleum Co | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 25.00 75.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Point Resources FPSO AS | ​ | ​ | Sandnes (Norway) | ​ | ​ | Norway | ​ | ​ | NOK | ​ | ​ | ​ | ​ | 150,100,000 | ​ | ​ | ​ | PR FPSO Holding AS | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Point Resources FPSO Holding AS | ​ | ​ | Sandnes (Norway) | ​ | ​ | Norway | ​ | ​ | NOK | ​ | ​ | ​ | ​ | 60,000 | ​ | ​ | ​ | Vår Energi AS | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Port Said Petroleum Co (†)​ | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
PR Jotun DA | ​ | ​ | Sandnes (Norway) | ​ | ​ | Norway | ​ | ​ | NOK | ​ | ​ | ​ | ​ | 0(a) | ​ | ​ | ​ | PR FPSO AS PR FPSO Holding AS | ​ | ​ | 95.00 5.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Raml Petroleum Co | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 22.50 77.50​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Ras Qattara Petroleum Co | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 37.50 62.50​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Rovuma Basin LNG Land Limitada (†) | ​ | ​ | Maputo (Mozambique) | ​ | ​ | Mozambique | ​ | ​ | MZN | ​ | ​ | ​ | ​ | 140,000 | ​ | ​ | ​ | Mozamb. Rov. V. SpA Third parties | ​ | ​ | 33.33 66.67​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Rovuma LNG Investments (DIFC) Ltd | ​ | ​ | Maputo (Mozambique) | ​ | ​ | Mozambique | ​ | ​ | USD | ​ | ​ | ​ | ​ | 50,000 | ​ | ​ | ​ | Eni Moz. LNG H. BV Third parties | ​ | ​ | 25.00 75.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Rovuma LNG SA | ​ | ​ | Maputo (Mozambique) | ​ | ​ | Mozambique | ​ | ​ | MZN | ​ | ​ | ​ | ​ | 100,000,000 | ​ | ​ | ​ | Eni Moz. LNG H. BV Third parties | ​ | ​ | 25.00 75.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Shorouk Petroleum Company | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 25.00 75.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Société Centrale Electrique du Congo SA | ​ | ​ | Pointe-Noire (Republic of the Congo) | ​ | ​ | Republic of the Congo | ​ | ​ | XAF | ​ | ​ | ​ | ​ | 44,732,000,000 | ​ | ​ | ​ | Eni Congo SA Third parties | ​ | ​ | 20.00 80.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Société Italo Tunisienne d’Exploitation Pétrolière SA (†) | ​ | ​ | Tunisi (Tunisia) | ​ | ​ | Tunisia | ​ | ​ | TND | ​ | ​ | ​ | ​ | 5,000,000 | ​ | ​ | ​ | Eni Tunisia BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Sodeps - Société de Developpement et d’Exploitation du Permis du Sud SA (†) | ​ | ​ | Tunisi (Tunisia) | ​ | ​ | Tunisia | ​ | ​ | TND | ​ | ​ | ​ | ​ | 100,000 | ​ | ​ | ​ | Eni Tunisia BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
Tecninco Engineering Contractors Llp (†) | ​ | ​ | Aksai (Kazakhstan) | ​ | ​ | Kazakhstan | ​ | ​ | KZT | ​ | ​ | ​ | ​ | 29,478,455 | ​ | ​ | ​ | EniProgetti SpA Third parties | ​ | ​ | 49.00 51.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Thekah Petroleum Co (in liquidation) | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Exploration BV Third parties | ​ | ​ | 25.00 75.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
United Gas Derivatives Co | ​ | ​ | New Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | USD | ​ | ​ | ​ | ​ | 153,000,000 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 33.33 66.67​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Vår Energi AS(†) | ​ | ​ | Forus (Norway) | ​ | ​ | Norway | ​ | ​ | NOK | ​ | ​ | ​ | ​ | 399,425,000 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 69.60 30.40​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Vår Energi Marine AS | ​ | ​ | Sandnes (Norway) | ​ | ​ | Norway | ​ | ​ | NOK | ​ | ​ | ​ | ​ | 61,000,000 | ​ | ​ | ​ | Vår Energi AS | ​ | ​ | 100.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
VIC CBM Ltd (†)​ | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | USD | ​ | ​ | ​ | ​ | 52,315,912 | ​ | ​ | ​ | Eni Lasmo Plc Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Virginia Indonesia Co CBM Ltd (†) | ​ | ​ | London (United Kingdom) | ​ | ​ | Indonesia | ​ | ​ | USD | ​ | ​ | ​ | ​ | 25,631,640 | ​ | ​ | ​ | Eni Lasmo Plc Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
West Ashrafi Petroleum Co (†) (in liquidation) | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Exploration BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
(†)
Jointly controlled entity.
​
(a)
Shares without nominal value.
​
F-133

TABLE OF CONTENTS
Gas & Power
In Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method (*) | ​
Mariconsult SpA (†)​ | ​ | ​ | Milan | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 120,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Società EniPower Ferrara Srl (†) | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 140,000,000 | ​ | ​ | ​ | EniPower SpA Third parties | ​ | ​ | 51.00 49.00​ | ​ | ​ | ​ | ​ | 51.00 | ​ | ​ | ​ | ​ | ​ | J.O. | ​ | ​
Transmed SpA (†)​ | ​ | ​ | Milan | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 240,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Outside Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Angola LNG Supply Services Llc | ​ | ​ | Wilmington (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 19,278,782 | ​ | ​ | ​ | Eni USA Gas M. Llc Third parties | ​ | ​ | 13.60 86.40​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Blue Stream Pipeline Co BV (†) | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Russia | ​ | ​ | USD | ​ | ​ | ​ | ​ | 22,000 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | 74.62(a) | ​ | ​ | ​ | ​ | ​ | J.O. | ​ | ​
Gas Distribution Company of Thessaloniki - Thessaly SA (†) | ​ | ​ | Ampelokipi- Menemeni (Greece) | ​ | ​ | Greece | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 247,127,605 | ​ | ​ | ​ | Eni gas e luce SpA Third parties | ​ | ​ | 49.00 51.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
GreenStream BV (†)​ | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Libya | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 200,000,000 | ​ | ​ | ​ | Eni North Africa BV Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | J.O. | ​ | ​
Premium Multiservices SA | ​ | ​ | Tunisi (Tunisia) | ​ | ​ | Tunisia | ​ | ​ | TND | ​ | ​ | ​ | ​ | 200,000 | ​ | ​ | ​ | Sergaz SA Third parties | ​ | ​ | 49.99 50.01​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
SAMCO Sagl | ​ | ​ | Lugano (Switzerland) | ​ | ​ | Switzerland | ​ | ​ | CHF | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Eni International BV Transmed.Pip.Co Ltd Third parties | ​ | ​ | 5.00 90.00 5.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Transmediterranean Pipeline Co Ltd (†)​ | ​ | ​ | St. Helier (Jersey) | ​ | ​ | Jersey | ​ | ​ | USD | ​ | ​ | ​ | ​ | 10,310,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | J.O. | ​ | ​
Unión Fenosa Gas SA (†) | ​ | ​ | Madrid (Spain) | ​ | ​ | Spain | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 32,772,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​

​
(*)
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-135

TABLE OF CONTENTS
Outside Italy​

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
Abu Dhabi Oil Refining Company (TAKREER) | ​ | ​ | Abu Dhabi (United Arab Emirates) | ​ | ​ | United Arab Emirates | ​ | ​ | AED | ​ | ​ | ​ | ​ | 500,000,000 | ​ | ​ | ​ | Eni Abu Dhabi R&T BV Third parties | ​ | ​ | 20.00 80.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
ADNOC Global Trading Ltd | ​ | ​ | Abu Dhabi (United Arab Emirates) | ​ | ​ | United Arab Emirates | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000 | ​ | ​ | ​ | Eni Abu Dhabi R&T BV Third parties | ​ | ​ | 20.00 80.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
AET - Raffinerie beteiligungs gesellschaft mbH(†) | ​ | ​ | Schwedt (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 27,000 | ​ | ​ | ​ | Eni Deutsch.GmbH Third parties | ​ | ​ | 33.33 66.67​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Bayernoil Raffinerie gesellschaft mbH(†)​ | ​ | ​ | Vohburg (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 10,226,000 | ​ | ​ | ​ | Eni Deutsch.GmbH Third parties | ​ | ​ | 20.00 80.00​ | ​ | ​ | ​ | ​ | 20.00 | ​ | ​ | ​ | ​ | ​ | J.O. | ​ | ​
City Carburoil SA(†)​ | ​ | ​ | Rivera (Switzerland) | ​ | ​ | Switzerland | ​ | ​ | CHF | ​ | ​ | ​ | ​ | 6,000,000 | ​ | ​ | ​ | Eni Suisse SA Third parties | ​ | ​ | 49.91 50.09​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Egyptian International Gas Technology Co | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 100,000,000 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 40.00 60.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Co. | ​ | ​
ENEOS Italsing Pte Ltd | ​ | ​ | Singapore (Singapore) | ​ | ​ | Singapore | ​ | ​ | SGD | ​ | ​ | ​ | ​ | 12,000,000 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 22.50 77.50​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Fuelling Aviation Services GIE | ​ | ​ | Tremblay en France (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 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 | ​ | ​ | 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 | ​

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Chemical

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | % Equity ratio | ​ | ​ | Consolidation or valutation method(*) | ​
In Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Brindisi Servizi Generali Scarl | ​ | ​ | Brindisi | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 1,549,060 | ​ | ​ | ​ | Versalis SpA Eni Rewind SpA EniPower SpA Third parties | ​ | ​ | 49.00 20.20 8.90 21.90​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
IFM Ferrara ScpA | ​ | ​ | Ferrara | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 5,270,466 | ​ | ​ | ​ | Versalis SpA Eni Rewind SpA S.E.F. Srl Third parties | ​ | ​ | 19.74 11.58 10.70 57.98​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Matrìca SpA(†) | ​ | ​ | Porto Torres (SS) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 37,500,000 | ​ | ​ | ​ | Versalis SpA Third parties | ​ | ​ | 50.00 50.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
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 Eni Rewind SpA Third parties | ​ | ​ | 33.11 4.61 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 Eni Rewind SpA Third parties | ​ | ​ | 48.44 38.39 13.17​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
Outside Italy​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lotte Versalis Elastomers Co Ltd(†) | ​ | ​ | Yeosu (South Korea) | ​ | ​ | South Korea | ​ | ​ | KRW | ​ | ​ | ​ | ​ | 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.
​
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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 (*) | ​
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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | Ottana Sviluppo ScpA (in bankruptcy) | ​ | ​ | Nuoro | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 516,000 | ​ | ​ | ​ | Eni Rewind SpA Third parties | ​ | ​ | 30.00 70.00​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
​ | Progetto Nuraghe Scarl | ​ | ​ | Porto Torres (SS) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 10,000 | ​ | ​ | ​ | Eni Rewind SpA Third parties | ​ | ​ | 48.55 51.45​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Eq. | ​ | ​
​ | Saipem SpA(#) (†)​ | ​ | ​ | San Donato Milanese (MI) | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 2,191,384,693 | ​ | ​ | ​ | Eni SpA Saipem SpA Third parties | ​ | ​ | 30.54(c) 1.46 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.
​

​ | (c) Controlling interest: ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 30.99 69.01 | ​

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Other significant investments
Exploration & Production
In Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | Consolidation or valutation method(*) | ​
Consorzio Universitario in Ingegneria per la Qualità e l’Innovazione | ​ | ​ | Pisa | ​ | ​ | Italy | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 135,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 20.00 80.00​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​

Outside Italy

​ | Administradora del Golfo de Paria Este SA | ​ | ​ | Caracas (Venezuela) | ​ | ​ | Venezuela | ​ | ​ | VES | ​ | ​ | ​ | ​ | 0.001 | ​ | ​ | ​ | Eni Venezuela BV Third parties | ​ | ​ | 19.50 80.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | Brass LNG Ltd | ​ | ​ | Lagos (Nigeria) | ​ | ​ | Nigeria | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,000,000 | ​ | ​ | ​ | Eni Int. NA NV Sàrl Third parties | ​ | ​ | 20.48 79.52​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | Darwin LNG Pty Ltd | ​ | ​ | West Perth (Australia) | ​ | ​ | Australia | ​ | ​ | AUD | ​ | ​ | ​ | ​ | 367,278,503.01 | ​ | ​ | ​ | Eni G&P LNG Aus. BV Third parties | ​ | ​ | 10.99 89.01​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | New Liberty Residential Co Llc | ​ | ​ | West Trenton (USA) | ​ | ​ | USA | ​ | ​ | USD | ​ | ​ | ​ | ​ | 0(a) | ​ | ​ | ​ | Eni Oil & Gas Inc Third parties | ​ | ​ | 17.50 82.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | Nigeria LNG Ltd | ​ | ​ | Port Harcourt (Nigeria) | ​ | ​ | Nigeria | ​ | ​ | USD | ​ | ​ | ​ | ​ | 1,138,207,000 | ​ | ​ | ​ | Eni Int. NA NV Sàrl Third parties | ​ | ​ | 10.40 89.60​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | North Caspian Operating Co NV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Kazakhstan | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 128,520 | ​ | ​ | ​ | Agip Caspian Sea BV Third parties | ​ | ​ | 16.81 83.19​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | OPCO - Sociedade Operacional Angola LNG SA | ​ | ​ | Luanda (Angola) | ​ | ​ | Angola | ​ | ​ | AOA | ​ | ​ | ​ | ​ | 7,400,000 | ​ | ​ | ​ | Eni Angola Prod.BV Third parties | ​ | ​ | 13.60 86.40​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | Petrolera Güiria SA | ​ | ​ | Caracas (Venezuela) | ​ | ​ | Venezuela | ​ | ​ | VES | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | Eni Venezuela BV Third parties | ​ | ​ | 19.50 80.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | SOMG - Sociedade de Operações e Manutenção de Gasodutos SA | ​ | ​ | Luanda (Angola) | ​ | ​ | Angola | ​ | ​ | AOA | ​ | ​ | ​ | ​ | 7,400,000 | ​ | ​ | ​ | Eni Angola Prod.BV Third parties | ​ | ​ | 13.60 86.40​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
​ | Torsina Oil Co | ​ | ​ | Cairo (Egypt) | ​ | ​ | Egypt | ​ | ​ | EGP | ​ | ​ | ​ | ​ | 20,000 | ​ | ​ | ​ | Ieoc Production BV Third parties | ​ | ​ | 12.50 87.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
(a)
Shares without nominal value.
​
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Gas & Power
Outside Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | Consolidation or valutation method (*) | ​
Norsea Gas GmbH | ​ | ​ | Emden (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 1,533,875.64 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 13.04 86.96​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
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Refining & Marketing and Chemical
Refining & Marketing
In Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | Consolidation or valutation method(*) | ​
Società Italiana Oleodotti di Gaeta SpA(a) | ​ | ​ | Rome | ​ | ​ | Italy | ​ | ​ | ITL | ​ | ​ | ​ | ​ | 360,000,000 | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 72.48 27.52​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​

Outside Italy

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Currency | ​ | ​ | Share Capital | ​ | ​ | Shareholders | ​ | ​ | % Ownership | ​ | ​ | Consolidation or valutation method(*) | ​
BFS Berlin Fuelling Services GbR | ​ | ​ | Hamburg (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 89,199 | ​ | ​ | ​ | Eni Deutsch.GmbH Third parties | ​ | ​ | 12.50 87.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Compania de Economia Mixta ‘Austrogas’ | ​ | ​ | Cuenca (Ecuador) | ​ | ​ | Ecuador | ​ | ​ | USD | ​ | ​ | ​ | ​ | 5,665,329 | ​ | ​ | ​ | Eni Ecuador SA Third parties | ​ | ​ | 13.38 86.62​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Dépôt Pétrolier de Fos SA | ​ | ​ | Fos-Sur-Mer (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 3,954,196.40 | ​ | ​ | ​ | Eni France Sàrl Third parties | ​ | ​ | 16.81 83.19​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Dépôt Pétrolier de la Côte d’Azur SAS | ​ | ​ | Nanterre (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 207,500 | ​ | ​ | ​ | Eni France Sàrl Third parties | ​ | ​ | 18.00 82.00​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Joint Inspection Group Ltd | ​ | ​ | London (United Kingdom) | ​ | ​ | United Kingdom | ​ | ​ | GBP | ​ | ​ | ​ | ​ | 0(b) | ​ | ​ | ​ | Eni SpA Third parties | ​ | ​ | 12.50 87.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
S.I.P.G. Société Immobilière Pétrolière de Gestion Snc | ​ | ​ | Tremblay-En-France (France) | ​ | ​ | France | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 40,000 | ​ | ​ | ​ | Eni France Sàrl Third parties | ​ | ​ | 12.50 87.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Sistema Integrado de Gestion de Aceites Usados | ​ | ​ | Madrid (Spain) | ​ | ​ | Spain | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 175,713 | ​ | ​ | ​ | Eni Iberia SLU Third parties | ​ | ​ | 15.44 84.56​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Tanklager - Gesellschaft Tegel (TGT) GbR | ​ | ​ | Hamburg (Germany) | ​ | ​ | Germany | ​ | ​ | EUR | ​ | ​ | ​ | ​ | 4,953 | ​ | ​ | ​ | Eni Deutsch.GmbH Third parties | ​ | ​ | 12.50 87.50​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
TAR - Tankanlage Ruemlang AG | ​ | ​ | Ruemlang (Switzerland) | ​ | ​ | Switzerland | ​ | ​ | CHF | ​ | ​ | ​ | ​ | 3,259,500 | ​ | ​ | ​ | Eni Suisse SA Third parties | ​ | ​ | 16.27 83.73​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​
Tema Lube Oil Co Ltd | ​ | ​ | Accra (Ghana) | ​ | ​ | Ghana | ​ | ​ | GHS | ​ | ​ | ​ | ​ | 258,309 | ​ | ​ | ​ | Eni International BV Third parties | ​ | ​ | 12.00 88.00​ | ​ | ​ | ​ | ​ | F.V. | ​ | ​

​
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
​
(a)
Company under extraordinary administration procedure pursuant to law no. 95 of april 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the authorization by the Ministry of Economic Development.
​
(b)
Shares without nominal value.
​
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Information on Eni’s consolidated subsidiaries with significant non-controlling interest
In 2019 and 2018, Eni did not own any consolidated subsidiaries with a significant non-controlling interest.
The total shareholders’ equity pertaining to minority interests as of December 31, 2019, amounted to €61 million (€57 million December 31, 2018).
Changes in the ownership interest without loss of control
In 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, 2019

Company name | ​ | ​ | Registered office | ​ | ​ | Country of operation | ​ | ​ | Business segment | ​ | ​ | % ownership interest | ​ | ​ | Eni’s % of the investment | ​
Joint venture | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Vår Energi AS | ​ | ​ | Forus (Norway) | ​ | ​ | Norway | ​ | ​ | Exploration & Production | ​ | ​ | ​ | ​ | 69.60 | ​ | ​ | ​ | 69.60 | ​
Saipem SpA | ​ | ​ | San Donato Milanese (MI) (Italy) | ​ | ​ | Italy | ​ | ​ | Other Activities | ​ | ​ | ​ | ​ | 30.54 | ​ | ​ | ​ | 30.99 | ​
Unión Fenosa Gas SA | ​ | ​ | Madrid (Spain) | ​ | ​ | Spain | ​ | ​ | Gas & Power | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | 50.00 | ​
Cardón IV SA | ​ | ​ | Caracas (Venezuela) | ​ | ​ | Venezuela | ​ | ​ | Exploration & Production | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | 50.00 | ​
Gas Distribution Company of Thessaloniki - Thessaly SA | ​ | ​ | Ampelokipi-Menemeni (Greece) | ​ | ​ | Greece | ​ | ​ | Gas & Power | ​ | ​ | ​ | ​ | 49.00 | ​ | ​ | ​ | 49.00 | ​
Joint Operation | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Mozambique Rovuma Venture SpA | ​ | ​ | San Donato Milanese (MI) (Italy) | ​ | ​ | Mozambique | ​ | ​ | Exploration & Production | ​ | ​ | ​ | ​ | 35.71 | ​ | ​ | ​ | 35.71 | ​
Raffineria di Milazzo ScpA | ​ | ​ | Milazzo (ME) (Italy) | ​ | ​ | Italy | ​ | ​ | Refining & Marketing | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | 50.00 | ​
GreenStream BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Libya | ​ | ​ | Gas & Power | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | 50.00 | ​
Blue Stream Pipeline Co BV | ​ | ​ | Amsterdam (Netherlands) | ​ | ​ | Russia | ​ | ​ | Gas & Power | ​ | ​ | ​ | ​ | 74.62 | ​ | ​ | ​ | 74.62 | ​
Associates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Abu Dhabi Oil Refining Co (Takreer) | ​ | ​ | Abu Dhabi (United Arab Emirates) | ​ | ​ | United Arab Emirates | ​ | ​ | Refining & Marketing | ​ | ​ | ​ | ​ | 20.00 | ​ | ​ | ​ | 20.00 | ​
Angola LNG Ltd | ​ | ​ | Hamilton (Bermuda) | ​ | ​ | Angola | ​ | ​ | Exploration & Production | ​ | ​ | ​ | ​ | 13.60 | ​ | ​ | ​ | 13.60 | ​
Coral FLNG SA | ​ | ​ | Maputo (Mozambique) | ​ | ​ | Mozambique | ​ | ​ | Exploration & Production | ​ | ​ | ​ | ​ | 25.00 | ​ | ​ | ​ | 25.00 | ​

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Main line items of profit and loss and balance sheet related to the principal joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below:

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​
(€ million) | ​ | ​ | Vår Energi AS | ​ | ​ | Saipem SpA | ​ | ​ | Unión Fenosa Gas SA | ​ | ​ | Cardón IV SA | ​ | ​ | Gas Distribution Company of Thessaloniki -Thessaly SA | ​ | ​ | Other joint ventures | ​
Current assets | ​ | ​ | ​ | ​ | 1,385 | ​ | ​ | ​ | ​ | ​ | 7,012 | ​ | ​ | ​ | ​ | ​ | 585 | ​ | ​ | ​ | ​ | ​ | 208 | ​ | ​ | ​ | ​ | ​ | 31 | ​ | ​ | ​ | ​ | ​ | 551 | ​ | ​
- of which cash and cash equivalent | ​ | ​ | ​ | ​ | 182 | ​ | ​ | ​ | ​ | ​ | 2,272 | ​ | ​ | ​ | ​ | ​ | 41 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 40 | ​ | ​
Non-current assets | ​ | ​ | ​ | ​ | 18,427 | ​ | ​ | ​ | ​ | ​ | 5,997 | ​ | ​ | ​ | ​ | ​ | 827 | ​ | ​ | ​ | ​ | ​ | 2,383 | ​ | ​ | ​ | ​ | ​ | 322 | ​ | ​ | ​ | ​ | ​ | 1,085 | ​ | ​
Total assets | ​ | ​ | ​ | ​ | 19,812 | ​ | ​ | ​ | ​ | ​ | 13,009 | ​ | ​ | ​ | ​ | ​ | 1,412 | ​ | ​ | ​ | ​ | ​ | 2,591 | ​ | ​ | ​ | ​ | ​ | 353 | ​ | ​ | ​ | ​ | ​ | 1,636 | ​ | ​
Current liabilities | ​ | ​ | ​ | ​ | 2,374 | ​ | ​ | ​ | ​ | ​ | 5,204 | ​ | ​ | ​ | ​ | ​ | 225 | ​ | ​ | ​ | ​ | ​ | 255 | ​ | ​ | ​ | ​ | ​ | 24 | ​ | ​ | ​ | ​ | ​ | 819 | ​ | ​
- current financial liabilities | ​ | ​ | ​ | ​ | 33 | ​ | ​ | ​ | ​ | ​ | 557 | ​ | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | 165 | ​ | ​
Non-current liabilities | ​ | ​ | ​ | ​ | 13,820 | ​ | ​ | ​ | ​ | ​ | 3,680 | ​ | ​ | ​ | ​ | ​ | 563 | ​ | ​ | ​ | ​ | ​ | 2,040 | ​ | ​ | ​ | ​ | ​ | 46 | ​ | ​ | ​ | ​ | ​ | 354 | ​ | ​
- non-current financial liabilities | ​ | ​ | ​ | ​ | 3,929 | ​ | ​ | ​ | ​ | ​ | 3,147 | ​ | ​ | ​ | ​ | ​ | 493 | ​ | ​ | ​ | ​ | ​ | 1,140 | ​ | ​ | ​ | ​ | ​ | 33 | ​ | ​ | ​ | ​ | ​ | 274 | ​ | ​
Total liabilities | ​ | ​ | ​ | ​ | 16,194 | ​ | ​ | ​ | ​ | ​ | 8,884 | ​ | ​ | ​ | ​ | ​ | 788 | ​ | ​ | ​ | ​ | ​ | 2,295 | ​ | ​ | ​ | ​ | ​ | 70 | ​ | ​ | ​ | ​ | ​ | 1,173 | ​ | ​
Net equity | ​ | ​ | ​ | ​ | 3,618 | ​ | ​ | ​ | ​ | ​ | 4,125 | ​ | ​ | ​ | ​ | ​ | 624 | ​ | ​ | ​ | ​ | ​ | 296 | ​ | ​ | ​ | ​ | ​ | 283 | ​ | ​ | ​ | ​ | ​ | 463 | ​ | ​
Eni’s % of the investment | ​ | ​ | ​ | ​ | 69.60 | ​ | ​ | ​ | ​ | ​ | 30.99 | ​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | 49.00 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Book value of the investment | ​ | ​ | ​ | ​ | 2,518 | ​ | ​ | ​ | ​ | ​ | 1,250 | ​ | ​ | ​ | ​ | ​ | 326 | ​ | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | 139 | ​ | ​ | ​ | ​ | ​ | 199 | ​ | ​
Revenues and other income | ​ | ​ | ​ | ​ | 2,552 | ​ | ​ | ​ | ​ | ​ | 9,118 | ​ | ​ | ​ | ​ | ​ | 1,255 | ​ | ​ | ​ | ​ | ​ | 598 | ​ | ​ | ​ | ​ | ​ | 58 | ​ | ​ | ​ | ​ | ​ | 270 | ​ | ​
Operating expense | ​ | ​ | ​ | ​ | (1,015) | ​ | ​ | ​ | ​ | ​ | (7,972) | ​ | ​ | ​ | ​ | ​ | (1,221) | ​ | ​ | ​ | ​ | ​ | (456) | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | (277) | ​ | ​
Depreciation, amortization and impairments | ​ | ​ | ​ | ​ | (1,208) | ​ | ​ | ​ | ​ | ​ | (690) | ​ | ​ | ​ | ​ | ​ | (53) | ​ | ​ | ​ | ​ | ​ | (86) | ​ | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | (47) | ​ | ​
Operating profit | ​ | ​ | ​ | ​ | 329 | ​ | ​ | ​ | ​ | ​ | 456 | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 28 | ​ | ​ | ​ | ​ | ​ | (54) | ​ | ​
Finance income (expense) | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (210) | ​ | ​ | ​ | ​ | ​ | (37) | ​ | ​ | ​ | ​ | ​ | (133) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (14) | ​ | ​
Income (expense) from investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (18) | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Profit before income taxes | ​ | ​ | ​ | ​ | 328 | ​ | ​ | ​ | ​ | ​ | 228 | ​ | ​ | ​ | ​ | ​ | (50) | ​ | ​ | ​ | ​ | ​ | (77) | ​ | ​ | ​ | ​ | ​ | 27 | ​ | ​ | ​ | ​ | ​ | (68) | ​ | ​
Income taxes | ​ | ​ | ​ | ​ | (258) | ​ | ​ | ​ | ​ | ​ | (130) | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | (103) | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | ​ | ​ | ​ | (12) | ​ | ​
Net profit | ​ | ​ | ​ | ​ | 70 | ​ | ​ | ​ | ​ | ​ | 98 | ​ | ​ | ​ | ​ | ​ | (42) | ​ | ​ | ​ | ​ | ​ | (180) | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | (80) | ​ | ​
Other comprehensive income | ​ | ​ | ​ | ​ | 40 | ​ | ​ | ​ | ​ | ​ | 66 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total other comprehensive income | ​ | ​ | ​ | ​ | 110 | ​ | ​ | ​ | ​ | ​ | 164 | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | (175) | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | (80) | ​ | ​
Net profit attributable to Eni | ​ | ​ | ​ | ​ | 49 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | (90) | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | (40) | ​ | ​
Dividends received from the joint venture | ​ | ​ | ​ | ​ | 1,057 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​
​

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2018 | ​
(€ million) | ​ | ​ | Vår Energi AS | ​ | ​ | Saipem SpA | ​ | ​ | Unión Fenosa Gas SA | ​ | ​ | Gas Distribution Company of Thessaloniki -Thessaly SA | ​ | ​ | Cardón IV SA | ​ | ​ | Lotte Versalis Elastomers Co Ltd | ​ | ​ | PetroJunín SA | ​ | ​ | Other joint ventures | ​
Current assets | ​ | ​ | ​ | ​ | 1,366 | ​ | ​ | ​ | ​ | ​ | 6,211 | ​ | ​ | ​ | ​ | ​ | 664 | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 191 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 368 | ​ | ​ | ​ | ​ | ​ | 130 | ​ | ​
- of which cash and cash equivalent | ​ | ​ | ​ | ​ | 883 | ​ | ​ | ​ | ​ | ​ | 1,674 | ​ | ​ | ​ | ​ | ​ | 107 | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | 40 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​
Non-current assets | ​ | ​ | ​ | ​ | 11,407 | ​ | ​ | ​ | ​ | ​ | 5,466 | ​ | ​ | ​ | ​ | ​ | 832 | ​ | ​ | ​ | ​ | ​ | 302 | ​ | ​ | ​ | ​ | ​ | 2,433 | ​ | ​ | ​ | ​ | ​ | 502 | ​ | ​ | ​ | ​ | ​ | 253 | ​ | ​ | ​ | ​ | ​ | 334 | ​ | ​
Total assets | ​ | ​ | ​ | ​ | 12,773 | ​ | ​ | ​ | ​ | ​ | 11,677 | ​ | ​ | ​ | ​ | ​ | 1,496 | ​ | ​ | ​ | ​ | ​ | 334 | ​ | ​ | ​ | ​ | ​ | 2,624 | ​ | ​ | ​ | ​ | ​ | 558 | ​ | ​ | ​ | ​ | ​ | 621 | ​ | ​ | ​ | ​ | ​ | 464 | ​ | ​
Current liabilities | ​ | ​ | ​ | ​ | 608 | ​ | ​ | ​ | ​ | ​ | 4,430 | ​ | ​ | ​ | ​ | ​ | 260 | ​ | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | 232 | ​ | ​ | ​ | ​ | ​ | 111 | ​ | ​ | ​ | ​ | ​ | 470 | ​ | ​ | ​ | ​ | ​ | 307 | ​ | ​
- current financial liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 305 | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 78 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 165 | ​ | ​
Non-current liabilities | ​ | ​ | ​ | ​ | 7,139 | ​ | ​ | ​ | ​ | ​ | 3,211 | ​ | ​ | ​ | ​ | ​ | 581 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 2,196 | ​ | ​ | ​ | ​ | ​ | 297 | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 126 | ​ | ​
- non-current financial liabilities | ​ | ​ | ​ | ​ | 366 | ​ | ​ | ​ | ​ | ​ | 2,646 | ​ | ​ | ​ | ​ | ​ | 510 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,410 | ​ | ​ | ​ | ​ | ​ | 289 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​
Total liabilities | ​ | ​ | ​ | ​ | 7,747 | ​ | ​ | ​ | ​ | ​ | 7,641 | ​ | ​ | ​ | ​ | ​ | 841 | ​ | ​ | ​ | ​ | ​ | 54 | ​ | ​ | ​ | ​ | ​ | 2,428 | ​ | ​ | ​ | ​ | ​ | 408 | ​ | ​ | ​ | ​ | ​ | 504 | ​ | ​ | ​ | ​ | ​ | 433 | ​ | ​
Net equity | ​ | ​ | ​ | ​ | 5,026 | ​ | ​ | ​ | ​ | ​ | 4,036 | ​ | ​ | ​ | ​ | ​ | 655 | ​ | ​ | ​ | ​ | ​ | 280 | ​ | ​ | ​ | ​ | ​ | 196 | ​ | ​ | ​ | ​ | ​ | 150 | ​ | ​ | ​ | ​ | ​ | 117 | ​ | ​ | ​ | ​ | ​ | 31 | ​ | ​
Eni’s % of the investment | ​ | ​ | ​ | ​ | 69.60 | ​ | ​ | ​ | ​ | ​ | 30.99 | ​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | 49.00 | ​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | 50.00 | ​ | ​ | ​ | ​ | ​ | 40.00 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Book value of the investment | ​ | ​ | ​ | ​ | 3,498 | ​ | ​ | ​ | ​ | ​ | 1,228 | ​ | ​ | ​ | ​ | ​ | 335 | ​ | ​ | ​ | ​ | ​ | 137 | ​ | ​ | ​ | ​ | ​ | 98 | ​ | ​ | ​ | ​ | ​ | 75 | ​ | ​ | ​ | ​ | ​ | 47 | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​
Revenues and other income | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8,530 | ​ | ​ | ​ | ​ | ​ | 1,521 | ​ | ​ | ​ | ​ | ​ | 53 | ​ | ​ | ​ | ​ | ​ | 610 | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​ | ​ | ​ | ​ | 112 | ​ | ​ | ​ | ​ | ​ | 731 | ​ | ​
Operating expense | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (7,682) | ​ | ​ | ​ | ​ | ​ | (1,461) | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | (372) | ​ | ​ | ​ | ​ | ​ | (58) | ​ | ​ | ​ | ​ | ​ | (100) | ​ | ​ | ​ | ​ | ​ | (697) | ​ | ​
Depreciation, amortization and impairments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (811) | ​ | ​ | ​ | ​ | ​ | (70) | ​ | ​ | ​ | ​ | ​ | (12) | ​ | ​ | ​ | ​ | ​ | (137) | ​ | ​ | ​ | ​ | ​ | (30) | ​ | ​ | ​ | ​ | ​ | (394) | ​ | ​ | ​ | ​ | ​ | (62) | ​ | ​
Operating profit | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | 101 | ​ | ​ | ​ | ​ | ​ | (66) | ​ | ​ | ​ | ​ | ​ | (382) | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​
Finance income (expense) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (165) | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (208) | ​ | ​ | ​ | ​ | ​ | (12) | ​ | ​ | ​ | ​ | ​ | 31 | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​
Income (expense) from investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (88) | ​ | ​ | ​ | ​ | ​ | 9 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Profit before income taxes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (216) | ​ | ​ | ​ | ​ | ​ | (32) | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | (107) | ​ | ​ | ​ | ​ | ​ | (78) | ​ | ​ | ​ | ​ | ​ | (351) | ​ | ​ | ​ | ​ | ​ | (33) | ​ | ​
Income taxes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (194) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​ | ​ | ​ | ​ | (35) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​
Net profit | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (410) | ​ | ​ | ​ | ​ | ​ | (33) | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | (142) | ​ | ​ | ​ | ​ | ​ | (78) | ​ | ​ | ​ | ​ | ​ | (370) | ​ | ​ | ​ | ​ | ​ | (43) | ​ | ​
Other comprehensive income | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (46) | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​
Total other comprehensive income | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (456) | ​ | ​ | ​ | ​ | ​ | (18) | ​ | ​ | ​ | ​ | ​ | 17 | ​ | ​ | ​ | ​ | ​ | (136) | ​ | ​ | ​ | ​ | ​ | (78) | ​ | ​ | ​ | ​ | ​ | (359) | ​ | ​ | ​ | ​ | ​ | (47) | ​ | ​
Net profit attributable to Eni | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (146) | ​ | ​ | ​ | ​ | ​ | (23) | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | (71) | ​ | ​ | ​ | ​ | ​ | (39) | ​ | ​ | ​ | ​ | ​ | (148) | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​
Dividends received from the joint venture | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​

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Main line items of profit and loss and balance sheet related to the principal associates represented by the amounts included in the reports accounted under IFRS of each company are provided in the table below:

​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 2019 | ​
(€ million) | ​ | ​ | Abu Dhabi Oil Refining Co (TAKREER) | ​ | ​ | Angola LNG Ltd | ​ | ​ | Coral FLNG SA | ​ | ​ | Other associates | ​
Current assets | ​ | ​ | ​ | ​ | 4,659 | ​ | ​ | ​ | ​ | ​ | 890 | ​ | ​ | ​ | ​ | ​ | 241 | ​ | ​ | ​ | ​ | ​ | 838 | ​ | ​
- of which cash and cash equivalent | ​ | ​ | ​ | ​ | 42 | ​ | ​ | ​ | ​ | ​ | 653 | ​ | ​ | ​ | ​ | ​ | 240 | ​ | ​ | ​ | ​ | ​ | 91 | ​ | ​
Non-current assets | ​ | ​ | ​ | ​ | 18,868 | ​ | ​ | ​ | ​ | ​ | 9,952 | ​ | ​ | ​ | ​ | ​ | 4,119 | ​ | ​ | ​ | ​ | ​ | 3,259 | ​ | ​
Total assets | ​ | ​ | ​ | ​ | 23,527 | ​ | ​ | ​ | ​ | ​ | 10,842 | ​ | ​ | ​ | ​ | ​ | 4,360 | ​ | ​ | ​ | ​ | ​ | 4,097 | ​ | ​
Current liabilities | ​ | ​ | ​ | ​ | 8,470 | ​ | ​ | ​ | ​ | ​ | 185 | ​ | ​ | ​ | ​ | ​ | 230 | ​ | ​ | ​ | ​ | ​ | 585 | ​ | ​
- current financial liabilities | ​ | ​ | ​ | ​ | 3,694 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 63 | ​ | ​
Non-current liabilities | ​ | ​ | ​ | ​ | 912 | ​ | ​ | ​ | ​ | ​ | 2,135 | ​ | ​ | ​ | ​ | ​ | 3,722 | ​ | ​ | ​ | ​ | ​ | 2,677 | ​ | ​
- non-current financial liabilities | ​ | ​ | ​ | ​ | 479 | ​ | ​ | ​ | ​ | ​ | 1,943 | ​ | ​ | ​ | ​ | ​ | 3,722 | ​ | ​ | ​ | ​ | ​ | 2,515 | ​ | ​
Total liabilities | ​ | ​ | ​ | ​ | 9,382 | ​ | ​ | ​ | ​ | ​ | 2,320 | ​ | ​ | ​ | ​ | ​ | 3,952 | ​ | ​ | ​ | ​ | ​ | 3,262 | ​ | ​
Net equity | ​ | ​ | ​ | ​ | 14,145 | ​ | ​ | ​ | ​ | ​ | 8,522 | ​ | ​ | ​ | ​ | ​ | 408 | ​ | ​ | ​ | ​ | ​ | 835 | ​ | ​
Eni’s % of the investment | ​ | ​ | ​ | ​ | 20.00 | ​ | ​ | ​ | ​ | ​ | 13.60 | ​ | ​ | ​ | ​ | ​ | 25.00 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Book value of the investment | ​ | ​ | ​ | ​ | 2,829 | ​ | ​ | ​ | ​ | ​ | 1,159 | ​ | ​ | ​ | ​ | ​ | 102 | ​ | ​ | ​ | ​ | ​ | 264 | ​ | ​
Revenues and other income | ​ | ​ | ​ | ​ | 399 | ​ | ​ | ​ | ​ | ​ | 1,552 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 818 | ​ | ​
Operating expense | ​ | ​ | ​ | ​ | (357) | ​ | ​ | ​ | ​ | ​ | (549) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (763) | ​ | ​
Depreciation, amortization and impairments | ​ | ​ | ​ | ​ | (335) | ​ | ​ | ​ | ​ | ​ | (509) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​
Operating profit | ​ | ​ | ​ | ​ | (293) | ​ | ​ | ​ | ​ | ​ | 494 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 27 | ​ | ​
Finance income (expense) | ​ | ​ | ​ | ​ | (46) | ​ | ​ | ​ | ​ | ​ | (151) | ​ | ​ | ​ | ​ | ​ | (12) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​
Income (expense) from investments | ​ | ​ | ​ | ​ | 282 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 35 | ​ | ​
Profit before income taxes | ​ | ​ | ​ | ​ | (57) | ​ | ​ | ​ | ​ | ​ | 343 | ​ | ​ | ​ | ​ | ​ | (12) | ​ | ​ | ​ | ​ | ​ | 60 | ​ | ​
Income taxes | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​
Net profit | ​ | ​ | ​ | ​ | (46) | ​ | ​ | ​ | ​ | ​ | 343 | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | ​ | ​ | ​ | 50 | ​ | ​
Other comprehensive income | ​ | ​ | ​ | ​ | (59) | ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​
Total other comprehensive income | ​ | ​ | ​ | ​ | (105) | ​ | ​ | ​ | ​ | ​ | 505 | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 55 | ​ | ​
Net profit attributable to Eni | ​ | ​ | ​ | ​ | (9) | ​ | ​ | ​ | ​ | ​ | 47 | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | 22 | ​ | ​
Dividends received from the associate | ​ | ​ | ​ | ​ | 46 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​

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​ | ​ | ​ | ​ | ​
​ | ​ | ​ | 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 | ​ | ​

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38 Significant non-recurring events and operations
In 2019, in 2018 and 2017, Eni did not report any non-recurring events and operations.
39 Positions or transactions deriving from atypical and/or unusual operations
In 2019, 2018 and 2017 no transactions deriving from atypical and/or unusual operations were reported.
40 Subsequent events
Impact 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.
Future trends in crude oil and natural gas prices will greatly depend on how the current COVID-19 crisis unfolds and on how long it lasts. Under the worst of the assumptions, the spread of the disease could trigger a global recession which could materially hit demand for energy products and prices of energy commodities. This scenario could be further complicated in case the members of the OPEC+ continue to cease supporting crude oil prices. These trends could have a material and adverse effect on our results of operations, cash flow, liquidity and business prospects, including trends in Eni shares and shareholders’ returns.
We retain some levers of financial flexibility in case of a significant contraction in cash flow from operations. The Group has established a liquidity reserve consisting of very liquid sovereign bonds and corporate securities which amounted to €6.8 billion at the balance sheet date, which together with cash on hands of approximately €6 billion will cushion the impact of a decline in liquidity. Furthermore, we have as of December 31, 2019, undrawn uncommitted borrowing facilities amounting to €13,299 million and undrawn long-term committed borrowing facilities of  €4,667 million. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. The main financial commitments of 2020 include long-term debt maturities of approximately €3.2 billion and short-term debt of  €2.45 billion, while our take-or-pay obligations under long-term gas contracts and other similar obligations amount to an estimated €8 billion at our budget scenario.
The effects of the recent trends in the oil market on the Group’s results of operations, liquidity and assets are currently under evaluation by management. This assessment implies the oil price scenario update and the management’s actions to counteract the changed environment, the effects of which, currently not yet determinable, will be accounted for in future reporting periods.
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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) 2019 | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub - Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | America | ​ | ​ | Australia and Oceania | ​ | ​ | Total | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proved property | ​ | ​ | ​ | ​ | 17,643 | ​ | ​ | ​ | ​ | ​ | 6,747 | ​ | ​ | ​ | ​ | ​ | 15,512 | ​ | ​ | ​ | ​ | ​ | 20,691 | ​ | ​ | ​ | ​ | ​ | 43,272 | ​ | ​ | ​ | ​ | ​ | 12,118 | ​ | ​ | ​ | ​ | ​ | 11,434 | ​ | ​ | ​ | ​ | ​ | 15,912 | ​ | ​ | ​ | ​ | ​ | 1,360 | ​ | ​ | ​ | ​ | ​ | 144,689 | ​ | ​
Unproved property | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 323 | ​ | ​ | ​ | ​ | ​ | 502 | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​ | ​ | ​ | ​ | 2,361 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | 1,592 | ​ | ​ | ​ | ​ | ​ | 979 | ​ | ​ | ​ | ​ | ​ | 194 | ​ | ​ | ​ | ​ | ​ | 6,014 | ​ | ​
Support equipment and facilities | ​ | ​ | ​ | ​ | 384 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 1,549 | ​ | ​ | ​ | ​ | ​ | 225 | ​ | ​ | ​ | ​ | ​ | 1,328 | ​ | ​ | ​ | ​ | ​ | 116 | ​ | ​ | ​ | ​ | ​ | 36 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 3,694 | ​ | ​
Incomplete wells and other | ​ | ​ | ​ | ​ | 635 | ​ | ​ | ​ | ​ | ​ | 103 | ​ | ​ | ​ | ​ | ​ | 1,362 | ​ | ​ | ​ | ​ | ​ | 359 | ​ | ​ | ​ | ​ | ​ | 2,541 | ​ | ​ | ​ | ​ | ​ | 1,165 | ​ | ​ | ​ | ​ | ​ | 1,006 | ​ | ​ | ​ | ​ | ​ | 457 | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​ | ​ | ​ | ​ | 7,671 | ​ | ​
Gross Capitalized Costs | ​ | ​ | ​ | ​ | 18,680 | ​ | ​ | ​ | ​ | ​ | 7,194 | ​ | ​ | ​ | ​ | ​ | 18,925 | ​ | ​ | ​ | ​ | ​ | 21,309 | ​ | ​ | ​ | ​ | ​ | 49,502 | ​ | ​ | ​ | ​ | ​ | 13,410 | ​ | ​ | ​ | ​ | ​ | 14,068 | ​ | ​ | ​ | ​ | ​ | 17,371 | ​ | ​ | ​ | ​ | ​ | 1,609 | ​ | ​ | ​ | ​ | ​ | 162,068 | ​ | ​
Accumulated depreciation, depletion and amortization | ​ | ​ | ​ | ​ | (14,604) | ​ | ​ | ​ | ​ | ​ | (5,778) | ​ | ​ | ​ | ​ | ​ | (12,802) | ​ | ​ | ​ | ​ | ​ | (12,879) | ​ | ​ | ​ | ​ | ​ | (33,237) | ​ | ​ | ​ | ​ | ​ | (2,652) | ​ | ​ | ​ | ​ | ​ | (9,100) | ​ | ​ | ​ | ​ | ​ | (13,465) | ​ | ​ | ​ | ​ | ​ | (754) | ​ | ​ | ​ | ​ | ​ | (105,271) | ​ | ​
Net Capitalized Costs consolidated subsidiaries﻿(a) | ​ | ​ | ​ | ​ | 4,076 | ​ | ​ | ​ | ​ | ​ | 1,416 | ​ | ​ | ​ | ​ | ​ | 6,123 | ​ | ​ | ​ | ​ | ​ | 8,430 | ​ | ​ | ​ | ​ | ​ | 16,265 | ​ | ​ | ​ | ​ | ​ | 10,758 | ​ | ​ | ​ | ​ | ​ | 4,968 | ​ | ​ | ​ | ​ | ​ | 3,906 | ​ | ​ | ​ | ​ | ​ | 855 | ​ | ​ | ​ | ​ | ​ | 56,797 | ​ | ​
Equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proved property | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11,223 | ​ | ​ | ​ | ​ | ​ | 71 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,511 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1,987 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14,794 | ​ | ​
Unproved property | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,260 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,271 | ​ | ​
Support equipment and facilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 34 | ​ | ​
Incomplete wells and other | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 945 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 229 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,215 | ​ | ​
Gross Capitalized Costs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14,447 | ​ | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,526 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 2,223 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 18,314 | ​ | ​
Accumulated depreciation, depletion and amortization | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5,287) | ​ | ​ | ​ | ​ | ​ | (61) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (323) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (20) | ​ | ​ | ​ | ​ | ​ | (1,124) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6,815) | ​ | ​
Net Capitalized Costs equity-accounted entities ﻿(a)(c) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 9,160 | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,203 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 1,099 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11,499 | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proved property | ​ | ​ | ​ | ​ | 16,569 | ​ | ​ | ​ | ​ | ​ | 6,236 | ​ | ​ | ​ | ​ | ​ | 14,140 | ​ | ​ | ​ | ​ | ​ | 17,474 | ​ | ​ | ​ | ​ | ​ | 40,607 | ​ | ​ | ​ | ​ | ​ | 11,240 | ​ | ​ | ​ | ​ | ​ | 12,711 | ​ | ​ | ​ | ​ | ​ | 15,347 | ​ | ​ | ​ | ​ | ​ | 1,967 | ​ | ​ | ​ | ​ | ​ | 136,291 | ​ | ​
Unproved property | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 332 | ​ | ​ | ​ | ​ | ​ | 456 | ​ | ​ | ​ | ​ | ​ | 56 | ​ | ​ | ​ | ​ | ​ | 2,311 | ​ | ​ | ​ | ​ | ​ | 3 | ​ | ​ | ​ | ​ | ​ | 1,530 | ​ | ​ | ​ | ​ | ​ | 861 | ​ | ​ | ​ | ​ | ​ | 193 | ​ | ​ | ​ | ​ | ​ | 5,760 | ​ | ​
Support equipment and facilities | ​ | ​ | ​ | ​ | 369 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 1,516 | ​ | ​ | ​ | ​ | ​ | 208 | ​ | ​ | ​ | ​ | ​ | 1,281 | ​ | ​ | ​ | ​ | ​ | 108 | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | 3,605 | ​ | ​
Incomplete wells and other | ​ | ​ | ​ | ​ | 653 | ​ | ​ | ​ | ​ | ​ | 103 | ​ | ​ | ​ | ​ | ​ | 1,554 | ​ | ​ | ​ | ​ | ​ | 1,504 | ​ | ​ | ​ | ​ | ​ | 2,307 | ​ | ​ | ​ | ​ | ​ | 1,382 | ​ | ​ | ​ | ​ | ​ | 562 | ​ | ​ | ​ | ​ | ​ | 595 | ​ | ​ | ​ | ​ | ​ | 127 | ​ | ​ | ​ | ​ | ​ | 8,787 | ​ | ​
Gross Capitalized Costs | ​ | ​ | ​ | ​ | 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 | ​ | ​ | ​ | ​ | (13,717) | ​ | ​ | ​ | ​ | ​ | (5,355) | ​ | ​ | ​ | ​ | ​ | (11,741) | ​ | ​ | ​ | ​ | ​ | (11,722) | ​ | ​ | ​ | ​ | ​ | (29,727) | ​ | ​ | ​ | ​ | ​ | (2,175) | ​ | ​ | ​ | ​ | ​ | (10,460) | ​ | ​ | ​ | ​ | ​ | (13,443) | ​ | ​ | ​ | ​ | ​ | (1,265) | ​ | ​ | ​ | ​ | ​ | (99,605) | ​ | ​
Net Capitalized Costs consolidated subsidiaries﻿(a) | ​ | ​ | ​ | ​ | 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 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 9,102 | ​ | ​ | ​ | ​ | ​ | 58 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,481 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1,912 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12,555 | ​ | ​
Unproved property | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,045 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,056 | ​ | ​
Support equipment and facilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 38 | ​ | ​
Incomplete wells and other | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 364 | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 10 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 19 | ​ | ​ | ​ | ​ | ​ | 224 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 627 | ​ | ​
Gross Capitalized Costs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 10,536 | ​ | ​ | ​ | ​ | ​ | 74 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,491 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | 2,143 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14,276 | ​ | ​
Accumulated depreciation, depletion and amortization | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (4,543) | ​ | ​ | ​ | ​ | ​ | (54) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (266) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | (1,052) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5,934) | ​ | ​
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 €878 million in 2019 and €831 million in 2018 for the consolidates subsidiaries and €166 million in 2019 and €180 million in 2018 for equity-accounted entities.
​
(b)
Includes Vår Energi AS asset fair value.
​
(c)
Includes allocation at fair value of the assets purchased by Vår Energi AS.
​
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Costs incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(€ million) 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 €2,069 million in 2019, negative for €517 million in 2018, asset for €355 million in 2017.
​
(b)
Includes the abandonment costs of the assets for €838 million in 2019, negative €22 million in 2018, negative for €23 million in 2017.
​
(c)
Includes allocation at fair value of the assets purchased by Vår Energi AS.
​
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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. Results of operations from oil and gas producing activities by geographical area consist of the following:

(€ million) 2019 | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub - Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | America | ​ | ​ | Australia and Oceania | ​ | ​ | Total | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- sales to consolidated entities | ​ | ​ | ​ | ​ | 1,493 | ​ | ​ | ​ | ​ | ​ | 618 | ​ | ​ | ​ | ​ | ​ | 1,081 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4,576 | ​ | ​ | ​ | ​ | ​ | 1,195 | ​ | ​ | ​ | ​ | ​ | 2,367 | ​ | ​ | ​ | ​ | ​ | 825 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 12,160 | ​ | ​
- sales to third parties | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | 4,084 | ​ | ​ | ​ | ​ | ​ | 3,715 | ​ | ​ | ​ | ​ | ​ | 944 | ​ | ​ | ​ | ​ | ​ | 766 | ​ | ​ | ​ | ​ | ​ | 149 | ​ | ​ | ​ | ​ | ​ | 180 | ​ | ​ | ​ | ​ | ​ | 227 | ​ | ​ | ​ | ​ | ​ | 10,095 | ​ | ​
Total revenues | ​ | ​ | ​ | ​ | 1,493 | ​ | ​ | ​ | ​ | ​ | 648 | ​ | ​ | ​ | ​ | ​ | 5,165 | ​ | ​ | ​ | ​ | ​ | 3,715 | ​ | ​ | ​ | ​ | ​ | 5,520 | ​ | ​ | ​ | ​ | ​ | 1,961 | ​ | ​ | ​ | ​ | ​ | 2,516 | ​ | ​ | ​ | ​ | ​ | 1,005 | ​ | ​ | ​ | ​ | ​ | 232 | ​ | ​ | ​ | ​ | ​ | 22,255 | ​ | ​
Production costs | ​ | ​ | ​ | ​ | (391) | ​ | ​ | ​ | ​ | ​ | (181) | ​ | ​ | ​ | ​ | ​ | (520) | ​ | ​ | ​ | ​ | ​ | (330) | ​ | ​ | ​ | ​ | ​ | (847) | ​ | ​ | ​ | ​ | ​ | (255) | ​ | ​ | ​ | ​ | ​ | (256) | ​ | ​ | ​ | ​ | ​ | (273) | ​ | ​ | ​ | ​ | ​ | (43) | ​ | ​ | ​ | ​ | ​ | (3,096) | ​ | ​
Transportation costs | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | (60) | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​ | ​ | ​ | ​ | (39) | ​ | ​ | ​ | ​ | ​ | (158) | ​ | ​ | ​ | ​ | ​ | (4) | ​ | ​ | ​ | ​ | ​ | (15) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (322) | ​ | ​
Production taxes | ​ | ​ | ​ | ​ | (183) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (263) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (483) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (252) | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | ​ | ​ | ​ | (6) | ​ | ​ | ​ | ​ | ​ | (1,194) | ​ | ​
Exploration expenses | ​ | ​ | ​ | ​ | (25) | ​ | ​ | ​ | ​ | ​ | (51) | ​ | ​ | ​ | ​ | ​ | (30) | ​ | ​ | ​ | ​ | ​ | (10) | ​ | ​ | ​ | ​ | ​ | (90) | ​ | ​ | ​ | ​ | ​ | (39) | ​ | ​ | ​ | ​ | ​ | (170) | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | (43) | ​ | ​ | ​ | ​ | ​ | (489) | ​ | ​
D.D. & A. and Provision for abandonment﻿(a) | ​ | ​ | ​ | ​ | (944) | ​ | ​ | ​ | ​ | ​ | (201) | ​ | ​ | ​ | ​ | ​ | (839) | ​ | ​ | ​ | ​ | ​ | (978) | ​ | ​ | ​ | ​ | ​ | (3,060) | ​ | ​ | ​ | ​ | ​ | (444) | ​ | ​ | ​ | ​ | ​ | (820) | ​ | ​ | ​ | ​ | ​ | (607) | ​ | ​ | ​ | ​ | ​ | (97) | ​ | ​ | ​ | ​ | ​ | (7,990) | ​ | ​
Other income (expenses) | ​ | ​ | ​ | ​ | (337) | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | (452) | ​ | ​ | ​ | ​ | ​ | (433) | ​ | ​ | ​ | ​ | ​ | (502) | ​ | ​ | ​ | ​ | ​ | (71) | ​ | ​ | ​ | ​ | ​ | (76) | ​ | ​ | ​ | ​ | ​ | (86) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (1,974) | ​ | ​
Pretax income from producing activities | ​ | ​ | ​ | ​ | (392) | ​ | ​ | ​ | ​ | ​ | 168 | ​ | ​ | ​ | ​ | ​ | 3,001 | ​ | ​ | ​ | ​ | ​ | 1,954 | ​ | ​ | ​ | ​ | ​ | 499 | ​ | ​ | ​ | ​ | ​ | 994 | ​ | ​ | ​ | ​ | ​ | 938 | ​ | ​ | ​ | ​ | ​ | (14) | ​ | ​ | ​ | ​ | ​ | 42 | ​ | ​ | ​ | ​ | ​ | 7,190 | ​ | ​
Income taxes | ​ | ​ | ​ | ​ | 148 | ​ | ​ | ​ | ​ | ​ | (11) | ​ | ​ | ​ | ​ | ​ | (2,561) | ​ | ​ | ​ | ​ | ​ | (839) | ​ | ​ | ​ | ​ | ​ | (268) | ​ | ​ | ​ | ​ | ​ | (326) | ​ | ​ | ​ | ​ | ​ | (719) | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​ | ​ | ​ | ​ | (31) | ​ | ​ | ​ | ​ | ​ | (4,612) | ​ | ​
Results of operations from E&P activities of consolidated subsidiaries﻿(b) | ​ | ​ | ​ | ​ | (244) | ​ | ​ | ​ | ​ | ​ | 157 | ​ | ​ | ​ | ​ | ​ | 440 | ​ | ​ | ​ | ​ | ​ | 1,115 | ​ | ​ | ​ | ​ | ​ | 231 | ​ | ​ | ​ | ​ | ​ | 668 | ​ | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | 2,578 | ​ | ​
Equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- sales to consolidated entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,080 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,080 | ​ | ​
- sales to third parties | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 677 | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 207 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 315 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,214 | ​ | ​
Total revenues | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,757 | ​ | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 207 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 315 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,294 | ​ | ​
Production costs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (336) | ​ | ​ | ​ | ​ | ​ | (8) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (24) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (25) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (393) | ​ | ​
Transportation costs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (84) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (11) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (96) | ​ | ​
Production taxes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (81) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (90) | ​ | ​
Exploration expenses | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (47) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (47) | ​ | ​
D.D. & A. and Provision for abandonment | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (722) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (70) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (51) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (844) | ​ | ​
Other income (expenses) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (237) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | (133) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (402) | ​ | ​
Pretax income from producing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 331 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 67 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 422 | ​ | ​
Income taxes | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (179) | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (54) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (235) | ​ | ​
Results of operations from E&P activities of equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 152 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 67 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | (29) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 187 | ​ | ​

​
(a)
Includes asset net impairment amounting to €1,217 million
​
(b)
Results of operations exclude revenues, DD&A and income taxes associated with 3,8 million boe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause. The price collected by the buyer has been recognized as revenues in the segment information of the E&P sector prepared in accordance with IFRS and DD&A and income taxes have been accrued accordingly, because the Group performance obligation under the contract has been fulfilled and it is very likely that the buyer will not redeem its contractual right to lift within the contractual terms.
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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
​
F-150

TABLE OF CONTENTS

(€ 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
​
F-151

TABLE OF CONTENTS
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 geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
In 2019, the average price for the marker Brent crude oil was $63 per barrel.
Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Eni has its proved reserves audited on a rotational basis by independent oil engineering companies 39. The description of qualifications of the person primarily responsible of the reserves audit is included in the third party audit report4 0.
In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.
In 2019, Ryder Scott Company, DeGolyer and MacNaughton provided an independent evaluation of about 31% of Eni’s total proved reserves as of December 31, 20194 1, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.
In the three-year period from 2017 to 2019, 86% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2019, the principal property not subjected to independent evaluation in the last three years 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 57%, 61% and 60% of total proved reserves as of December 31, 2019, 2018 and 2017, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves associated with such contracts represented 3%, 3% and 4% of total proved reserves on an oil-equivalent basis as of December 31, 2019, 2018 and 2017, respectively.
​
39
From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018 and independent evaluation was provided also by Societé Generale de Surveillance (SGS).
​
4 0
See “Item 19 – Exhibits”.
​
4 1
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 4%, 4% and 1.6% of total proved reserves as of December 31, 2019, 2018 and 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.
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, 2019, 2018 and 2017.
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 company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
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2018 | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub - Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | America | ​ | ​ | Australia and Oceania | ​ | ​ | Total | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves at December 31, 2017 | ​ | ​ | ​ | ​ | 215 | ​ | ​ | ​ | ​ | ​ | 360 | ​ | ​ | ​ | ​ | ​ | 476 | ​ | ​ | ​ | ​ | ​ | 280 | ​ | ​ | ​ | ​ | ​ | 764 | ​ | ​ | ​ | ​ | ​ | 766 | ​ | ​ | ​ | ​ | ​ | 232 | ​ | ​ | ​ | ​ | ​ | 162 | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | 3,262 | ​ | ​
of which: developed | ​ | ​ | ​ | ​ | 169 | ​ | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | 306 | ​ | ​ | ​ | ​ | ​ | 203 | ​ | ​ | ​ | ​ | ​ | 546 | ​ | ​ | ​ | ​ | ​ | 547 | ​ | ​ | ​ | ​ | ​ | 81 | ​ | ​ | ​ | ​ | ​ | 144 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2,220 | ​ | ​
undeveloped | ​ | ​ | ​ | ​ | 46 | ​ | ​ | ​ | ​ | ​ | 141 | ​ | ​ | ​ | ​ | ​ | 170 | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​ | ​ | ​ | ​ | 218 | ​ | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | 151 | ​ | ​ | ​ | ​ | ​ | 18 | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | 1,042 | ​ | ​
Purchase of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 319 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 319 | ​ | ​
Revisions of Previous Estimates | ​ | ​ | ​ | ​ | 15 | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | 73 | ​ | ​ | ​ | ​ | ​ | 21 | ​ | ​ | ​ | ​ | ​ | 30 | ​ | ​ | ​ | ​ | ​ | (27) | ​ | ​ | ​ | ​ | ​ | (54) | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | 86 | ​ | ​
Improved Recovery | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​
Extensions and Discoveries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 13 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 100 | ​ | ​
Production | ​ | ​ | ​ | ​ | (22) | ​ | ​ | ​ | ​ | ​ | (40) | ​ | ​ | ​ | ​ | ​ | (56) | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​ | ​ | ​ | ​ | (89) | ​ | ​ | ​ | ​ | ​ | (35) | ​ | ​ | ​ | ​ | ​ | (28) | ​ | ​ | ​ | ​ | ​ | (19) | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | (318) | ​ | ​
Sales of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (278) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (279) | ​ | ​
Reserves at December 31, 2018 | ​ | ​ | ​ | ​ | 208 | ​ | ​ | ​ | ​ | ​ | 48 | ​ | ​ | ​ | ​ | ​ | 493 | ​ | ​ | ​ | ​ | ​ | 279 | ​ | ​ | ​ | ​ | ​ | 718 | ​ | ​ | ​ | ​ | ​ | 704 | ​ | ​ | ​ | ​ | ​ | 476 | ​ | ​ | ​ | ​ | ​ | 252 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 3,183 | ​ | ​
Equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves at December 31, 2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 136 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 160 | ​ | ​
of which: developed | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 43 | ​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 6 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 111 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 117 | ​ | ​
Purchase of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 297 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 297 | ​ | ​
Revisions of Previous Estimates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (96) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (95) | ​ | ​
Improved Recovery | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Extensions and Discoveries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (3) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (5) | ​ | ​
Sales of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves at December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 297 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 12 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 357 | ​ | ​
Reserves at December 31, 2018 | ​ | ​ | ​ | ​ | 208 | ​ | ​ | ​ | ​ | ​ | 345 | ​ | ​ | ​ | ​ | ​ | 504 | ​ | ​ | ​ | ​ | ​ | 279 | ​ | ​ | ​ | ​ | ​ | 730 | ​ | ​ | ​ | ​ | ​ | 704 | ​ | ​ | ​ | ​ | ​ | 476 | ​ | ​ | ​ | ​ | ​ | 289 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 3,540 | ​ | ​
Developed | ​ | ​ | ​ | ​ | 156 | ​ | ​ | ​ | ​ | ​ | 198 | ​ | ​ | ​ | ​ | ​ | 328 | ​ | ​ | ​ | ​ | ​ | 153 | ​ | ​ | ​ | ​ | ​ | 559 | ​ | ​ | ​ | ​ | ​ | 587 | ​ | ​ | ​ | ​ | ​ | 252 | ​ | ​ | ​ | ​ | ​ | 175 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2,413 | ​ | ​
consolidated subsidiaries | ​ | ​ | ​ | ​ | 156 | ​ | ​ | ​ | ​ | ​ | 44 | ​ | ​ | ​ | ​ | ​ | 317 | ​ | ​ | ​ | ​ | ​ | 153 | ​ | ​ | ​ | ​ | ​ | 551 | ​ | ​ | ​ | ​ | ​ | 587 | ​ | ​ | ​ | ​ | ​ | 252 | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | 2,208 | ​ | ​
equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 154 | ​ | ​ | ​ | ​ | ​ | 11 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 8 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 32 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 205 | ​ | ​
Undeveloped | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | 147 | ​ | ​ | ​ | ​ | ​ | 176 | ​ | ​ | ​ | ​ | ​ | 126 | ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​ | ​ | ​ | ​ | 117 | ​ | ​ | ​ | ​ | ​ | 224 | ​ | ​ | ​ | ​ | ​ | 114 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,127 | ​ | ​
consolidated subsidiaries | ​ | ​ | ​ | ​ | 52 | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | 176 | ​ | ​ | ​ | ​ | ​ | 126 | ​ | ​ | ​ | ​ | ​ | 167 | ​ | ​ | ​ | ​ | ​ | 117 | ​ | ​ | ​ | ​ | ​ | 224 | ​ | ​ | ​ | ​ | ​ | 109 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 975 | ​ | ​
equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 4 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 5 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 152 | ​ | ​
​

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 | ​ | ​
​

F-154

TABLE OF CONTENTS
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 company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
​

2018 | ​ | ​ | Italy | ​ | ​ | Rest of Europe | ​ | ​ | North Africa | ​ | ​ | Egypt | ​ | ​ | Sub - Saharan Africa | ​ | ​ | Kazakhstan | ​ | ​ | Rest of Asia | ​ | ​ | America | ​ | ​ | Australia and Oceania | ​ | ​ | Total | ​
Consolidated subsidiaries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves at December 31, 2017 | ​ | ​ | ​ | ​ | 1,131 | ​ | ​ | ​ | ​ | ​ | 896 | ​ | ​ | ​ | ​ | ​ | 3,145 | ​ | ​ | ​ | ​ | ​ | 4,351 | ​ | ​ | ​ | ​ | ​ | 3,660 | ​ | ​ | ​ | ​ | ​ | 2,108 | ​ | ​ | ​ | ​ | ​ | 1,065 | ​ | ​ | ​ | ​ | ​ | 225 | ​ | ​ | ​ | ​ | ​ | 709 | ​ | ​ | ​ | ​ | ​ | 17,290 | ​ | ​
of which: developed | ​ | ​ | ​ | ​ | 987 | ​ | ​ | ​ | ​ | ​ | 771 | ​ | ​ | ​ | ​ | ​ | 1,233 | ​ | ​ | ​ | ​ | ​ | 1,421 | ​ | ​ | ​ | ​ | ​ | 1,693 | ​ | ​ | ​ | ​ | ​ | 1,878 | ​ | ​ | ​ | ​ | ​ | 862 | ​ | ​ | ​ | ​ | ​ | 171 | ​ | ​ | ​ | ​ | ​ | 519 | ​ | ​ | ​ | ​ | ​ | 9,535 | ​ | ​
undeveloped | ​ | ​ | ​ | ​ | 144 | ​ | ​ | ​ | ​ | ​ | 125 | ​ | ​ | ​ | ​ | ​ | 1,912 | ​ | ​ | ​ | ​ | ​ | 2,930 | ​ | ​ | ​ | ​ | ​ | 1,967 | ​ | ​ | ​ | ​ | ​ | 230 | ​ | ​ | ​ | ​ | ​ | 203 | ​ | ​ | ​ | ​ | ​ | 54 | ​ | ​ | ​ | ​ | ​ | 190 | ​ | ​ | ​ | ​ | ​ | 7,755 | ​ | ​
Purchase of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 69 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 69 | ​ | ​
Revisions of Previous Estimates | ​ | ​ | ​ | ​ | 138 | ​ | ​ | ​ | ​ | ​ | 50 | ​ | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | 2,238 | ​ | ​ | ​ | ​ | ​ | 23 | ​ | ​ | ​ | ​ | ​ | (22) | ​ | ​ | ​ | ​ | ​ | 81 | ​ | ​ | ​ | ​ | ​ | 45 | ​ | ​ | ​ | ​ | ​ | (16) | ​ | ​ | ​ | ​ | ​ | 2,756 | ​ | ​
Improved Recovery | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Extensions and Discoveries | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 7 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 205 | ​ | ​ | ​ | ​ | ​ | 76 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 374 | ​ | ​
Production | ​ | ​ | ​ | ​ | (156) | ​ | ​ | ​ | ​ | ​ | (162) | ​ | ​ | ​ | ​ | ​ | (474) | ​ | ​ | ​ | ​ | ​ | (445) | ​ | ​ | ​ | ​ | ​ | (184) | ​ | ​ | ​ | ​ | ​ | (97) | ​ | ​ | ​ | ​ | ​ | (201) | ​ | ​ | ​ | ​ | ​ | (43) | ​ | ​ | ​ | ​ | ​ | (42) | ​ | ​ | ​ | ​ | ​ | (1,804) | ​ | ​
Sales of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (464) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (869) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,361) | ​ | ​
Reserves at December 31, 2018 | ​ | ​ | ​ | ​ | 1,199 | ​ | ​ | ​ | ​ | ​ | 320 | ​ | ​ | ​ | ​ | ​ | 2,890 | ​ | ​ | ​ | ​ | ​ | 5,275 | ​ | ​ | ​ | ​ | ​ | 3,506 | ​ | ​ | ​ | ​ | ​ | 1,989 | ​ | ​ | ​ | ​ | ​ | 1,217 | ​ | ​ | ​ | ​ | ​ | 277 | ​ | ​ | ​ | ​ | ​ | 651 | ​ | ​ | ​ | ​ | ​ | 17,324 | ​ | ​
Equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves at December 31, 2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 349 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,819 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,182 | ​ | ​
of which: developed | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 83 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,819 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,916 | ​ | ​
undeveloped | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 266 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 266 | ​ | ​
Purchase of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 360 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 360 | ​ | ​
Revisions of Previous Estimates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (22) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (26) | ​ | ​
Improved Recovery | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Extensions and Discoveries | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (33) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (81) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (116) | ​ | ​
Sales of Minerals in Place | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves at December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 360 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 310 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,716 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,400 | ​ | ​
Reserves at December 31, 2018 | ​ | ​ | ​ | ​ | 1,199 | ​ | ​ | ​ | ​ | ​ | 680 | ​ | ​ | ​ | ​ | ​ | 2,904 | ​ | ​ | ​ | ​ | ​ | 5,275 | ​ | ​ | ​ | ​ | ​ | 3,816 | ​ | ​ | ​ | ​ | ​ | 1,989 | ​ | ​ | ​ | ​ | ​ | 1,217 | ​ | ​ | ​ | ​ | ​ | 1,993 | ​ | ​ | ​ | ​ | ​ | 651 | ​ | ​ | ​ | ​ | ​ | 19,724 | ​ | ​
Developed | ​ | ​ | ​ | ​ | 980 | ​ | ​ | ​ | ​ | ​ | 576 | ​ | ​ | ​ | ​ | ​ | 1,461 | ​ | ​ | ​ | ​ | ​ | 3,331 | ​ | ​ | ​ | ​ | ​ | 1,928 | ​ | ​ | ​ | ​ | ​ | 1,846 | ​ | ​ | ​ | ​ | ​ | 822 | ​ | ​ | ​ | ​ | ​ | 1,870 | ​ | ​ | ​ | ​ | ​ | 452 | ​ | ​ | ​ | ​ | ​ | 13,266 | ​ | ​
consolidated subsidiaries | ​ | ​ | ​ | ​ | 980 | ​ | ​ | ​ | ​ | ​ | 300 | ​ | ​ | ​ | ​ | ​ | 1,447 | ​ | ​ | ​ | ​ | ​ | 3,331 | ​ | ​ | ​ | ​ | ​ | 1,871 | ​ | ​ | ​ | ​ | ​ | 1,846 | ​ | ​ | ​ | ​ | ​ | 822 | ​ | ​ | ​ | ​ | ​ | 154 | ​ | ​ | ​ | ​ | ​ | 452 | ​ | ​ | ​ | ​ | ​ | 11,203 | ​ | ​
equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 276 | ​ | ​ | ​ | ​ | ​ | 14 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 57 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 1,716 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 2,063 | ​ | ​
Undeveloped | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | 104 | ​ | ​ | ​ | ​ | ​ | 1,443 | ​ | ​ | ​ | ​ | ​ | 1,944 | ​ | ​ | ​ | ​ | ​ | 1,888 | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | 395 | ​ | ​ | ​ | ​ | ​ | 123 | ​ | ​ | ​ | ​ | ​ | 199 | ​ | ​ | ​ | ​ | ​ | 6,458 | ​ | ​
consolidated subsidiaries | ​ | ​ | ​ | ​ | 219 | ​ | ​ | ​ | ​ | ​ | 20 | ​ | ​ | ​ | ​ | ​ | 1,443 | ​ | ​ | ​ | ​ | ​ | 1,944 | ​ | ​ | ​ | ​ | ​ | 1,635 | ​ | ​ | ​ | ​ | ​ | 143 | ​ | ​ | ​ | ​ | ​ | 395 | ​ | ​ | ​ | ​ | ​ | 123 | ​ | ​ | ​ | ​ | ​ | 199 | ​ | ​ | ​ | ​ | ​ | 6,121 | ​ | ​
equity-accounted entities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 84 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 253 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 337 | ​ | ​
​

F-155

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.
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The standardized measure of discounted future net cash flows by geographical area consists of the following:

(€ 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 | ​ | ​
​

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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, 2019, 2018 and 2017, are as follows:

(€ million) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
2019 | ​ | ​ | Consolidated subsidiaries | ​ | ​ | Equity- accounted entities | ​ | ​ | Total | ​
Standardized measure of discounted future net cash flows at December 31, 2018 | ​ | ​ | ​ | ​ | 52,411 | ​ | ​ | ​ | ​ | ​ | 5,241 | ​ | ​ | ​ | ​ | ​ | 57,652 | ​ | ​
Increase (Decrease): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
- sales, net of production costs | ​ | ​ | ​ | ​ | (18,236) | ​ | ​ | ​ | ​ | ​ | (1,675) | ​ | ​ | ​ | ​ | ​ | (19,911) | ​ | ​
- net changes in sales and transfer prices, net of production costs | ​ | ​ | ​ | ​ | (14,972) | ​ | ​ | ​ | ​ | ​ | (2,247) | ​ | ​ | ​ | ​ | ​ | (17,219) | ​ | ​
- extensions, discoveries and improved recovery, net of future production and development costs | ​ | ​ | ​ | ​ | 1,240 | ​ | ​ | ​ | ​ | ​ | 86 | ​ | ​ | ​ | ​ | ​ | 1,326 | ​ | ​
- changes in estimated future development and abandonment costs | ​ | ​ | ​ | ​ | (1,157) | ​ | ​ | ​ | ​ | ​ | (916) | ​ | ​ | ​ | ​ | ​ | (2,073) | ​ | ​
- development costs incurred during the period that reduced future development costs | ​ | ​ | ​ | ​ | 5,128 | ​ | ​ | ​ | ​ | ​ | 687 | ​ | ​ | ​ | ​ | ​ | 5,815 | ​ | ​
- revisions of quantity estimates | ​ | ​ | ​ | ​ | 5,573 | ​ | ​ | ​ | ​ | ​ | 1,377 | ​ | ​ | ​ | ​ | ​ | 6,950 | ​ | ​
- accretion of discount | ​ | ​ | ​ | ​ | 8,666 | ​ | ​ | ​ | ​ | ​ | 1,050 | ​ | ​ | ​ | ​ | ​ | 9,716 | ​ | ​
- net change in income taxes | ​ | ​ | ​ | ​ | 6,013 | ​ | ​ | ​ | ​ | ​ | (761) | ​ | ​ | ​ | ​ | ​ | 5,252 | ​ | ​
- purchase of reserves in-place | ​ | ​ | ​ | ​ | 260 | ​ | ​ | ​ | ​ | ​ | 2,579 | ​ | ​ | ​ | ​ | ​ | 2,839 | ​ | ​
- sale of reserves in-place(a) | ​ | ​ | ​ | ​ | (429) | ​ | ​ | ​ | ​ | ​ | (88) | ​ | ​ | ​ | ​ | ​ | (517) | ​ | ​
- changes in production rates (timing) and other | ​ | ​ | ​ | ​ | 990 | ​ | ​ | ​ | ​ | ​ | 77 | ​ | ​ | ​ | ​ | ​ | 1,067 | ​ | ​
Net increase (decrease) | ​ | ​ | ​ | ​ | (6,924) | ​ | ​ | ​ | ​ | ​ | 169 | ​ | ​ | ​ | ​ | ​ | (6,755) | ​ | ​
Standardized measure of discounted future net cash flows at December 31, 2019 | ​ | ​ | ​ | ​ | 45,487 | ​ | ​ | ​ | ​ | ​ | 5,410 | ​ | ​ | ​ | ​ | ​ | 50,897 | ​ | ​

​
(a)
Includes volume as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
​
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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 | ​ | ​

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SIGNATURES
The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: April 2, 2020
Eni SpA
/s/ MASSIMO MONDAZZI
Massimo Mondazzi
Title: Chief Financial Officer