ENI S.p.A.
Annual Report 2016

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form 20-F (Mark One) ☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 OR For the fiscal year ended December 31, 2016 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to 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 Commission file number: 1-14090 Eni SpA (Exact name of Registrant as specified in its charter) Republic of Italy (Jurisdiction of incorporation or organization) 1, piazzale Enrico Mattei - 00144 Roma - Italy (Address of principal executive offices) 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) Securities registered or to be registered pursuant to Section 12(b) of the Act. Title of each class Shares American Depositary Shares (Which represent the right to receive two Shares) Name of each exchange on which registered New York Stock Exchange* New York Stock Exchange * Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission. Securities registered or to be registered pursuant to Section 12(g) of the Act: None Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report. Ordinary shares 3,634,185,330 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 ☐ 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 18 Item 17 If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No ☑ ☐ TABLE OF CONTENTS Certain defined terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Presentation of financial and other information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Statements regarding competitive position . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Abbreviations and conversion table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART I Item 1. Item 2. Item 3. Item 4. Item 4A. Item 5. Item 6. Item 7. Item 8. Item 9. Item 10. Item 11. Item 12. Item 12A. Item 12B. Item 12C. Item 12D. PART II Item 13. Item 14. Item 15. Item 16. Item 16A. Item 16B. Item 16C. Item 16D. Item 16E. Item 16F. Item 16G. Item 16H. PART III Item 17. Item 18. Item 19. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS . . . . . . . . . . . . . . . . . . . . . . . . . . OFFER STATISTICS AND EXPECTED TIMETABLE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . KEY INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Operating Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exchange Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . INFORMATION ON THE COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . History and development of the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BUSINESS OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exploration & Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas & Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Refining & Marketing & Chemicals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate and Other activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Research and development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Environmental matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Regulation of Eni’s businesses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Organizational structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . OPERATING AND FINANCIAL REVIEW AND PROSPECTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Executive summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Critical accounting estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014-2016 Group results of operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liquidity and capital resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Recent developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Management’s expectations of operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Directors and Senior Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Board practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Share ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Major Shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Related party transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FINANCIAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements and other financial information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Significant changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . THE OFFER AND THE LISTING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Offer and listing details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ADDITIONAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Memorandum and Articles of Association . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Material contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exchange controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Taxation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Documents on display . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . . . . . . . . . . . . . . DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Warrants and rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . American Depositary Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . [RESERVED] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Board of Statutory Auditors financial expert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Code of Ethics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Principal accountant fees and services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exemptions from the Listing Standards for Audit Committees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchases of equity securities by the issuer and affiliated purchasers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in Registrant’s Certifying Accountant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mine safety disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . EXHIBITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page ii ii ii iii vii 1 1 1 1 4 5 6 27 27 32 32 62 67 75 75 77 78 86 92 92 92 93 93 98 98 111 118 118 128 128 137 152 163 164 165 165 165 166 166 166 167 167 168 169 169 176 177 177 182 182 185 185 185 185 185 188 188 188 189 189 189 189 191 191 191 191 194 195 195 195 i Certain disclosures contained herein including, without limitation, 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 engaged 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. ii GLOSSARY A glossary of oil and gas terms is available on Eni’s web page at the address eni.com. Below is a selection of the most frequently used terms. 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 Net borrowings TSR (Total Shareholder Return) Business terms AEEGSI (Authority for Electricity Gas and Water) formerly AEEG (Authority for Electricity and Gas) net between A non-GAAP measure of the Company’s financial condition, calculated as the including ratio and non-controlling interest. For a discussion of management’s view of the this measure and its reconciliation with the most directly usefulness of comparable GAAP measure, “Ratio of total debt to total shareholders’s equity (including non-controlling interest)” see “Item 5 – Financial Condition”. shareholders’ borrowings equity, 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”. 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. The Regulatory Authority for Electricity Gas and Water 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. 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 BOE Concession contracts Condensates Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons. 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”). regulating currently applied mainly in Western countries Contracts relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive right on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state. Condensates 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. iii Contingent resources Conversion capacity Conversion index Deep waters Development 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. 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. 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. Waters deeper than 200 meters. 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. EPC EPCI Exploration FPSO FSO Infilling wells LNG LPG Margin Mineral Potential Mineral Storage Engineering, Procurement and Construction. Engineering, Procurement, Construction and Installation. Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling. Floating Production Storage and Offloading System. Floating Storage and Offloading System. 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. 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. Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression. 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 the trading environment and are, to a certain extent, a gauge of industry profitability. reflect (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 location in on the development of new technologies, or for accumulations yet evaluation of known to be developed or where accumulations is still at an early stage. their 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 plants. Propane, that were separation normal-butane and isobutane, previously defined as natural gasoline, are natural gas liquids. isopentane and pentane plus, equipment treatment natural gas or Network Code A code containing norms and regulations for access to, management and operation of natural gas pipelines. iv Over/Under lifting Possible reserves Probable reserves 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. Possible reserves are those additional reserves that are less certain to be recovered than 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) Proved reserves Reserves Contract in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating 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. to extract 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 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 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. v 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. Ship-or-pay Strategic Storage Take-or-pay Title Transfer Facility Upstream/Downstream 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. According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system. 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. is a virtual The Title Transfer Facility, more commonly known as TTF, 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. 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. vi ABBREVIATIONS mmCF = million cubic feet BCF = billion cubic feet mmCM = million cubic meters BCM BOE = billion cubic meters = barrel of oil equivalent KBOE = thousand barrel of oil equivalent mmtonnes = million tonnes MW GWh TWh /d /y = megawatt = gigawatthour = terawatthour = per day = per year mmBOE = million barrel of oil equivalent E&P = the Exploration & Production = billion barrel of oil equivalent segment BBOE BBL KBBL = barrels = thousand barrels mmBBL = million barrels BBBL = billion barrels ktonnes = thousand tonnes G&P = the Gas & Power segment R&M & C = the Refining & Marketing and Chemicals segment E&C = the Engineering & Construction segment 1 acre 1 barrel 1 BOE CONVERSION TABLE = 0.405 hectares = 42 U.S. gallons = 1 barrel of crude oil = 5,458 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 1 kilometer 1 short ton 1 long ton 1 tonne of oil equivalent = approximately 0.62 miles = 0.907 tonnes = 1.016 tonnes = 1 metric ton 1 tonne of crude oil = 1 metric ton of crude oil = 2,000 pounds = 2,240 pounds = 1,000 kilograms = approximately 2,205 pounds = approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees) vii Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS NOT APPLICABLE PART I 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, 2012, 2013, 2014, 2015 and 2016. Effective January 1, 2016, management elected to modify the accounting method to recognize exploration expenses and adopted the successful-effort-method (SEM). SEM is largely adopted by oil&gas companies, to which Eni is increasingly comparable given the recent re-focalization of the Group activities on its core upstream business. Under the SEM, geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an unproved tangible asset until the drilling of the well is complete and the results have been evaluated. If commercially viable quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an unproved asset. If it is determined that development will not occur then the costs are recorded as expenses. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons are initially capitalized as an unproved tangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to proved property. In accordance to IAS 8 “Accounting policies, Changes in accounting estimates and Errors”, the retrospective application of the SEM has required adjustment of the opening balance of the retained earnings and other comparative balance sheet items as of January 1, 2014. Specifically, the opening balance of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and the retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items. Please refer to Note 1 to the Consolidated Financial Statements for further information. On January 22, 2016, Eni Group divested its Engineering & Construction segment (“E&C”), following the closing of the sale of a 12.503% stake in Saipem SpA to an Italian state-owned agency, CDP Equity SpA, and the concurrent efficacy of a shareholder agreement between Eni and CDP Equity SpA, which established the joint control of the two parties over the target entity. Those transactions triggered the loss of control of Eni over Saipem, which was the parent company of the E&C segment. Therefore, effective January 1, 2016, Saipem revenues and expenses, assets and liabilities have been derecognized. The retained interest of 30.55% in Saipem has been recognized as an investment in an equity-accounted joint venture. The initial carrying amount of the investment was aligned to the share price at the closing date of the transaction (€4.2 per share, equal to €564 million) recognizing a loss through profit of €441 million, as part of the result of the discontinued operations of 2016. Considering the pro-quota share capital increase of Saipem subscribed by Eni for a cash out of €1,069 million, the initial carrying amount of the investment amounted to €1,614 million. At the end of February 2016, Saipem reimbursed intercompany loans owed to Eni (€5,818 million as of December 31, 2015) by using the proceeds from the share capital increase and new credit facilities from third-party financing institutions. Eni’s Chemical business, managed by the wholly-owned subsidiary Versalis, has been reclassified as continuing operations, with retrospectively effects on the comparative information. In accordance with the IFRS 5, Versalis has ceased to be classified as discontinued operations due to termination of 1 negotiations with US-based SK Capital hedge fund, who had shown an interest in acquiring a majority stake in Versalis. In Eni’s Annual Report on Form 20-F 2015 this business was reported as discontinued operations. Consequently, Eni’s management reinstated the criteria of the continuing use to evaluate Versalis by aligning its book value to the recoverable amount, calculated as the higher of fair value less cost to sell and value-in-use. Conversely, under IFRS 5 Versalis was measured at the lower of its carrying amount and fair value less cost to sell. This change in the accounting of Versalis marginally affected the opening balance of Eni’s consolidated net assets (an increase of €294 million) and was neutral on the Group’s net financial position. The results of Versalis have been aggregated with those of R&M, in the reportable segment “R&M and Chemicals” because the two segments have similar economic characteristics. This has been retrospectively applied to the selected historical financial data for all comparative periods. All such data should be read in connection with the Consolidated Financial Statements and the related notes thereto included in Item 18. Year ended December 31, 2012 2013 2014 2015 2016 (€ million except data per share and per ADR) CONSOLIDATED PROFIT STATEMENT DATA Net sales from continuing operations ................................. 115,419 Operating profit (loss) by segment from continuing operations 104,117 98,218 72,286 55,762 Exploration & Production ........................................ Gas & Power ......................................................... Refining & Marketing and Chemicals .......................... Corporate and Other activities .................................. Impact of unrealized intragroup profit elimination and other consolidation adjustments (1) ............................. Operating profit (loss) from continuing operations ................ Net profit (loss) attributable to Eni from continuing operations Net profit (loss) attributable to Eni from discontinued operations ................................................................... Net profit (loss) attributable to Eni .................................... Data per ordinary share (euro) (2) Operating profit (loss): – basic ....................................................................... – diluted ..................................................................... Net profit (loss) attributable to Eni basic and diluted from continuing operations .................................................... Net profit (loss) attributable to Eni basic and diluted from discontinued operations .................................................. Net profit (loss) attributable to Eni basic and diluted ............. Data per ADR ($) (2) (3) Operating profit (loss): – basic ....................................................................... – diluted ..................................................................... Net profit (loss) attributable to Eni basic and diluted from continuing operations .................................................... Net profit (loss) attributable to Eni basic and diluted from discontinued operations .................................................. Net profit (loss) attributable to Eni basic and diluted ............. 19,190 (3,129) (1,941) (641) 2,094 15,573 4,870 3,520 8,390 15,349 (2,923) (2,261) (736) 928 10,357 5,808 10,727 64 (2,811) (518) 1,503 8,965 1,720 (488) 5,320 (417) 1,303 (959) (1,258) (1,567) (497) 1,205 (3,076) (7,952) (826) (8,778) 2,567 (391) 723 (681) (61) 2,157 (1,051) (413) (1,464) 4.30 4.30 1.34 0.97 2.32 11.05 11.05 3.45 2.50 5.95 2.86 2.86 1.60 2.48 2.48 0.48 (0.85) (0.85) 0.60 0.60 (2.21) (0.29) (0.13) 1.47 (0.12) 0.36 (0.23) (2.44) (0.12) (0.41) 7.59 7.59 4.26 6.59 6.59 1.27 (1.90) (1.90) 1.33 1.33 (4.90) (0.65) (0.36) 3.90 (0.31) 0.96 (0.51) (5.41) (0.25) (0.90) (1) (2) (3) This item pertains to intragroup sales of commodities and capital goods recorded in the assets of the purchasing business segment as of the end of the reporting period. 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 2016 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on April 13, 2017. 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/US$ average recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2012 through 2014 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 2016 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 (euro 0.80 per ADR) at the Noon Buying Rate recorded on the payment date on September 15, 2016, while the balance of euro 0.80 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2016. The balance dividend for 2016 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on April 26, 2017 to holders of Eni shares, being the ex-dividend date April 24, 2017, while ADRs holders will be paid on May 8, 2017. 2 As of December 31, 2012 2013 2014 2015 2016 (€ million except data per share and per ADR) CONSOLIDATED BALANCE SHEET DATA Total assets ................................................................. 144,208 24,192 Short-term and long-term debt ......................................... 4,005 Capital stock issued ....................................................... 3,357 Minority interest .......................................................... 62,066 Shareholders’ equity - Eni share ........................................ Capital expenditures from continuing operations .................. 12,452 Weighted average number of ordinary shares outstanding (fully diluted - shares million) .................................................. Dividend per share (euro) (1) ............................................ Dividend per ADR ($) (1) (2) ............................................ 3,623 1.08 2.82 142,426 25,560 4,005 2,842 61,211 11,221 3,623 1.10 2.99 150,366 25,891 4,005 2,455 63,186 11,178 3,610 1.12 2.65 139,001 27,793 4,005 1,916 55,493 10,741 3,601 0.80 1.77 124,545 27,239 4,005 49 53,037 9,180 3,601 0.80 1.77 (1) (2) Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2016 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on April 13, 2017. Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2012 through 2014 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 2016 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 (euro 0,80 per ADR) at the Noon Buying Rate recorded on the payment date on September 15, 2016, while the balance of euro 0.80 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2016. The balance dividend for 2016 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on April 26, 2017 to holders of Eni shares, being the ex-dividend date April 24, 2017 while ADRs holders will be paid on May 8, 2017. 3 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, 2012, 2013, 2014, 2015 and 2016. Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL) ........................................ of which developed ............................................... Proved reserves of liquids of equity-accounted entities at period end (mmBBL) ........................................ of which developed ............................................... Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) ............................. of which developed ............................................... Proved reserves of natural gas of equity-accounted entities at period end (BCF) ................................... of which developed ............................................... Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end ....................... of which developed ............................................... Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end ............................. of which developed ............................................... Average daily production of liquids (KBBL/d) (1) ...................................................... Average daily production of natural gas available for sale (mmCF/d) (1) ................................................ Average daily production of hydrocarbons available for sale (KBOE/d) (1)(4) .............................................. Hydrocarbon production sold (mmBOE) .................. Oil and gas production costs per BOE (2) ................... Profit per barrel of oil equivalent (3) ......................... Year ended December 31, 2012 2013 2014 2015 2016 3,084 1,762 266 44 3,079 1,831 148 35 3,077 1,847 149 46 3,372 2,100 187 48 3,230 2,190 168 43 14,190 8,965 14,442 8,542 14,808 8,342 14,302 8,899 18,462 9,244 6,767 424 5,667 3,394 1,499 122 882 4,118 1,631 598.7 10.82 17.33 3,726 34 5,708 3,387 827 40 833 3,868 1,537 555.3 12.19 16.19 3,737 120 5,772 3,366 830 67 828 3,782 1,517 549.5 12.00 9.86 3,993 1,402 5,975 3,720 915 303 908 4,284 1,688 614.1 9.18 (3.83) 3,871 1,905 6,613 3,884 877 391 878 4,329 1,671 608.6 7.79 1.98 (1) (2) (3) (4) Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (383, 451, 442, 397 and 478 mmCF/d in 2012, 2013, 2014, 2015 and 2016, respectively). Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment including also royalties) 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”. 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. From January 1, 2016, as part of a regular reviewing procedure, Eni has updated the conversion rate of gas to 5,458 cubic feet of gas equals 1 barrel of oil (it was 5,492 cubic feet of gas per barrel in previous reporting periods). This update reflected changes in Eni’s gas properties that took place in the last three years and was assessed by collecting data on the heating power of gas in all Eni’s gas fields currently on stream. The effect of this update on production expressed in boe for the full year 2016 was 5 kboe/d. Other per-boe indicators were only marginally affected by the update (e.g. realization prices, costs per boe) and negligible was the impact on depletion charges. Other oil companies may use different conversion rates. 4 Selected Operating Information continued Sales of natural gas to third parties (1) ...................................... Natural gas consumed by Eni (1) ............................................. Sales of natural gas of affiliates (Eni’s share) (1) ......................... Total sales and own consumption of natural gas of the Gas & Power segment (1) ................................................................ E&P natural gas sales in Europe and in the Gulf of Mexico (1) ....... Worldwide natural gas sales (1) ................................................. Electricity sold (2) ................................................................. Refinery throughputs (3) ........................................................ Balanced capacity of wholly-owned refineries (4) ......................... Retail sales (in Italy and rest of Europe) (3) ................................. Number of service stations at period end (in Italy and rest of Europe) ................................................... Chemical production (3) ......................................................... Average throughput per service station (in Italy and rest of Europe) (5) ................................................ Employees at period end (number) (6) ....................................... Year ended December 31, 2012 2013 2014 2015 2016 77.87 6.43 8.29 92.59 2.73 95.32 42.58 30.01 574 10.87 6,384 6.09 77.67 5.93 6.96 90.56 2.61 93.17 35.05 27.38 574 9.69 6,386 5.82 76.11 5.62 4.38 86.11 3.06 89.17 33.58 25.03 404 9.21 6,220 5.28 79.06 5.88 2.78 87.72 3.16 90.88 34.88 26.41 388 8.89 5,846 5.70 77.24 6.10 2.97 86.31 2.62 88.93 37.05 24.52 388 8.59 5,622 5.65 2,064 1,828 36,018 36,678 1,725 34,846 1,754 34,196 1,742 33,536 (1) (2) (3) (4) (5) (6) Expressed in BCM. Expressed in TWh. Expressed in mmtonnes. Expressed in KBBL/d. Expressed in thousand liters per day. Realting to continuing operations for all periods presented. Exchange Rates The following tables set forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board). Year ended December 31, 2012 ....................................................................................... 2013 ....................................................................................... 2014 ....................................................................................... 2015 ....................................................................................... 2016 ....................................................................................... (1) Average of the Noon Buying Rates for the last business day of each month in the period. High Low Average (1) (U.S. dollars per €) 1.35 1.38 1.39 1.20 1.15 1.21 1.28 1.21 1.05 1.04 1.29 1.33 1.33 1.11 1.10 At period end 1.32 1.38 1.21 1.09 1.06 5 September 2016 ..................................................................................... October 2016 ......................................................................................... November 2016 ..................................................................................... December 2016 ...................................................................................... January 2017 ......................................................................................... February 2017 ....................................................................................... High Low At period end (U.S. dollars per euro) 1.12 1.09 1.06 1.04 1.04 1.05 1.13 1.12 1.11 1.08 1.08 1.08 1.12 1.10 1.06 1.06 1.08 1.06 Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on March 10, 2017 was $1.07 per €1.00. Risk factors The risks described below may have a material effect on our operational and financial performance. We invite our investors to consider these risks carefully. Eni’s operating results and cash flow and future rate of growth are exposed to the effects of fluctuating prices of crude oil, natural gas, oil products and chemicals Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni’s control. These factors include among other things: • • • • • • • • • • global and regional dynamics of oil and gas supply and demand. From mid-2014, the oil industry has been negatively affected by a sharp price downturn driven by global oversupplies and a slowdown in macroeconomic growth. Over this time span, the price of crude oil has lost approximately 50% of its value. In 2016, after dropping below $30 per barrel (“BBL”), the price of Brent crude has staged a recovery to close at around $50 per barrel at year-end as a result of a less unfavorable supply-demand balance. This was helped by the agreement reached in late 2016 by producing countries belonging to the Organization of the Petroleum Exporting Countries (“OPEC”) and other non-member countries to cut the output. For the full year (“FY”) 2016, the benchmark Brent price averaged $43.7 per barrel, a reduction of approximately 17% compared to 2015; global political developments, including sanctions imposed on certain producing countries and conflict situations; global economic and financial market conditions; the influence of the OPEC over world supply and therefore oil prices; prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables); weather conditions; operational issues; governmental regulations and actions; success in development and deployment of new technologies for the recovery of crude oil and natural gas reserves and technological advances affecting energy consumption; and the effect of worldwide energy conservation and environmental protection efforts intended to reduce greenhouse gas (“GHG”) emissions from human activities. All these factors can affect the balance between global demand and supply for oil and prices of oil. Management believes that the oil market will gradually recover in the medium-term. We foresee a better balance between demand and supply driven by the recently agreed OPEC cuts and the cooperation of other countries in curbing production and the effects of the reduced investments made by international oil companies during the downturn, while global oil consumptions are expected to grow at a moderate pace. However, management has also evaluated the continuing risks and uncertainties inherent in such forecasts, 6 including actual implementation of the production cuts announced by the OPEC, structural changes that have been affecting oil industry – e.g. the increase in oil supply following the U.S. tight oil revolution – the reduced impact of geopolitical crises and the greater role played by renewable energy sources, as well as risks associated with internationally-agreed measures intended to reduce GHG. Based on this outlook, Eni’s management has slightly revised to 70 $/BBL from the previous 65 $/BBL its long-term price assumptions of the Brent crude oil marker utilized in the Group financial projections of the 2017-2020 industrial plan and in evaluating recoverability of the carrying amounts of the Group’s oil and gas assets. In the 2015 financial statements the adoption of a long-term oil price of 65 $/BBL led to the recognition of impairment losses of €3.4 billion post-tax at our oil&gas assets. Conversely, the upward revision of the long-term assumptions for Brent crude oil prices led to the reversal of previously recognized impairment losses for €1,005 million (post-tax). Price fluctuations may have a material effect on the Group’s results of operations and cash flow. Lower oil prices from period to period negatively affect the Group’s consolidated results of operations and cash flow, because revenues are price sensitive; such current prices are reflected in revenues recognized in the 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. Eni estimates that its consolidated net profit and cash flow vary by approximately €0.2 billion for each one dollar change in the price of the Brent crude oil benchmark with respect to the price scenario assumed in Eni’s financial projections for 2017 at 55 $/BBL. In addition to the adverse effect on revenues, profitability and cash flow, lower oil and gas prices could result in debooking of proved reserves, if they become economically unviable in this type of environment, and asset impairments. Depending on the significance and speed of a decrease in crude oil prices, Eni may also need to review investment decisions and the viability of development projects. Lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flow and hence the funds available to finance expansion projects, further reducing the Company’s ability to grow future production and revenues. In addition, they may reduce returns from development projects, either planned or implemented, forcing the Company to reschedule, postpone or cancel development projects. The Group is currently planning a capital budget of approximately €31.6 billion in the next four years, excluding expenditures associated with assets which the Group is planning to divest. This capital budget is significantly lower than the Group’s previous financial projections, down by 8% on a constant exchange rate basis, which reflect management’s approach to be more selective in its spending decisions in a low oil-price environment. 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, including Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investor Services Inc (“Moody’s”). These downgrades 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. At the end of March 2016, both agencies lowered Eni’s long-term corporate credit rating (to BBB+ and Baa1, respectively). Eni estimates that movements in oil prices affect approximately 50% of Eni’s current production. The remaining portion of Eni’s current production is insulated from crude oil price movements considering that the Company’s property portfolio is characterized by a sizeable presence of production sharing contracts, where, due to the cost recovery mechanism, the Company is entitled to a larger number of barrels in case of a decline in crude oil prices. (See the specific risks of the Exploration & Production segment in “Risks associated with the exploration and production of oil and natural gas” below). Because of the above mentioned risks, an extended continuation of the current commodity price environment, or further declines in commodity prices, will materially and adversely affect the Group’s business prospects, financial condition, results of operations, cash flows, liquidity, ability to finance planned capital expenditures and commitments and may impact shareholder returns, including dividends and the share price. 7 In gas markets, price volatility reflects the dynamics of demand and supply for natural gas. In recent years, in the face of weak demand dynamics in Europe due to the economic downturn and competition from coal and renewable sources in the production of gas-fired power, gas supplies in Europe have continued to rise. Factors underlying this rise comprise the increased availability of liquefied natural gas (“LNG”) on a global scale, which in the future will be fuelled by an expected growth in LNG exports from the U.S. and the Asia-Pacific region, and volumes of contracted supplies of European gas wholesalers under long-term arrangements with take-or-pay clauses. See also the other trends described in the risk factors relating to Eni’s Gas & Power business below. The increased liquidity of European hubs has put significant downward pressure on spot prices. Eni expects those trends to continue in the foreseeable future due to a weak outlook for gas demand and continued oversupplies. If Eni fails to renegotiate its long-term gas supply contracts in order to make its gas competitive as market conditions evolve, its profitability and cash flow in the Gas & Power segment would be significantly further affected by current downward trends in gas prices. The Group’s results from its Refining & Marketing and Chemicals businesses are primarily dependent upon the supply and demand for refined and chemicals products and the associated margins on refined product and chemical products sales, with the impact of changes in oil prices on results of these segments being dependent upon the speed at which the prices of products adjust to reflect movements in oil prices. Competition There is strong competition worldwide, both within the oil industry and with other industries, to supply energy to the industrial, commercial and residential energy markets Eni faces strong competition in each of its business segments. In the current uncertain financial and economic environment, Eni expects that prices of energy commodities, in particular oil and gas, will be very volatile, with average prices and margins influenced by changes in the global supply and demand for energy, as well as in the market dynamics. This is likely to increase competition in all of Eni’s businesses, which may impact costs and margins. Competition affects licence costs and product prices, with a consequent effect on Eni’s margins and its market shares. Eni’s ability to remain competitive requires continuous focus on technological innovation, reducing unit costs and improving efficiency. It also depends on Eni’s ability to get access to new investment opportunities, both in Europe and worldwide. • • In the Exploration & Production segment, Eni faces competition from both international and State-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage because of its relatively smaller size compared to other international oil companies, particularly when bidding for large scale or capital intensive projects, and may be exposed to 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. If, because of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control costs, its growth prospects and future results of operations and cash flow may be adversely affected. In the Gas & Power segment, Eni faces strong competition from gas and energy players to sell gas to the industrial segment, the thermoelectric sector and the retail customers both in the Italian market and in markets across Europe. Competition has been fuelled by ongoing weak trends in demand due to the downturn and macroeconomic uncertainties and continued oversupplies in the marketplace. These have been driven by rising production of LNG on global scale and inter-fuel competition. In the latest years the use of gas in gas-fired power plants has been negatively affected by an increase use of coal in firing power plants due to cost advantages and a dramatic growth in the adoption of renewable sources of energy (photovoltaic and solar). The large-scale development of shale gas in the United States was another fundamental trend that aggravated the oversupply situation in Europe because many LNG projects that originally targeted the U.S. market instead provided extra supply to the already saturated European sector. The continuing growth in the production of shale gas in the United States has increased global gas supplies. These market imbalances in Europe were exacerbated by the fact that throughout the last decade and up to a few years ago the market consensus projected that gas demand in the continent would grow steadily until 2020 and beyond, driven by economic growth and the increased adoption of gas in firing power production. European gas wholesalers including Eni committed to purchasing large amounts of gas under long-term supply contracts with so-called “take-or-pay” clauses from the 8 main producing countries bordering Europe (namely Russia, the Netherlands, Norway and Algeria). They also made significant capital expenditures to upgrade existing pipelines and to build new infrastructures in order to expand gas import capacity to continental markets. Long-term gas supply contracts with take-or-pay clauses expose gas wholesalers to a volume risk, as they are contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price. Due to the trends described above of the prolonged economic downturn and inter-fuel competition, the projected increases in gas demand failed to materialize, resulting in a situation of oversupply and pricing pressure. As demand contracted across Europe, gas supplies increased, thus driving the development of very liquid continental hubs to trade spot gas. Spot prices at continental hubs have become the main benchmarks to which selling prices are indexed across all end-markets, including large industrial customers, thermoelectric utilities and the retail segment. The profitability of gas operators was negatively impacted by falling sales prices at those hubs, where prices have been pressured by intense competition among gas operators in the face of weak demand, oversupplies and the constraint to dispose of minimum annual volumes of gas to be purchased under long-term supply contracts. Eni does not expect any significant improvement in the European gas sector in the near future. We are currently projecting weak gas demand trends due to macroeconomic uncertainties and unclear EU policies regarding how to satisfy energy demand in Europe and the energy mix. Additionally, supplies at continental hubs will continue to build given the expected ramp-up of LNG exports from the United States due to steady growth in gas production and ongoing projects to reconvert LNG regasification facilities into liquefaction export units and the start of several LNG projects in the Pacific region and elsewhere. Eni believes that these ongoing negative trends may adversely affect the Company’s future results of operations and cash flows, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of gas in accordance with its long-term gas supply contracts with take-or-pay clauses. In its Gas & Power segment, Eni is vertically integrated in the production of electricity via its gas-fired power plants, which currently use the combined-cycle technology. In the electricity business, Eni competes with other producers and traders from Italy or outside Italy who sell electricity in the Italian market. Going forward, the Company expects continuing competition due to the projections of moderate economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production on the Italian market. The economics of the gas-fired electricity business have dramatically changed over the latest few years due to ongoing competitive trends. Spot prices of electricity in the wholesale market across Europe decreased due to excess supplies driven by the growing production of electricity from renewable sources, which also benefit from governmental subsidies, and a recovery in the production of coal-fired electricity which was helped by a substantial reduction in the price of this fuel on the back of a massive oversupply of coal which occurred on a global scale. As a result of falling electricity prices, margins on the production of gas-fired electricity went into negative territory. Eni believes that the profitability outlook in this business will remain weak in the foreseeable future. In the Refining & Marketing segment, Eni faces strong competition both in industrial and in commercial activities. In 2016 refining margins decreased by approximately 50% y-o-y due to overcapacity in Europe, global oversupplies and strong competition from cheaper products stream coming from more efficient refiners in the Middle East, in Asia and elsewhere. Looking forward, management believes that refining margins will remain under pressure in the foreseeable future and will hover around $4 per barrel in the next couple of years, level at which our refining business is currently barely profitable. In marketing, Eni faces the challenges of growing competition from operators without brands and large retailers, which leverage on the price awareness of final consumers to increase their market share. In the Chemical business, Eni faces strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized segments such as the production of basic petrochemical products and plastics. Many of those competitors based in the Far East and the Middle East are able to benefit from cost advantages due to scale, favorable environmental regulations, availability of cheap feedstock and proximity to end-markets. Excess capacity and sluggish economic growth in Europe have exacerbated competitive pressures with negative impacts on profitability. Furthermore, petrochemical producers based in the United • • • 9 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. The Company expects continuing margin pressures in its petrochemical segment in the foreseeable future as a result of those trends. 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. 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 mitigate 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 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. Accidents at a single well can lead to loss of life, damage or destruction to properties, environmental damage, GHG emissions and consequently potential economic losses that could have a material and adverse effect on the business, results of operations, liquidity, reputation and prospects of the Group, including its share price and dividends. Eni’s activities in the Refining & Marketing business entail health, safety and environmental risks related to the handling, transformation and distribution of oil and oil products. These risks arise from the inherent characteristics of hydrocarbons, in particular flammability and toxicity. Also environmental risks are involved in the use of oil products, such as GHG emissions, soil and groundwater contamination. Eni’s activities in the Refining & Marketing and Chemicals segment also entail health, safety and environmental risks related to the overall life cycle of the products manufactured, and to raw materials used in the manufacturing process, such as oil-based feedstock, catalysts, additives and monomer feedstock. These risks can arise from the intrinsic characteristics of the products involved (flammability, toxicity, or long-term environmental impact such as greenhouse gas emissions and risks of various forms of pollution and contamination of the soil and the groundwater), their use, emissions and discharges resulting from their manufacturing process, 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 and the environment. The Company invests significant resources in order to upgrade the methods and systems for safeguarding the safety and health of employees, contractors and communities, and the environment; to prevent risks; to comply with applicable laws and policies; and to respond to and learn from unexpected incidents. Eni seeks to minimize these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and distribution networks, and managing its operations in a safe, compliant and reliable manner. Failure to manage these including releases or oil spills, blowouts, fire, risks could effectively result in unexpected incidents, mechanical failures and other incidents resulting in personal injury, loss of life, environmental damage, legal liabilities and/or damage claims, destruction of crude oil or natural gas wells, as well as damage to equipment and other property, all of which could lead to a disruption in operations. 10 In December 2016, an incident occurred at our Eni Slurry Technology unit located in the refinery of Sannazzaro where a fire due to a mechanical fault partially damaged the plant. We recorded a plant write-off of €193 million and a provision for site dismantling and cleanup of €24 million. We did not identify any environmental provision as of the date of this Annual Report. Considering that the value of the plant was partially insured with third parties, the Group loss related to the accident amounted to €95 million. 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 decommissioning of productive infrastructure and environmental site remediation. 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 for all of its subsidiaries, which is designated to hedge part of the liabilities associated with damage to third parties, loss of value to the Group’s assets related to unfavorable events and in connection with environmental cleanup and remediation. Particularly, Eni’s entities are insured against liabilities for damage to third parties and environmental claims up to $1.2 billion in case of offshore incident and $1.4 billion in case of incident at onshore facilities (refineries). In addition, 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 few 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 occurrence of the events mentioned above could have a material adverse impact on the Group’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects and shareholders’ returns and damage the Group’s reputation. 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 loss would not have a material adverse effect on the Company. Risks associated with the exploration and production of oil and natural gas to natural hazards and other uncertainties, The exploration and production of oil and natural gas require high levels of capital expenditures and including those relating to the physical are subject characteristics of oil and gas fields. 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, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. A description of the main risks facing the Company’s business in the exploration and production of oil&gas is provided below. Eni’s oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2016, approximately 53% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Norway, Italy, Angola, the Gulf of Mexico, Congo, United Kingdom and Nigeria. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. Offshore 11 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. Further, 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. Failure to manage these risks could result in injury or loss of life, damage to property or environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to Eni’s reputation and could have a material adverse effect on Eni’s operations, results, liquidity, reputation, business prospects and the share price. Exploratory drilling efforts 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, completing and operating 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, and shortages or delays in the delivery of equipment. The Company also engages in exploration drilling activities offshore, including in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea). In these locations, the Company generally experiences more challenging conditions and incurs higher exploration costs than onshore or in shallow waters. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to make investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Some of these activities are high-risk projects that generally involve sizeable plays located in deep and ultra-deep waters or at higher depths where operations are more challenging and costly than in other areas. Furthermore, deep and ultra-deep water operations will require significant time before commercial production of discovered reserves can commence, increasing both the operational and financial risks associated with these activities. In 2016 Eni invested approximately €0.42 billion in exploration projects. The Company plans to invest €2.1 billion in the four-year plan 2017-2020 and to execute exploration projects in the Norwegian Barents Sea, North and West Africa (Nigeria, Egypt, Libya, Congo, Gabon, Angola and Morocco), East Africa (Mozambique, Kenya) and South-East Asia (Indonesia, Vietnam, Myanmar and other locations), the United Kingdom, offshore Gulf of Mexico and offshore Cyprus. Planned projects will be equally split between low-risk initiatives, involving proven areas and the appraisal of recent discoveries, as well as high-risk plays targeting conventional hydrocarbons. 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. 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 environmentally-sensitive locations. Eni’s future results of operations and liquidity 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: • • • • • the outcome of negotiations with joint venture partners, governments and state-owned companies, suppliers, customers or others, including, for example, Eni’s ability to negotiate favourable long-term contracts to market gas reserves; commercial arrangements for pipelines and related equipment hydrocarbons; timely issuance of permits and licences by government agencies; the Company’s relative size compared to its main competitors which may prevent it from participating in large-scale projects or affect its ability to reap benefits associated with economies of scale; to transport and market the ability to carefully carry out front-end engineering design so as to prevent the occurrence of technical inconvenience during the execution phase; 12 • • • • • • 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; these events may cause cost overruns and delays impacting the time-to-market of the reserves; risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs; poor performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) – turn key contractual scheme. Eni believes this kind of risk may be due to lack of contractual flexibility, poor quality of front-end engineering design and commissioning delays; changes in operating conditions and cost overruns. In recent years, the industry has been adversely impacted by the growing complexity and scale of projects which drove cost increases and delays, including higher environmental and safety costs; the actual performance of the reservoir and natural field decline; and the ability and time necessary to build suitable transport infrastructures to export production to end markets. Events such as the ones described above of poor project execution, inadequate front-end engineering design, delays in the achievement of critical events and project milestones, delays in the delivery of production facilities and other equipment by third parties, differences between scheduled and actual timing of the first oil, as well as cost overruns may adversely affect the economic returns of Eni’s development projects. Failure to deliver major projects on time and on budget could negatively affect results of short-term targets of production growth. Finally, operations, cash flow and the achievement of development and marketing of hydrocarbons reserves typically require several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commercial potential, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long leadtime projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from the prices and costs assumed when the investment decision was actually made, leading to lower rates of return. In addition, 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 capitalized 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 Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. 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”) and similar contractual schemes. 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 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. The opposite occurs in case of lower oil prices. 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, negotiation with national oil companies and other entities owners of known reserves and acquisitions. In a number of reserve-rich countries, national oil companies decide to develop portions of oil and gas reserves that remain to be developed. To the extent that national oil companies decide to develop those reserves without the participation of international oil companies or if the Company fails to establish partnership with national oil companies, Eni’s ability to access or develop additional reserves will be limited. 13 An inability to replace produced reserves by finding, 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 and this will negatively affect future results of operations, cash flow and business prospects. Uncertainties in estimates of oil and natural gas reserves Several uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of proved reserve estimates depend on a number of factors, assumptions and variables, among which the most important are the following: • • • • • the quality of available geological, technical and economic data and their interpretation and judgment; projections regarding future rates of production and costs and timing of development expenditures; changes in the prevailing tax rules, other government regulations and contractual conditions; results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices 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. Reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s PSAs and similar contractual schemes. 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 12 month period ending December 31, 2016. For the 12 month period ending December 31, 2016, the average price was 42.8 $/BBL for the Brent crude oil in comparison to a price reference of 54 $/BBL in 2015. This decline in the price of crude oil triggered the downward revision of those reserves that have become uneconomic in this type of environment, amounting to approximately 76 mmBOE, net of higher reserve entitlement in certain PSA contracts due to the cost recovery mechanism: lower oil and gas prices, the reimbursement of expenditures incurred by the Company requires additional volumes of reserves. i.e. because of Many of these 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. Accordingly, the estimated reserves reported as of the end of 2016 could be significantly different from the quantities of oil and natural gas that will be ultimately recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition. The development of the Group’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates. The Group’s proved undeveloped reserves may not be ultimately developed or produced At December 31, 2016, approximately 43% 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, 2016 includes estimates of total future development costs associated with the Group’s proved undeveloped reserves of approximately €39.4 billion (undiscounted). It cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be 14 as estimated. In case of change in the Company’s development plans to develop of 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. 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 and, in particular, may be reduced due to the recent significant decline in commodity prices Investors should not assume the present value of future net revenues from Eni’s proved reserves is the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with U.S. SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the U.S. SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as: • • • • the actual prices Eni receives for sales of crude oil and natural gas; the actual cost and timing of development and production expenditures; the timing and amount of actual production; and changes in governmental regulations or taxation. The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, 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, 2016, the net present value of Eni’s proved reserves totaled approximately €29.8 billion, calculated in accordance with the requirements of FASB Extractive Activities – Oil & Gas (Topic 932). This value was significantly lower than in 2015 due to reduced commodity prices. The average price used to estimate Eni’s proved reserves and the net present value at December 31, 2016, as calculated in accordance with U.S. SEC rules, was 42.8 $/BBL for the Brent crude oil in comparison to 54 $/BBL in 2015. Future prices may materially differ from those used in the Group’s year-end estimates. Political considerations A substantial portion of Eni’s oil and gas reserves and gas supplies are located in countries outside the EU and North America, mainly in Africa, Central Asia and Central-Southern America, where the socio-political framework and macroeconomic outlook is less stable than in the OECD countries. In those less stable countries, Eni is exposed to a wide range of risks and uncertainties, which could materially impact the ability of the Company to conduct its operations in a safe, reliable and profitable manner. As of December 31, 2016, approximately 85% of Eni’s proved hydrocarbon reserves were located in such countries and 60% of Eni’s supplies of natural gas came from outside OECD countries. Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions, inflation levels, exchange rates and similar events in those non-OECD countries may negatively impair Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues: • • lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; laws, regulations and contractual arrangements leading, unfavourable enforcement of for example, to expropriations, nationalizations or forced divestitures of assets and unilateral cancellation or modification of contractual terms. Eni is facing increasing competition from State-owned oil companies who are partnering Eni in a number of oil and gas projects and properties in the host countries where Eni conducts its upstream operations. These State-owned oil companies can change contractual terms and other conditions of oil and gas projects in order 15 to obtain a larger share of profit from a given project, thereby reducing Eni’s profit share. They can also render different interpretations of contractual clauses relating to the recovery of certain expenses incurred by the Company to produce hydrocarbons reserves in any given projects; restrictions on exploration, production, imports and exports; tax or royalty increases (including retroactive claims); political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar incidents. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, the loss of personnel or assets. They may force Eni to evacuate personnel for security reasons and to increase spending on security. 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 geographic areas in which Eni operates; difficulties in finding qualified suppliers in critical operating environments; and complex processes of granting authorisations or licences affecting time-to-market of certain development projects. • • • • • Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Kazakhstan, Venezuela, Iraq and Russia. In addition, any possible reprisals because of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on Eni’s business, results of operations and financial condition. In 2011, Eni’s operations in Libya were materially affected by an internal revolution and a change of regime, which has led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political developments forced Eni to temporarily interrupt or reduce its producing activities, negatively affecting Eni’s results of operations and cash flow until the situation began to stabilize. Although the Group’s production levels in Libya have returned to levels prior to the outbreak of the civil war, the geopolitical situation remains unstable and unpredictable. In 2016, Eni’s production in Libya was 346 kboe/day, the highest level since the outbreak of the civil war, which represented approximately 20% of the Group’s total production for the year. Furthermore, Eni’s activities in Nigeria have been impacted in recent years by continuing episodes of theft, acts of sabotage and other similar disruptions, which have jeopardized 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 those countries. We have factored into our future production levels possible risks of unfavorable geopolitical developments in our main countries of extractive operations. Those risks include temporary production losses and disruptions in the Group’s operations in connection with, among other things, acts of war, sabotage, social unrest, clashes and other form of civil disorder. The contingency has been calculated as a haircut to the Group’s future production levels based on management’s appreciation of those risks, past experience and other considerations. However, this contingency does not cover worst-case developments and worst case events, which could determine a prolonged production shutdown. Eni closely monitors political, social and economic risks of approximately 70 countries in which it has invested or intends to invest, in order to evaluate the economic and financial return of certain projects and to selectively evaluate projects. While the occurrence of those events is unpredictable, the occurrence of any such events could adversely affect Eni’s results from operations, cash flow and business prospects, also including the counterparty risk arising from the financing exposure of Eni in case state-owned entities, which are party to Eni’s upstream projects for developing hydrocarbons, fail to reimburse due amounts. In the current depressed environment for crude oil prices, the financial outlook of certain countries where Eni’s hydrocarbons reserves are located has significantly deteriorated due to lower proceeds from the exploitation of hydrocarbons resources. This trend has increased the risk of sovereign default, which may cause political and macroeconomic instability and trigger one or more of the above mentioned risks. In addition, state-owned petroleum companies of those countries are exposed to liquidity risk. Eni is partnering with those national oil companies in executing certain oil and gas development projects or is currently selling its equity production to national oil companies. Financial difficulties of those national oil companies might jeopardize the financial feasibility of ongoing projects or increase the financial exposure of Eni, which is contractually obliged to finance the share of development expenditures of the partner company in case of a financial shortfall of the latter. This risk is mitigated by the default clause customary 16 in such contracts, pursuant to which which states that in case of a default, the non-defaulting party is entitled to compensate its claims with the share of production of the defaulting party. National oil trade receivable due to Eni for the supply of equity companies may also delay the repayment of hydrocarbons. In view of certain long-overdue exposures related to the supply of equity hydrocarbons, cost recovery and cash call to execute investments, certain of which were also disputed by our counterparties, the Group has entered into arrangements with a number of National Oil Companies. Those arrangements provide for the securitization of amounts due to Eni or repayment plans whereby Eni receivables are reimbursed in instalments with the proceeds of the sale of hydrocarbons produced in mineral initiatives operated by Eni or from elsewhere. Based on ongoing arrangements under discussion to recover part of the overdue amounts, the Group recognized a valuation allowance of approximately €0.41 billion. Furthermore, because the proceeds to reimburse Eni’s receivable will derive from the sale of hydrocarbons reserves yet to be developed, those future proceeds are subject to the mineral risk. In these circumstances, the Group recognized through profit the discount effect of those reimbursement plan utilizing a discount factor that factored in the mineral risk of underlying the reimbursement plan. In 2016, we incurred discount expense of approximately €0.13 billion. Furthermore, in 2016 we incurred losses on trade receivables and equity-accounted entities driven by the devaluation of local currencies for approximately €0.28 billion. It is possible that the Group may incur further losses in connection with its commercial and financial exposure towards certain NOCs of countries which are running wide current account deficits in case of an escalation of local financial crises. For a full description of our overdue trade and other receivables outstanding at year-end, see Note 11 to the Consolidated Financial Statements. An escalation of the political crisis in Russia and Ukraine could affect Eni’s business in particular and the global energy supply generally 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. Approximately 30% of Eni’s natural gas is supplied by Russia. These supplies are out of the reach of current sanctions. Furthermore, Eni is currently partnering the Russian company Rosneft in executing two exploration projects in the Russian sections of the Barents Sea and one in the Black Sea. The contracts pertaining to the above-mentioned exploration licenses were entered into before the enactment of the restrictive measures and the competent authorities of the relevant EU Member States waived contracts under execution when the sanctions were firstly enacted. The EU sanction regime has been extend until July 2017; however it is possible that it could change in relation to the evolution of the political situation in Ukraine. It is possible that wider sanctions targeting the Russian energy, banking and/or finance industries may be implemented. Further sanctions imposed on Russia, Russian individuals 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 future prospects. Risks in the Company Gas & Power business Risks associated with the trading environment and competition in the gas market The outlook of the European gas market remains unfavorable due to oversupply, exacerbated by increased availability of liquefied natural gas (“LNG”) globally, and weak demand dynamics. Growth in gas demand has been dampened by sluggish macroeconomic activity in the Eurozone, the increasing use of renewable sources in the production of electricity and the competition from cheaper fossil fuels (like coal) in firing thermoelectric production. Looking forward, management does not expect any meaningful acceleration in gas demand growth in Italy and in Europe and is forecasting an average growth rate lower than 1% in Europe and Italy until 2020. Against the backdrop of a deteriorating competitive environment, management has periodically renegotiated the Company’s long-term supply contracts with take-or-pay clauses, where the Company is 17 obliged to offtake a contractually set minimum volume of gas supplies or, in case of failure, to pay the contractual price (see below). The renegotiation has allowed the Company to adjust the original oil-linked the indexation mechanism of Company’s supply portfolio, ensuring better competitiveness for the Group’s gas. However, in spite of those measures, continuing cost efficiencies and other actions intended to boost margins, the Gas & Power business reported an operating loss of €391 million for the FY 2016. the purchase costs to market benchmarks at approximately 70% of Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the four-year planning period. Those include continuing oversupplies, strong competition and the risk of deterioration in the spread of Italian spot prices versus continental benchmarks. Eni believes that those trends will negatively affect the gas marketing business future results of operations and cash flows by reducing gas selling prices and margins. Eni’s financial outlook has factored in the rigidities of the Company’s long-term supply contracts with take-or-pay clauses. The main source of risk concerns Eni’s wholesale business, the results of which are exposed to the volatility of the spreads between spot prices at European hubs and Italian spot prices because the Group’s supply costs are mainly indexed to spot prices at European hubs, whereas a large part of the Group’s selling volumes are indexed to Italian spot prices. Against this backdrop, Eni’s management will continue to execute its strategy of renegotiating the Company’s long-term gas supply contracts in order to align pricing and volume terms to current market conditions as they evolve. 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. In particular, management is planning to renegotiate its main long-term supply contracts over the plan period targeting to align supply costs to the expected dynamics in the outlet markets, which will allow the Company to recover logistics costs and G&A costs, targeting to achieve structural breakeven. 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, the claiming party has the ability to open an arbitration procedure to obtain revised contractual conditions. However, also the suppliers might file counterclaim with the arbitration panel seeking to dismiss Eni’s request for a price review. All these possible developments within renegotiation processes could possibly increase the level of risks and uncertainties relating the outcome of those renegotiations. Current, negative trends in gas demands and supplies may impair the Company’s ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts In order to secure long-term access to gas availability, particularly with a view to supplying the Italian gas market and anticipating certain trends in gas demand, which thus far have failed to materialize, Eni has signed a number of long-term gas supply contracts with national operators of certain key producing countries. Most of European gas supplies are sourced from those countries (Russia, Algeria, Libya, the Netherlands and Norway). These contracts include take-or-pay clauses whereby the Company is required to off-take 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 contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price. Looking forward, management believes that the current market outlook which will be negatively affected by continued oversupplies, weak demand growth, strong competitive pressures as well as any possible change in sector-specific regulation represents a risk to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts. In the medium term, this risk will be mitigated by the expected reduction of the contractual minimum take, due to expiration of some contracts. In this scenario, management is committed to the renegotiation of long-term gas supply contract and to portfolio optimization, in order to reduce the exposure to take-or-pay contracts and to the related financial risk. Thanks to contract renegotiations and effective selling activities, the Company lifted part of the underlying volumes, the purchase cost of which the Company advanced to its gas supplies in previous years due to the incurrence of the take-or-pay clause. By these means, the Company has achieved over the latest 18 years a reduction in its deferred costs recorded in the balance sheet from €2.4 billion at the end of 2012, which was the bottom of the gas downturn, to approximately €0.3 billion as of 2016 year-end. Management plans to substantially finalize the recovery of the residual amounts of gas paid in advance in the next few years, fulfilling contractual clauses and recovering the prepaid amounts. Environmental, health and safety regulations Eni has incurred in the past, 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 EU, international, national, regional and local laws and regulations regarding the impact of its operations on the environment and health and safety of employees, contractors, communities and 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 health 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 also regulate emissions of substances and pollutants, handling of hazardous materials and discharges to surface and subsurface of water 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 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 materials. Breaches of environmental, health and safety laws expose the Company’s employees to criminal and civil liabilities associated with compensation for liability and the Company to the incurrence of environmental, health or safety damage, as well as damage to its reputation. Additionally, in the case of violation of certain rules regarding the safeguard of the environment and safety in the workplace, the Company can be liable for negligent or willful conduct on part of 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, safety in the workplace, health of employees, contractors and communities involved by the Company operations, including: • • • • including the costs costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, incurred in connection with governmental action to address climate change; remedial and cleanup measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below); damage compensation claimed by individuals and entities, including local, regional or state administrations, in case Eni causes any kind of accident, oil spill, well blowouts, pollution, contamination, emission of GHG above permitted levels or of other hazardous gases or other environmental liability as a result of its operations or the Company is found guilty of violating environmental laws and regulations; and costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging. Furthermore, in the countries where Eni operates or expects to operate in the near future, new laws and regulations, the imposition of tougher licence requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause Eni to incur material costs resulting from actions taken to comply with such laws and regulations, including: 19 • • • • modifying operations; installing pollution control equipment; implementing additional safety measures; and performing site cleanups. As a further result of any new laws and regulations or other factors, Eni may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish Eni’s productivity and materially and adversely impact Eni’s results of operations, including profits and cash flow. Security threats require continuous assessment and response measures. Acts of terrorism against Eni’s plants, installations, platforms and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people and the environment. Risks of environmental, health and safety incidents and liabilities are inherent in many of Eni’s operations and products. Although management believes that Eni adopts high operational standards to ensure safety in running its operations and safeguard of the environment and the health of employees, contractors and communities. Incidents like blowouts, oil spills, contaminations, pollution, and release in the air, soil and ground water of pollutants and other dangerous materials, liquids or gases, and other similar events could occur that would result in damage, also of large proportion and reach, to the environment, employees, contractors, communities and property. The occurrence of any such events could have a material adverse impact on the Group business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ return and damage to the Group reputation. 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 regulations and, from time to time, such claims have been made against us. In Italy, environmental requirements and regulations typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, natural resource damage, and other damage as a result of Eni’s conduct of operations that was lawful at the time it occurred or 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. Eni has been sued from time to time for alleged environmental crimes and liabilities in relation to the majority of its proprietary areas in Italy where the Company has conducted industrial operations over the years. Many of these proceedings are currently underway. The majority of those potential liabilities relate to certain industrial activities that the Company disposed of, liquidated, closed or shut down in prior years where Group products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities. At those industrial hubs, Eni has undertaken a number of initiatives to restore and clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. The Group believes that it cannot be held liable for contaminations which occurred in past years (as permitted by applicable regulations in case of declaration rendered by a guiltless owner i.e. as a result of Eni’s conduct that was lawful at the time it occurred) or because Eni took over operations from third parties. However, 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 committed to perform. Eni expects remedial and clean-up activities at Eni’s dismantled sites to continue in the foreseeable future impacting Eni’s liquidity. The Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amounts represent the management’s best estimates of the Company’s existing liabilities for environmental and associated matters. Management believes that it is possible that in the future Eni may incur significant 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 of Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavorable developments in ongoing litigation on the environmental status of certain of the 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 20 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 those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni’s liquidity, results of operations, consolidated financial condition, business prospects, reputation and shareholders’ value, including dividends and the share price. Laws and regulations related to climate change may adversely affect the Group’s businesses Growing public concern in a number of countries over GHG emissions and climate change, as well as a multiplication of stricter regulations in this area, could adversely affect the Group’s businesses, increase its operating costs and reduce its profitability. The scientific community has established a link between climate change and increasing GHG emissions. The worldwide goal to limit global warming has led to the need to gradually reduce fossil fuel use notably through the diversification of the energy mix. The share of natural gas, the least GHG-emitting fossil energy source, represented 48% of Eni’s production in 2016 on available-for-sale basis; as of December 31, 2016, gas reserves represented approximately 51% of our total proved reserves of our subsidiary undertakings. In December 2015, a global climate agreement involving 195 countries was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The Agreement has set the goal to limit well below the 2° C the increase in global temperature compared to pre-industrial parameters. On November 4, 2016, the Paris Agreement was ratified. However, the voluntary commitments taken by the ratifying countries are insufficient to reach the 2°C goal. Nonetheless, the agreement may result in increased political pressure worldwide to adopt measures intended to reduce and monitor GHG emissions and may spur further initiatives aimed at reducing GHG emissions in the future. Changes in environmental requirements related to GHG and climate change may negatively impact demand for oil and natural gas and production may decline as a result of environmental requirements targeting the reduction of GHG emissions (including land use policies responsive to environmental concerns). State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of GHG in areas in which Eni conducts business. Because Eni’s business depends on the global demand for oil and natural gas, existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including incentives to preserve energy or use alternative energy sources, could have a negative impact on Eni’s business if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas. Some governments have introduced carbon pricing mechanisms, which can be an effective measure to reduce GHG emissions across the economy at lowest overall cost to society. We expect more governments to follow and governments may also require companies to apply technical measures to reduce their GHG emissions. These latter may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon dioxide that could result in increased investments and higher project costs for us and could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition. The adoption and implementation of regulations that require reporting of GHG or otherwise limit emissions of GHG from the Group’s equipment and operations could require us to incur costs to monitor and report on GHG emissions or install new equipments, to reduce emissions of GHG associated with the Group’s operations. Our portfolio exposure is reviewed annually against changing GHG regulatory regimes and physical conditions to identify emerging risks. To test the resilience of new projects, we assess potential costs associated with GHG emissions when evaluating all new capital projects. Our approach applies a uniform cost of €40 (real terms) per tonne of carbon dioxide (CO2) equivalent to the total GHG emissions of each investment. This review has concluded that the internal rates of return of our ongoing projects will be only marginally affected by a carbon pricing mechanism. The project development process features a number of checks that may require development of detailed GHG and energy management plans. High-emitting projects undergo additional sensitivity testing, including the potential for future CCS (Carbon Capture and Storage) projects. Projects in the most GHG-exposed asset classes have GHG intensity targets that reflect 21 standards sufficient to allow them to compete and prosper in a more CO2 regulated future. These processes can lead to projects being stopped, designs being changed, and potential GHG mitigation investments in preparation for when regulation would make these investments commercially being identified, compelling. Furthermore, management performed a review of the recoverability of the book values of the Company’s oil&gas assets under the assumptions of the International Energy Agency (IEA) 450 Scenario as updated in November 2016 (450s WEO 2016). This review has covered a panel of oil&gas CGUs, which were selected based on certain parameters, including amount of the capital employed, emission intensity, reserve life and other risk factors. Those CGUs represented approximately 30% of the Group capital employed in the E&P segment. The IEA 450 Scenario sets out an energy pathway consistent with the goal of limiting the average global temperature increase to 2°C. This is accomplished by seeking to limit the concentration of greenhouse gases in the atmosphere to around 450 parts per million of CO2 equivalent. By the year 2030, the IEA’s 450 Scenario describes an energy sector with significant renewables penetration, marked improvement in vehicle as well as process efficiency, and widespread replacement of coal by natural gas in power generation. The IEA has assumed oil and gas prices in 2030 of around $113 per barrel and $12.5 per MMbtu respectively, and global CO2 equivalent costs of $133 per tonne (all in nominal terms). The related impact on expected production is that global demand for oil would fall by 17% between 2015 and 2030, while demand for natural gas would grow by 8% during that period. The IEA’s projected GHG regulation and demand scenario are expected to result in lower demand for some of our products and potential albeit immaterial impairments to some of our less energy efficient assets. However, we could also see certain benefits as a robust global CO2 price would make some forms of energy, such as natural gas and renewables, more competitive compared with coal. Our preliminary view, looking at 2030, is that the aggregate impact under the IEA’s 450 Scenario would be positive overall for us compared with our own outlook. This is primarily due to the higher oil and gas prices assumed by the IEA. While the IEA assumes significant global CO2 costs of $133/tonne (in nominal terms) in 2030, our portfolio sensitivity to oil and gas prices exceeds our sensitivity to CO2 costs associated with our GHG emissions. Finally, it should be noted some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. If any such effects were to occur because of climate change or otherwise, they could have an adverse effect on the Group’s assets and operations. Risks related to legal proceedings and compliance with anti-corruption legislation Eni is the defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of the latest balance sheet date to account for ongoing proceedings, it is possible that 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; (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 where Eni or its subsidiaries or its officers are parties involve the alleged breach of anti-corruption laws and regulations and ethical misconduct. Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and anti-corruption laws, by Eni, 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. See “Note 38 – Guarantees, commitments and risks – Legal proceedings, in the Consolidated Financial Statements”. 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 22 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 connected to acquisitions materialize, 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. In general, the effects of climate change could result in less stable weather patterns, resulting in more severe storms and other weather conditions that could interfere with Eni’s operations and damage Eni’s facilities. Furthermore, Eni’s operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to Eni’s operations and consequent loss or damage of properties and facilities, as well as a loss of output, revenues, maintenance and repair expenses and cash flow shortfall. 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 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, its business and operations could be severely disrupted with negative consequences on results of operations and cash flow. Exposure to financial risk Eni’s business activities are inherently exposed to financial risk. This includes exposure to market risk, including commodity price risk, interest rate risk and foreign currency risk, as well as liquidity risk, and credit risk. Eni’s primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil and gas reserves, volume of gas purchased under its long-term gas purchase contracts, which are not covered by contracted sales, its refining margins and other activities. The Group’s risk management objectives in addressing commodity risk are to optimise the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. To achieve this, Eni engages in risk management activities seeking both to hedge Group’s exposures and to profit from short-term market opportunities and trading. Eni is engaged in substantial trading and commercial activities in the physical markets. Eni also uses financial instruments such as futures, options, Over The Counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage the commodity risk exposure. Eni also uses financial instruments to manage foreign exchange and interest rate risk. The Group’s approach to risk management includes identifying, evaluating and managing the financial risk using a top-down approach whereby the Board of Directors is responsible for establishing the Group risk management strategy and setting the maximum tolerable amounts of risk exposure. The Group’s Chief Executive Officer is responsible for implementing the Group risk management strategy, while the Group’s Chief Financial Officer is in charge of defining policies and tools to manage the Group’s exposure to financial risk, as well as monitoring and reporting activities. Various Group committees are in charge of defining internal criteria, guidelines and targets of risk management activities consistent with the strategy and limits defined at Eni’s top level, to be used by the Group’s business units, including monitoring and controlling activities. Although Eni believes it has 23 established sound risk management procedures, trading activities involve elements of forecasting and Eni is exposed to the risks of market movements, of incurring significant losses if prices develop contrary to management expectations and of default of counterparties. Exchange rate risk Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni’s results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to U.S. dollars, while a significant portion of Eni’s expenses are incurred in euros. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity. The Exploration & Production segment is particularly affected by movements in the dollar versus the euro exchange rates as the U.S. dollar is the functional currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations. Susceptibility to variations in sovereign rating risk Eni’s credit ratings are potentially exposed to risk in reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the Notes or other debt instruments issued by the Company could be downgraded. Interest rate risk Interest on Eni’s debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, “Euribor”, and the London Interbank Offered Rate, “Libor”. As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its debt. Additionally, spreads offered to the Company may rise in connection with variations in sovereign rating risks or company rating risks, as well as the general conditions of capital markets. 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 in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively affect the Group results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. European and global financial markets are currently subject to volatility amid uncertainties relating to a weak macroeconomic outlook, particularly in the Euro-zone, and the financial stress of certain emerging economies or countries whose financial conditions depends upon the proceeds of the sale of hydrocarbon resources following a prolonged slump in commodity prices. In the event of extended periods of constraints in the financial markets, or if Eni is unable to access the financial markets (including cases where this is due to Eni’s financial position or market sentiment as to Eni’s prospects) at a time when cash flows from Eni’s business operations may be under pressure, Eni’s ability to maintain Eni’s long-term investment program may be impacted with a consequent effect on Eni’s growth rate, and may impact shareholder returns, including dividends or share price. The oil and gas industry is capital intensive. Eni makes and expects to continue to make substantial capital expenditures in its business for the exploration, development, exploitation and production of oil and natural gas reserves. The Company’s capital budget for the four-year plan 2017-2020 amounts to €31,6 billion, net of capex associated with the planned asset disposals, and is significantly lower than the Group’s previous industrial plan (down by an estimated 8% at constant exchange rates) as a result of a planned reduction in spending prompted by weak commodity prices and a more selective approach to spending compared to the past. The Company has budgeted approximately €7.8 billion for capital expenditure in 2017, which is 18% lower than in 2016 at constant exchange rates. Management may find that additional reductions in Eni’s capital budget become necessary depending on market conditions. 24 Historically, Eni’s capital expenditures have been financed with cash generated by operations, proceeds from asset disposals, borrowings under its credit facilities and proceeds from the issuance of debt and bonds. The actual amount and timing of future capital expenditures may differ materially from Eni’s estimates as a result of, among other things, changes in commodity prices, available cash flows, lack of access to capital, actual drilling results, the availability of drilling rigs and other services and equipments, the availability of transportation capacity, and regulatory, technological and competitive developments. Eni’s cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to: • • • • • the amount of Eni’s proved reserves; the volume of crude oil and natural gas Eni is able to produce and sell from existing wells; the prices at which crude oil and natural gas are sold; Eni’s ability to acquire, find and produce new reserves; and the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds. If revenues or Eni’s ability to borrow decrease significantly due to factors such as a prolonged decline in crude oil and natural gas prices, Eni might have limited ability to obtain the capital necessary to sustain its planned capital expenditures. If cash generated by operations, cash from asset disposals, or cash available under Eni’s liquidity reserves or its credit facilities is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of Eni’s reserves, which in turn could adversely affect its business, financial condition, results of operations, and cash flows and its ability to achieve its growth plans. With respect to the 2017-2020 business plan in particular, management expects to deliver approximately €5-7 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of stakes in the Group’s exploration assets thereby in essence monetizing some of the Group’s recent exploration successes and reserves. These additional cash flows are intended to provide the Group with further financial flexibility in view of funding organic growth and the Group’s planned shareholder distributions in a manner consistent with the Group’s target capital structure. The Company is seeking to complete such disposals in large part within 2017. However, asset disposals are subject to execution risk and may fail to be completed, and the proceeds received from such disposals may not reflect valuations that management currently believes are achievable, particularly if the disposals are carried out in difficult market conditions. The failure to achieve the planned disposal program could negatively affect the achievement of the Group’s financial targets forcing us to either curtail capital expenditure thus hampering growth or take on more finance debt. These factors could also negatively affect shareholders’ returns, including the amount of cash available for dividend distribution as well as the share price. In addition, funding Eni’s capital expenditures with additional debt will increase its leverage and the issuance of additional debt will require a portion of Eni’s cash flows from operations to be used for the payment of interest and principal on its debt, thereby reducing its ability to use cash flows to fund capital expenditures and dividends. Credit risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In the latest years, the Group has experienced a level of counterparty default higher than in previous years due to the severity of the economic and financial downturn and the amount of trade receivables overdue at the balance sheet date has increased significantly. Furthermore, a collapse in oil prices has stressed the financial condition of many State-owned entities, which are party to the Group’s upstream projects for exploring and developing hydrocarbons or are buyers of Eni’s equity production. In the 2016 Consolidated Financial Statements, we accrued an allowance against doubtful trade accounts amounting to €503 million, mainly relating to the Gas & Power business segment in relation to Italian retail customers who were experiencing financial difficulties. Management believes that this business is particularly exposed to credit risk due to its large and diversified customer base, which includes a large number of medium and small-sized businesses and retail customers who have been particularly impacted by the financial and economic downturn. Eni believes that 25 the management of doubtful accounts represents an issue to the Company, which will require management focus and commitment going forward. In the future Eni cannot exclude the recognition of significant provisions for doubtful accounts. Considering the deteriorated financial outlook of many oil-producing countries where Eni is conducting its upstream operations due to a prolonged decline in commodity prices, management is strictly monitoring exposure to the counterpart risk in its Exploration & Production (“E&P”) segment. The financial difficulties of certain countries also involve state-owned oil companies who are partnering Eni in the execution of development projects of hydrocarbons reserves or who are buying Eni’s share of production in joint projects. In 2016, we incurred approximately €0.4 billion of losses related to the expected outcome of certain renegotiations to settle disputed amounts or to establish repayment plans of certain overdue receivables owed by few National Oil Companies. Due to the prolonged financial downturn of certain countries hit by a fall in petroleum revenues, it is possible that the Group may incur further counterparty losses in the future. For further information see the paragraph “Political Considerations” above. Digital infrastructure is an important part of maintaining Eni’s operations. A breach of Eni’s digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs including the reliable operation of The reliability and security of Eni’s digital infrastructure is critical to maintaining the availability of technology in Eni’s various business Eni’s business applications, operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. If Eni’s systems for protecting Eni’s digital security prove to be ineffective, either due to intentional actions such as cyber-attacks or negligence, Eni could be adversely affected by, among other things, loss or damage to intellectual property, proprietary information, or customer data, an interruption of business operations, and increased costs to prevent, respond to, or mitigate potential risks to Eni’s digital infrastructure. Furthermore, in some circumstances, failures to protect digital infrastructure could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs. 26 Item 4. INFORMATION ON THE COMPANY History and development of the Company Eni SpA with its consolidated subsidiaries engages in the exploration, development and production of hydrocarbons, in the supply and marketing of gas, LNG and power, in the refining and marketing of petroleum products, in the production and marketing of basic petrochemicals, plastics and elastomers and in commodity trading. In 2016, the Group exited the Engineering & Construction segment by divesting an interest of 12.503% in the segment parent company, Saipem. Simultaneously to that divestment the Group signed a shareholder agreement with the acquirer that established joint control over Saipem. As a result of those transactions, Eni derecognized Saipem’s assets and liabilities, revenues and expenses effective January 1, 2016. The retained interest of 30.55% in Saipem has been accounted for as an equity-accounted investment from the transactions date. Eni has operations in 73 countries and 33.536 employees as of December 31, 2016. Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders. The name of the agent of Eni in the United States is Giovan Battista Di Giovanni, 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 44 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2016, Eni average daily production amounted to 1,671 KBOE/d on an available-for-sale basis. As of December 31, 2016, Eni’s total proved reserves amounted to 7,490 mmBOE, which include subsidiary undertakings and Eni’s share of reserves of equity-accounted entities. Eni’s Gas & Power segment engages in the supply, trading and marketing of gas, LNG and electricity, international gas transport activities and commodity trading and derivatives. This segment also includes the activity of electricity generation that is ancillary to the marketing of electricity. In 2016, Eni’s worldwide sales of natural gas amounted to 88.93 BCM, of which 38.43 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, 2016. In 2016, electricity sold totaled 37.05 TWh. The Gas & Power segment comprises results of the Group activities intended to manage commodity risk and of asset-backed trading activities. Through the trading department of the parent company and its wholly-owned subsidiary Eni Trading & Shipping SpA, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. This activity is designated to hedge part of the Group exposure to the commodity risk and to optimize commercial margins by entering speculative derivative transactions. Furthermore, this activity includes the result of crude oil and products supply, trading and shipping. Eni’s Refining & Marketing segment 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. In 2016, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to 24.73 mmtonnes (of which traditional refinery throughputs were 24.52 mmtonnes and green refinery throughputs were 0.21 mmtonnes) and sales of refined products were 33.41 mmtonnes, of which 25.6 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 8.59 mmtonnes in Italy and in the rest of Europe. In 2016, Eni’s retail market share in Italy through its “Eni” branded network of service stations was 24.3%. 27 Through its wholly-owned subsidiary Versalis, the Group engages in the production and marketing of basic petrochemical products, plastics and elastomers. Activities are concentrated in Italy and in Europe. The four-year industrial plan foresees the start-up of joint ventures for the production of elastomers in East Asia. In 2016, production volumes of petrochemicals amounted to 5,646 Ktonnes. The results of Versalis have been aggregated with those of R&M, in the reportable segment “R&M and Chemicals” because the two segments exhibit similar economic characteristics. Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in: San Donato Milanese (Milan), Via Emilia, 1; and San Donato Milanese (Milan), Piazza Ezio Vanoni, 1. • • Internet address: eni.com A list of Eni’s subsidiaries is provided in “Item 18 – note 48 – Other information about investments – of the Notes on Consolidated Financial Statements”. Strategy Eni’s strategy is reflective of a deteriorated commodity price environment. During the oil downturn, we have managed to be more selective in our capital investment decisions, to dispose of non-strategic assets, to boost efficiency across all business lines, to renegotiate contracts, to right-size refinery and chemical plants capacity and to streamline processes, operations and G&A. In 2016, we reduced our capital expenditure by 19% y-o-y, mainly in our E&P segment with negligible impacts on our production levels. In spite of the severity of the oil price contraction, which has lost about two thirds of its value from its highs in 2014 compared to the average value registered in 2016, the ratio of net borrowings to total shareholders’ equity, including non-controlling interests, was 0.28 at 2016 year-end below the management 0.3 ceiling. For further information see “Item 5 – Liquidity.” Our priority in the next few years is to increase cash-flow generation, through growing profitably in E&P and enhancing our mid and downstream businesses. We will continue to focus on capital discipline, effective management of the time-to-market of our reserves, early monetization of discovered resources through the disposal of interests in exploration assets and cost control. Our four-year plan foresees a capital budget of approximately €31.6 billion, which is 8% lower than the previous plan, while we are revising upwardly our long-term Brent price assumptions to 70 $/barrel, up from a previous 65 $/barrel. This capital budget is reflective of our cautious stance about future trends in the oil market. Going forward, we will retain a low level of cash neutrality, i.e. we have identified actions and initiatives which should enable the Company to fund its planned capital expenditures via cash flow from operations in a low Brent price environment. Our key financial objectives are disclosed under “Item 5 – Management’s expectations of operations”. Our strategic guidelines are described below. • In the Exploration & Production segment, we plan to achieve profitable production growth to boost cash generation. New field start-ups, ramp-ups at our current field and production optimization to fight natural depletion will underpin our production targets at 2020. Exploration will be the main driver of our future growth and reserve replacement. It will also boost cash generation through early monetization of discovered resources, as it was the case with the Zohr 40% divestment, which is expected to be completed in 2017. Phased project development, designed to reduce financial exposure and fasten production start-up, effective management of the time-to-market of our capital projects and cost control will sustain cash generation. In the Gas & Power, R&M and Chemicals segments, our priority is to retain profitable and cash-generative operations against the backdrop of structural headwinds in the competitive environment due to expectations of sluggish trends in commodity demand, strong competition and oversupplies/overcapacity. The achievement of this goal will require continued initiatives of business enhancement and improvement. • 28 In executing this strategy, management intends to pursue integration opportunities among segments, and within each segment to focus strongly on efficiency improvement through technology upgrading, cost efficiencies, commercial and supply optimization and continuing process streamlining across all segments. Finally, we are reaffirming our commitment to a progressive dividend policy, in line with our plans of underlying earnings and cash flow growth and the scenario evolution. For a description of risks and uncertainties associated with the Company’s outlook and the capital expenditure program see “Item 5 – Operating and financial review and prospects – Management’s expectations of operations”. Significant business and portfolio developments The significant business and portfolio developments that occurred in 2016 and to date in 2017 were the following: • Eni signed two preliminary agreements with Bp and Rosneft for the disposal of a 40% interest in the important gas Zohr discovery, located in the operated block of Shoruk (Eni’s interest 100%) off Egypt. These transactions confirm the effectiveness of Eni’s “dual exploration model”, which simultaneously targets the fast-track development of discovered resources, while reducing stakes retained in exploration leases in order to monetize in advance part of the discovered volumes and reduce expenditures in development process. These agreements have economic efficacy from January 1, 2016 and contemplate the reimbursement to Eni of capex incurred until the closing date. The new partners have the option to acquire a further 5% stake at the same terms defined in the agreements. The first transaction closed on February 2017 following approval by the Egyptian authorities; the second one with Rosneft is expected to close by the first half of 2017. The total consideration of the deal amounts to approximately €2 billion as of January 1, 2017, including the reimbursement of costs incurred by Eni in 2016. • March 2017: Eni and Gazprom signed a Memorandum of Understanding aiming to analyze the prospects for cooperation in developing the Southern corridor for gas supplies from Russia to European countries, including Italy, as well as the updating of the Russia-Italy gas supply agreements. The Memorandum also provides for the analysis of partnerships in the LNG sector. • March 2017: Eni and ExxonMobil signed a sale and purchase agreement to acquire a 25% indirect interest in the Area 4 block, offshore Mozambique. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The agreed terms include a cash price of approximately $2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Following completion of the transaction, Eni East Africa will be co-owned by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by and CNPC. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore. This operating model will enable the use of best practices and skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project. • • March 2017: finalized a farm-in agreement to acquire a 50% interest of Block 11, Offshore Cyprus, which will be operated by Total. The exploration area covers 2,215 square kilometers, nearby the Zohr discovery in the Egyptian offshore. Block 11 is expected to be drilled within 2017. February 2017: started-up the Cabaça South East field of the East Hub Development Project, in Block 15/06 of the Angolan deep offshore, five months ahead of development plan estimates and with a very good time-to-market. Block 15/06 will reach a peak of 150 KBBL/d this year. the Merakes discovery under the January 2017: successfully drilled an appraisal well of Production Sharing Contract (PSC) in East Sepinggan. This discovery is located 35 kilometers from the Eni operated Jangkrik field, close to starting operations. January 2017: made a discovery in the PL128/128D licenses in the Norwegian Sea nearby the FPSO (Floating Production, Storage and Offloading) operating the Norne field. This discovery is part of Eni’s near-field exploration strategy aimed at unlocking the presence of additional resources in proximity to existing infrastructures. • • 29 • • • • • • • • • the mineral potential of January 2017: awarded three new exploration licenses in Norway, as a part of the APA Round. January 2017: signed a Memorandum of Understanding with the Nigerian Authorities for the the Country. The agreement also comprises the development of upgrading of the Port Harcourt refinery and a capacity doubling of the power generation unit in Okpai IPP. November 2016: signed four agreements in Bahrein with the National Oil Companies for the evaluation of the mineral potential of certain exploration areas and for the study of the Awali fields. October 2016: signed a binding agreement between the partners of the Area 4 in Mozambique (Eni East Africa, joint operation between Eni and CNPC, Galp, Kogas and ENH) and BP for the sale, over a 20-year period, of approximately 3.3 million tons of LNG per annum (corresponding to about 5 BCM), which will be produced at the Coral South Floating facility. The agreement, approved by the Government of Mozambique, is a fundamental step towards achieving the Final Investment Decision (FID) of the project. The achievement of the FID is prerequisite to the efficacy of the sale contract. Back in February 2016, the Mozambique authorities approved the first development phase of Coral, targeting production of 5 trillion cubic feet (TCF) of gas. October 2016: restarted production at the Kashagan field with the completion of works to fully replace the damaged pipelines following the gas leak occurred at the end of 2013. The production of 180 KBOE/d was achieved by year-end. The production capacity of 370 KBBL/d planned for the Phase 1 is expected to be achieved during 2017, when gas reinjection comes online. September 2016: as part of Eni’s “near-field” exploration strategy, activities resumed onshore Tunisia with the Larich East discovery. The well has been put into production by linking the discovery well to the MLD oil treatment center. September 2016: reached a production plateau of 700 mmCF/d (corresponding to 128 KBOE/d, 67 KBOE/d net to Eni) from the Nooros field. This record-setting production level was reached in just 13 months after the discovery and ahead of schedule, thanks to the success of the latest exploration wells drilled in the Nooros area and the drilling of new development wells. In addition, thanks to the mature operating environment and the conventional nature of the project, production costs are among the lowest in Eni’s portfolio. September 2016: the potential at the Baltim South West field discovery, in the conventional water of Egypt, was upped due to successful test of the first appraisal well. The discovery is located near the Nooros field. September 2016: successfully drilled the Zohr 5x appraisal well, located in 1,538 meters of water depth and 12 kilometers south west from the discovery well. The appraisal well confirmed the overall potential of the Zohr Field. The Zohr development was sanctioned by Egyptian authorities in February 2016. Expected the drilling of a sixth well that will accelerate the production start-up within the end of 2017. • • • March 2016: production start-up at the Goliat oilfield, which is the first producing oilfield in the Barents Sea in the license PL229. Goliat is operated through floating cylindrical production and storage vessel (FPSO). Production has achieved the full-field plateau at 100 KBBL/d (65 KBBL/d net to Eni). In 2016, Eni increased its exploration rights portfolio by about 10,500 square kilometers net, mainly in Egypt, Ghana, Morocco, Montenegro, Norway and the United Kingdom. As part of its strategy designed to evolve the Company’s business model towards a low-carbon environment, Eni intends to develop renewable energy projects in its countries of operations. In 2016, Eni selected and launched a number of industrial initiatives on a large scale in Italy and abroad: (i) The “Italy project” plans to build facilities, mainly in the solar photovoltaic business, in owned industrial areas, which are ready to use and currently lack any industrial value. Fifteen projects have been identified with an overall capacity of approximately 220 MW to be installed by 2022. The first phase of the project foresees the installation of five units: Assemini and Porto Torres in Sardinia (obtained the Final Investment Decision for both projects, while the approval is ongoing from the relevant authorities), Monte Sant’Angelo in Puglia and Priolo in Sicily (FID obtained) and finally Augusta in Sicily; (ii) Outside Italy the company has identified a number of projects to be deployed in countries of operations considered strategic for the Company (mainly Africa and Asia) to increase Eni’s energy efficiency, the sustainability of our consumptions, as well as to improve the access to energy of local communities through a more sustainable energy mix. In December 2016 Eni obtained the FID for a development project in the upstream field BRN in Algeria. Furthermore, a number of agreements for collaboration have been settled with Ghana, Algeria and Tunisia, to strengthen Eni’s presence in these countries and to enlarge the 30 scope of activities. Finally, in 2016 Eni signed strategic framework agreements with: (i) General Electric (GE) for the development of innovative technologies on renewable energy projects (brownfield and greenfield) and hybrid renewable projects focused on energy efficiency. This agreement is intended to identify and develop jointly projects for power generation from renewable sources on large scale; (ii) Terna, Italian grid operator for electricity transmission, for the evaluation of opportunities for the development of energy systems with a focus on sustainability and supporting production from renewables. 31 Exploration & Production BUSINESS OVERVIEW Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 44 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2016, Eni average daily production amounted to 1,671 KBOE/d on an available-for-sale basis. As of December 31, 2016, Eni’s total proved reserves amounted to 7,490 mmBOE; proved reserves of subsidiaries totaled 6,613 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 877 mmBOE. Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth by developing its portfolio of projects underway and by optimizing its current producing fields. We plan to achieve a production growth rate of 3% on average post disposals in the next 2017-2020 four-year period. Our production plans are incorporating our Brent price scenario of 55$/BBL in 2017 and a gradual recovery in the subsequent years up to our long-term case of 70$/BBL in 2020 and going forwards (on constant monetary term compared to 2020, i.e. from 2021 onwards crude oil prices will grow in line with a projected inflationary rate); as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under “Item 5 – Management’s expectations of operations” Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations including, North Africa, Sub-Saharan Africa and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. New field start-ups, production ramp-ups and continuing production optimization will add approximately 850 KBOE/d in 2020; over 60% of these new projects have already been sanctioned and Eni is operator in approximately 70%. Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion and reducing facilities downtime. This will require intense development activities of work-over and infilling and careful planning of maintenance activities. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery. Management plans to invest some €27.1 billion to explore for and to develop reserves over the next four years, with a decrease of 13% net of exchange rate effects versus the previous four-year plan to mitigate the impact of a low oil price environment and net of planned disposal. We plan to prioritize lower intensity projects, brown-field developments and infilling wells mainly in Egypt, Libya and Algeria, while we plan to re-schedule spending in some large projects. This re-scheduling will account for half of the overall reduction, while the remaining will be determined by contracts renegotiations. Planned expenditures in exploration are expected to be some €2.1 billion, slightly lower than the previous four-year plan. Exploration expenditure will be focused on proven plays, near field and appraisal exploration, where we plan to drill 50% of our scheduled wells in 2017-2018. Management planned to progressively increase activity in high-risk high-rewards targets, retaining large stakes in those initiatives with a view of implementing Eni’s dual exploration model. Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight control on project time schedules and costs and reducing the time span, which is necessary to develop and market reserves. We plan to achieve efficient development of our reserves by: (i) in-sourcing critical engineering and project management activities also redeploying to other areas key competences, which will be freed with the start-up of certain strategic projects and increase direct control and governance on construction and commissioning activities; and (ii) signing framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows. Based on those initiatives, we believe that almost all of our projects which we are currently developing over the next four years will be completed on time and on budget. Finally we plan to achieve further cost efficiencies by: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; 32 (ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; (iii) applying our technologies which we believe can reduce drilling and completion costs; and (iv) renegotiating contracts for oilfield services and other items to reap the benefits of the deflationary trend in the industry. We plan to mitigate the operational risk relating to drilling activities by applying Eni’s rigorous procedures throughout the engineering and execution stages, by leveraging on proprietary drilling technologies, excellent skills and know-how, increased control of operations and by deploying technologies which we believe to be able to reduce blow-out risks and to enable the Company to respond quickly and effectively in case of emergencies. For the year 2017, management plans to spend over €6 billion in reserves development and exploration projects, net of planned disposals. 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 buy-back and service contracts. Reserves governance Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is entrusted with the task 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. 33 Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has stated that those guidelines comply with the SEC rules(1). 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 at the head office verifies the production profiles of such properties where significant changes have occurred; (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 25 years of experience in the oil&gas industry and more than 15 years of experience in evaluating reserves. Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers. Reserves independent evaluation Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation(2) of part of its proved reserves on a rotational basis. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third party audit report(3). In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/ gas/water production/injection data of wells, reservoir studies, to field performance, development plans, future capital and operating costs. technical analysis relevant In order to calculate the economic 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 2016, Ryder Scott Company, DeGolyer and MacNaughton and Gaffney, Cline & Associates provided an independent evaluation of approximately 41% of Eni’s total proved reserves at December 31, 2016(4), confirming, as in previous years, the reasonableness of Eni internal evaluation(5). In the 2014-2016 three-year period, 94% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2016, the main Eni properties, which did not undergo an independent evaluation in the last three years, were Zubair (Iraq), Bu Attifel (Libya) and CAFC-MLE (Algeria). (1) (2) (3) (4) (5) See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009. From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott and from 2015, also Gaffney, Cline & Associates. See “Item 19 – Exhibits”. Includes Eni’s share of proved reserves of equity-accounted entities. See “Item 19 – Exhibits”. 34 Summary of proved oil and gas reserves The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2016, 2015 and 2014. Net proved reserves are set out in more detail under the heading “Supplemental oil and gas information” on page F-147. HYDROCARBONS (mmBOE) Rest of Europe Italy North Africa of which Egypt Sub- Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves Consolidated subsidiaries Year ended Dec. 31, 2014 ....................... 503 developed ........................................ 401 undeveloped ..................................... 102 Year ended Dec. 31, 2015 ....................... 465 developed ........................................ 362 undeveloped ..................................... 103 Year ended Dec. 31, 2016 ....................... 354 developed ........................................ 287 67 undeveloped ..................................... 544 1,740 904 335 209 836 495 1,694 404 1,010 91 684 426 2,432 374 957 52 1,475 1,293 352 941 Equity-accounted entities Year ended Dec. 31, 2014 ....................... developed ........................................ undeveloped ..................................... Year ended Dec. 31, 2015 ....................... developed ........................................ undeveloped ..................................... Year ended Dec. 31, 2016 ....................... developed ........................................ undeveloped ..................................... 16 15 1 14 14 14 14 Consolidated subsidiaries and equity accounted entities Year ended Dec. 31, 2014 ....................... 503 developed ........................................ 401 undeveloped ..................................... 102 Year ended Dec. 31, 2015 ....................... 465 developed ........................................ 362 undeveloped ..................................... 103 Year ended Dec. 31, 2016 ....................... 354 developed ........................................ 287 67 undeveloped ..................................... 544 1,756 919 335 837 209 495 1,708 404 1,024 91 684 426 2,446 374 971 52 1,475 1,293 352 941 1,239 702 537 1,282 764 518 1,317 809 508 81 23 58 87 22 65 82 26 56 1,320 725 595 1,369 786 583 1,399 835 564 1,069 589 480 1,198 689 509 1,221 966 255 1,069 589 480 1,198 689 509 1,221 966 255 285 112 173 422 159 263 491 175 316 5 3 2 4 2 2 2 2 290 115 175 426 161 265 493 177 316 232 188 44 269 217 52 227 205 22 728 26 702 810 265 545 779 349 430 960 214 746 1,079 482 597 1,006 554 452 160 135 25 150 115 35 145 111 34 160 135 25 150 115 35 145 111 34 5,772 3,366 2,406 5,975 3,720 2,255 6,613 3,884 2,729 830 67 763 915 303 612 877 391 486 6,602 3,433 3,169 6,890 4,023 2,867 7,490 4,275 3,215 35 LIQUIDS (mmBBL) Rest of Europe Italy North Africa of which Egypt Sub- Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves Consolidated subsidiaries Year ended Dec. 31, 2014 ....................... 243 developed ........................................ 184 undeveloped ..................................... 59 Year ended Dec. 31, 2015 ....................... 228 developed ........................................ 171 undeveloped ..................................... 57 Year ended Dec. 31, 2016 ....................... 176 developed ........................................ 132 44 undeveloped ..................................... 331 174 157 305 237 68 264 228 36 Equity-accounted entities Year ended Dec. 31, 2014 ....................... developed ........................................ undeveloped ..................................... Year ended Dec. 31, 2015 ....................... developed ........................................ undeveloped ..................................... Year ended Dec. 31, 2016 ....................... developed ........................................ undeveloped ..................................... Consolidated subsidiaries and equity accounted entities Year ended Dec. 31, 2014 ....................... 243 developed ........................................ 184 undeveloped ..................................... 59 Year ended Dec. 31, 2015 ....................... 228 developed ........................................ 171 undeveloped ..................................... 57 Year ended Dec. 31, 2016 ....................... 176 developed ........................................ 132 44 undeveloped ..................................... 331 174 157 305 237 68 264 228 36 776 521 255 821 542 279 735 492 243 14 13 1 13 13 13 13 790 534 256 834 555 279 748 505 243 739 470 269 787 511 276 809 507 302 17 7 10 16 6 10 15 8 7 756 477 279 803 517 286 824 515 309 281 205 76 281 205 76 697 306 391 771 355 416 767 556 211 697 306 391 771 355 416 767 556 211 131 64 67 262 126 136 307 124 183 1 1 132 64 68 262 126 136 307 124 183 147 116 31 189 149 40 163 143 20 117 26 91 158 29 129 140 22 118 264 142 122 347 178 169 303 165 138 13 12 1 9 9 9 8 1 13 12 1 9 9 9 8 1 3,077 1,847 1,230 3,372 2,100 1,272 3,230 2,190 1,040 149 46 103 187 48 139 168 43 125 3,226 1,893 1,333 3,559 2,148 1,411 3,398 2,233 1,165 36 NATURAL GAS (BCF) Rest of Europe Italy North Africa of which Egypt Sub- Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves Consolidated subsidiaries Year ended Dec. 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . 1,432 developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,192 240 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year ended Dec. 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . 1,304 developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,051 253 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year ended Dec. 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . 977 845 developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,171 5,291 887 2,110 284 3,181 1,044 4,798 919 2,566 125 2,232 878 9,258 801 2,531 77 6,727 5,520 799 4,721 Equity-accounted entities Year ended Dec. 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year ended Dec. 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year ended Dec. 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 15 13 13 15 15 Consolidated subsidiaries and equity accounted entities Year ended Dec. 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . 1,432 developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,192 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 240 Year ended Dec. 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . 1,304 developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,051 253 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year ended Dec. 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . 977 845 developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,171 5,306 887 2,125 284 3,181 1,044 4,811 919 2,579 125 2,232 878 9,273 801 2,546 77 6,727 5,520 799 4,721 2,744 1,271 1,473 2,714 1,390 1,324 2,767 1,651 1,116 351 89 262 387 85 302 368 104 264 3,095 1,360 1,735 3,101 1,475 1,626 3,135 1,755 1,380 2,049 1,553 496 2,354 1,830 524 2,485 2,239 246 846 261 585 878 185 693 1,003 280 723 18 10 8 12 9 3 4 4 2,049 1,553 496 2,354 1,830 524 2,485 2,239 246 864 271 593 890 194 696 1,007 284 723 468 393 75 439 373 66 353 338 15 3,353 6 3,347 3,581 1,295 2,286 3,484 1,782 1,702 3,821 399 3,422 4,020 1,668 2,352 3,837 2,120 1,717 807 14,808 675 8,342 6,466 132 771 14,302 8,899 585 186 5,403 741 18,462 9,244 559 9,218 182 3,737 120 3,617 3,993 1,402 2,591 3,871 1,905 1,966 807 18,545 675 8,462 132 10,083 771 18,295 585 10,301 186 7,994 741 22,333 559 11,149 182 11,184 Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 212 mmBOE as of December 31, 2016 (139 and 282 mmBOE as of December 31, 2015 and 2014, respectively). Said volumes are not included in reserves volumes shown in the table herein. Subsidiaries Equity-accounted entities 2014 2015 2016 2014 2015 2016 Additions to proved reserves ........................ Purchases of minerals-in-place ..................... Sales of minerals-in-place ............................ Production for the year (a) ............................ 643 4 (8) (575) (mmBOE) 849 1,254 11 98 (10) (17) (629) (616) (8) (13) (28) (a) The difference over production sold of 608.6 mmBOE (549.5 mmboe in 2014 and 642.4 mmboe in 2015) reflected natural gas volumes of 32.1 mmBOE consumed in operations (29.4 mmBOE in 2014 and 26.4 mmBOE in 2015), changes in inventories and other factors. Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources ..................................................... Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic ..................................................... Subsidiaries and equity-accounted entities 2014 2015 (%) 2016 112 145 193 112 148 193 37 Eni’s proved reserves as of December 31, 2016 totaled 7,490 mmBOE (liquids 3,398 mmBBL; natural gas 22,333 BCF). Eni’s proved reserves reported an increase of 600 mmBOE, or 8.7%, from December 31, 2015. All sources additions to proved reserves booked in 2016 were 1,244 mmBOE; of which 1,254 mmBOE came from Eni’s subsidiaries and negative from Eni’s share of equity-accounted entities. Due to a lowered Brent price at $42.8 per barrel in 2016 ($54 per barrel in 2015), our all sources additions were adversely affected by a downward revision of 76 mmBOE, due to our having to remove certain 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”. The methods (or technologies) used in the Eni’s proved reserves assessment in 2016 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However, for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates. The all sources reserves replacement ratio achieved by Eni’s subsidiaries and equity-accounted entities was 193% in 2016 (145% in 2015 and 112% in 2014).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 11.6 years as of December 31, 2016, which included reserves of both subsidiaries and equity-accounted entities. Eni’s subsidiaries Eni’s subsidiaries added 1,254 mmBOE of proved oil&gas reserves in 2016. This comprised 173 mmBBL of liquids and 5,808 BCF of natural gas. Additions to proved reserves derived from: (i) extensions and discoveries were 887 mmBOE, with major increase booked in Egypt following the final investment decision of the Zohr gas project; (ii) revisions of previous estimates were 365 mmBOE mainly reported in Libya, Iraq and Kazakhstan due to continuous development activities and field performances; and (iii) improved recovery were 2 mmBOE mainly reported in Algeria and Norway. Eni’s share of equity-accounted entities Additions in Eni’s share of equity-accounted entities’ proved oil&gas were negative in 2016 and derived from downward revisions of previous estimates reported in Americas. Proved undeveloped reserves Proved undeveloped reserves as of December 31, 2016 totaled 3,215 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,165 mmBBL, mainly concentrated in Africa. Proved 38 undeveloped reserves of natural gas amounted to 11,184 BCF, mainly located in Africa and Americas. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,040 mmBBL of liquids and 9,218 BCF of natural gas. In 2016, total proved undeveloped reserves increased by 348 mmBOE mainly due to: (i) extensions and discoveries (up by 873 mmBOE), in particular in Egypt due to final investment decision sanctioned for the Zohr discovery; (ii) revisions of previous estimates (up by 121 mmBOE) mainly reported in Congo and Iraq; (iii) reclassification to proved developed reserves (down by 646 mmBOE). During 2016, Eni converted 646 mmBOE of proved undeveloped reserves to proved developed reserves due to the progress of development activities, production start-ups and project revisions. The main reclassifications related to the following fields/projects: Kashagan (Kazakhstan), Perla (Venezuela), Litchendjili (Congo), Zubair (Iraq) and Goliat (Norway). to proved developed reserves In 2016, capital expenditure amounted to approximately €7.5 billion and was made to progress the development of proved undeveloped reserves. the projects development and execution, such as the complex nature of Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. Of the proved undeveloped reserves that have been reported for five or more years, the largest are related to forthcoming development phases of in Kazakhstan (approximately 0.2 BBOE) and certain assets in Venezuela the Kashagan project (approximately 0.4 BBOE) and in Iraq (approximately 0.2 BBOE), as well as to certain Libyan gas fields (approximately 0.5 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfilment of the contractual delivery quantities in Libya, Eni will implement phased production start-up from the relevant fields which are expected to be put in production over the next several years. (See also our discussion under the “Risk factors” section regarding risks associated with oil&gas development projects). Eni remains strongly committed to put these projects into production over the next few years. The length of the development period is a function of a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project. Delivery commitments Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities. Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 453 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria, Norway and Venezuela. The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production is expected to account for approximately 86% of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2016. 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 39 uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni’s important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni’s production operations. In 2016, oil and natural gas production available for sale averaged 1,671 KBOE/d (1,688 KBOE/d in 2015) decreased by 1.0% from 2015, mainly due to the production shutdown in the Val d’Agri profit center (See also – oil and gas properties – Italy described above) as well as planned facilities downtime, mainly in the United Kingdom, and the mature fields declines. These negatives were partially offset by new field start-ups and the continuing ramp-up of production at fields started in 2015, mainly reported in Angola, Egypt, Kazakhstan, Norway and Venezuela as well as higher production in Iraq and the price effects reported in PSA contracts. New field start-ups and ramp-ups of production added an estimated 280 KBOE/d of new production. Liquids production (878 KBBL/d) decreased by 30 KBBL/d, or 3.3%, due to the production shutdown in the Val d’Agri profit center, planned facilities downtime and the mature fields decline. These negatives were partially offset by new fields start-up and production ramp-up in particular in Angola, Kazakhstan and Norway as well as higher production in Iraq. Natural gas production (4,329 mmCF/d) reported an increase of 45 mmCF/d, or 1.1% from 2015. Higher production in Egypt and Venezuela were partially offset by planned facilities downtime and the decline of mature fields. Oil and gas production sold amounted to 608.6 mmBOE. The 3.4 mmBOE difference over production on an available-for-sale basis (612 mmBOE) reflected mainly changes in inventories and other factors. Approximately 68% of liquids production sold (320 mmBBL) was destined to Eni’s mid-downstream sectors. About 22% of natural gas production sold (1,574 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 geographical area of each of the last three fiscal years. 2014 Production available for sale (a) Rest of Europe Sub- Saharan Africa Kazakhstan North Africa Italy Rest of Asia Americas Australia and Oceania Hydrocarbons production Eni consolidated subsidiaries ................ (KBOE/d) 171 63 (mmBOE) Eni share of equity-accounted entities ...... (KBOE/d) (mmBOE) 184 67 Liquids production Eni consolidated subsidiaries ................ Eni share of equity-accounted entities ...... 73 27 93 34 (KBBL/d) (mmBBL) (KBBL/d) (mmBBL) 528 193 4 1 249 91 4 1 Natural gas production Eni consolidated subsidiaries ................ (mmCF/d) 541 (BCF) 198 Eni share of equity-accounted entities ...... (mmCF/d) (BCF) 498 1,533 559 182 3 1 305 111 2 1 230 84 411 150 7 3 85 31 52 19 181 66 87 31 4 2 36 13 1 279 102 18 6 112 41 10 4 74 27 10 4 205 75 25 1,497 9 546 20 8 6 2 813 297 15 5 106 3,754 39 1,371 28 10 (a) It excludes production volumes of natural gas consumed in operations. Said volumes were 442 mmCF/d or 29.4 mmBOE. 40 2015 Production available for sale (a) Rest of Europe Sub- Saharan Africa Kazakhstan North Africa Italy Rest of Asia Americas Australia and Oceania Hydrocarbons production Eni consolidated subsidiaries ................ (KBOE/d) 161 59 (mmBOE) Eni share of equity-accounted entities ...... (KBOE/d) (mmBOE) 179 65 Liquids production Eni consolidated subsidiaries ................ Eni share of equity-accounted entities ...... 69 25 85 31 (KBBL/d) (mmBBL) (KBBL/d) (mmBBL) 631 230 4 1 268 98 4 1 Natural gas production Eni consolidated subsidiaries ................ (mmCF/d) 503 (BCF) 183 Eni share of equity-accounted entities ...... (mmCF/d) (BCF) 515 1,990 727 188 3 1 324 119 256 93 378 138 92 33 56 20 199 73 123 45 5 2 77 28 1 1 259 94 19 7 120 44 24 9 75 28 12 4 243 89 68 25 25 1,655 9 604 33 12 5 2 891 325 17 6 107 4,194 39 1,531 90 33 (a) It excludes production volumes of natural gas consumed in operations. Said volumes were 397 mmCF/d or 26.4 mmBOE. 2016 Production available for sale (a) Rest of Europe Sub- Saharan Africa Kazakhstan North Africa Italy Rest of Asia Americas Australia and Oceania Hydrocarbons production Eni consolidated subsidiaries ................ (KBOE/d) 127 47 (mmBOE) Eni share of equity-accounted entities ...... (KBOE/d) (mmBOE) 195 71 Liquids production Eni consolidated subsidiaries ................ Eni share of equity-accounted entities ...... 47 17 109 40 (KBBL/d) (mmBBL) (KBBL/d) (mmBBL) 608 222 3 1 241 88 3 1 Natural gas production Eni consolidated subsidiaries ................ (mmCF/d) 436 (BCF) 159 Eni share of equity-accounted entities ...... (mmCF/d) (BCF) 468 2,000 732 171 3 1 312 114 4 2 247 91 1 353 129 16 6 107 39 65 24 234 86 114 42 4 2 78 28 1 1 199 73 15 6 114 42 60 22 69 25 14 5 243 89 252 92 23 1,600 8 585 71 27 3 1 859 314 19 7 110 4,043 40 1,479 286 105 (a) It excludes production volumes of natural gas consumed in operations. Said volumes were 478 mmCF/d or 32.1 mmBOE. 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 56 KBOE/d, 84 KBOE/d and 78 KBOE/ d in 2016, 2015 and 2014, respectively. The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. Also Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided. The average production cost does not include any ad valorem or severance taxes. 41 AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION ($) Rest of Europe Italy North Africa of which Egypt Sub- Saharan Africa Kazakhstan Rest of Australia and Asia Americas Oceania Total 2014 Consolidated subsidiaries Oil and condensates, per BBL . . . . . . . . . . . . . . . . . . . . 87.80 Natural gas, per KCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.74 Average production cost, per BOE . . . . . . . . . . . . . . . 15.19 Equity-accounted entities Oil and condensates, per BBL . . . . . . . . . . . . . . . . . . . . Natural gas, per KCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average production cost, per BOE . . . . . . . . . . . . . . . 2015 Consolidated subsidiaries Oil and condensates, per BBL . . . . . . . . . . . . . . . . . . . . 43.46 Natural gas, per KCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.92 Average production cost, per BOE . . . . . . . . . . . . . . . 11.08 Equity-accounted entities Oil and condensates, per BBL . . . . . . . . . . . . . . . . . . . . Natural gas, per KCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average production cost, per BOE . . . . . . . . . . . . . . . 2016 Consolidated subsidiaries Oil and condensates, per BBL . . . . . . . . . . . . . . . . . . . . 33.19 Natural gas, per KCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.93 Average production cost, per BOE . . . . . . . . . . . . . . . 9.69 Equity-accounted entities Oil and condensates, per BBL . . . . . . . . . . . . . . . . . . . . Natural gas, per KCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average production cost, per BOE . . . . . . . . . . . . . . . 93.45 2.12 18.88 91.86 0.62 8.94 49.91 1.49 14.08 48.26 0.47 7.93 88.80 88.99 8.08 6.79 8.49 13.61 17.94 6.08 12.50 45.88 46.66 4.69 5.72 6.30 10.93 18.03 3.78 8.98 39.97 39.43 3.29 4.89 4.49 9.31 33.05 3.82 6.34 41.92 1.41 12.09 39.61 0.34 7.58 17.93 1.85 9.74 77.99 6.18 10.70 65.90 15.64 9.79 40.10 4.83 6.48 27.89 9.27 8.67 36.89 3.50 6.14 34.95 5.92 8.19 79.13 3.96 11.75 81.48 42.27 43.36 2.20 11.61 38.18 4.24 16.48 34.86 1.94 8.70 32.39 4.17 8.81 91.61 88.90 7.46 6.83 20.14 12.00 70.56 14.13 26.18 45.84 46.46 5.07 4.54 14.49 9.18 35.15 5.30 14.51 37.96 39.33 3.60 3.20 7.08 7.79 30.85 4.25 8.34 Development activities In 2016, a total of 296 development wells were drilled (118.7 of which represented Eni’s share) as compared to 335 development wells drilled in 2015 (132.4 of which represented Eni’s share) and 440 development wells drilled in 2014 (191 of which represented Eni’s share). The drilling of 68 development wells (28.6 of which represented Eni’s share) is currently underway. The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2016. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. DEVELOPMENT WELL ACTIVITY Net wells completed Wells in progress at 31 Dec. 2014 2015 2016 2016 (units) Productive Dry Productive Dry Productive Dry Gross Net Italy ................................................. Rest of Europe .................................... North Africa ...................................... Sub-Saharan Africa ............................... Kazakhstan ........................................ Rest of Asia ....................................... Americas ........................................... Australia and Oceania ............................ Total including equity-accounted entities ........ 12.5 9.8 54.5 31.6 1.5 54.2 22.1 0.1 186.3 6.0 10.2 30.5 22.0 4.7 29.7 17.4 0.5 121.0 1.0 1.0 1.6 0.7 0.4 4.7 0.1 2.8 2.5 5.9 0.1 4.0 5.6 38.6 21.2 4.6 31.6 9.9 11.4 115.5 1.0 4.0 18.0 36.0 0.8 2.0 4.0 68.0 1.0 0.6 10.0 14.0 0.3 1.9 28.6 1.2 0.2 3.0 0.5 1.3 3.2 Exploration activities In 2016, a total of 16 new exploratory wells were drilled (10.2 of which represented Eni’s share), as compared to 29 exploratory wells drilled in 2015 (19.1 of which represented Eni’s share) and 44 exploratory wells drilled in 2014 (25.8 of which represented Eni’s share). 42 The overall commercial success rate was 50% (50% net to Eni) as compared to 16.7% (25.1% net to Eni) and 31.3% (38% net to Eni) in 2015 and 2014, respectively. The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2016. 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. EXPLORATORY WELL ACTIVITY Net wells completed Wells in progress at Dec. 31(1) 2014 2015 2016 2016 (units) Productive Dry Productive Dry Productive Dry Gross Net Italy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rest of Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . North Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sub-Saharan Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kazakhstan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rest of Asia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Americas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia and Oceania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total including equity-accounted entities . . . . . . . . . 3.5 7.3 1.3 2.0 14.1 0.6 4.3 4.3 7.3 4.3 1.4 0.9 23.1 3.3 0.6 1.0 4.9 0.1 6.0 0.1 2.2 5.8 2.9 3.4 0.3 14.6 6.2 1.0 0.4 1.8 1.1 0.9 1.0 6.2 4.0 9.0 16.0 32.0 6.0 8.0 3.0 1.0 79.0 2.3 2.3 12.3 17.0 1.1 3.2 1.5 0.3 40.0 (1) Includes temporary suspended wells pending further evaluation. Oil and gas properties, operations and acreage In 2016, Eni performed its operations in 44 countries located in five continents. As of December 31, 2016, Eni’s mineral right portfolio consisted of 780 exclusive or shared rights of exploration and development activities for a total acreage of 323,896 square kilometers net to Eni of which developed acreage of 32,489 square kilometers and undeveloped acreage of 291,407 square kilometers net to Eni. In 2016, changes in total net acreage mainly derived from: (i) new leases mainly in Egypt, Ghana, Morocco, Montenegro, Norway and the United Kingdom for a total acreage of approximately 10,500 square kilometers; (ii) the total relinquishment of licenses mainly in Australia, Gabon, India, Liberia, Norway and the United States covering an acreage of approximately 13,000 square kilometers; and (iii) partial relinquishment in Australia, Portugal and South Africa or interest reduction mainly in Myanmar, for approximately 17,000 square kilometers. 43 The table below provides certain information about the Company’s oil&gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2016. A gross acreage is one in which Eni owns a working interest. December 31, 2015 December 31, 2016 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 . . . . . . . . . . . . . . . . . . . Italy . . . . . . . . . . . . . . . . . . . . . . . . . Rest of Europe . . . . . . . . . . . . . . Cyprus . . . . . . . . . . . . . . . . . . . . . . Croatia . . . . . . . . . . . . . . . . . . . . . . Greenland . . . . . . . . . . . . . . . . . . Montenegro . . . . . . . . . . . . . . . . Norway . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Portugal United Kingdom . . . . . . . . . . . Other Countries . . . . . . . . . . . . AFRICA . . . . . . . . . . . . . . . . . . . . North Africa . . . . . . . . . . . . . . . . Algeria . . . . . . . . . . . . . . . . . . . . . . Egypt . . . . . . . . . . . . . . . . . . . . . . . Libya . . . . . . . . . . . . . . . . . . . . . . . . Morocco . . . . . . . . . . . . . . . . . . . . Tunisia . . . . . . . . . . . . . . . . . . . . . . Sub-Saharan Africa . . . . . . . . Angola . . . . . . . . . . . . . . . . . . . . . . Congo . . . . . . . . . . . . . . . . . . . . . . Gabon . . . . . . . . . . . . . . . . . . . . . . Ghana . . . . . . . . . . . . . . . . . . . . . . Ivory Coast . . . . . . . . . . . . . . . . . Kenya . . . . . . . . . . . . . . . . . . . . . . . Liberia . . . . . . . . . . . . . . . . . . . . . . Mozambique . . . . . . . . . . . . . . . Nigeria . . . . . . . . . . . . . . . . . . . . . . South Africa . . . . . . . . . . . . . . . Other Countries . . . . . . . . . . . . ASIA . . . . . . . . . . . . . . . . . . . . . . . . Kazakhstan . . . . . . . . . . . . . . . . . Rest of Asia . . . . . . . . . . . . . . . . China . . . . . . . . . . . . . . . . . . . . . . . India . . . . . . . . . . . . . . . . . . . . . . . . Indonesia . . . . . . . . . . . . . . . . . . . Iraq . . . . . . . . . . . . . . . . . . . . . . . . . Myanmar . . . . . . . . . . . . . . . . . . . Pakistan . . . . . . . . . . . . . . . . . . . . Russia . . . . . . . . . . . . . . . . . . . . . . . Timor Leste . . . . . . . . . . . . . . . . Turkmenistan . . . . . . . . . . . . . . Vietnam . . . . . . . . . . . . . . . . . . . . Other Countries . . . . . . . . . . . . AMERICAS . . . . . . . . . . . . . . . Ecuador . . . . . . . . . . . . . . . . . . . . Mexico . . . . . . . . . . . . . . . . . . . . . . Trinidad & Tobago . . . . . . . . United States . . . . . . . . . . . . . . . Venezuela . . . . . . . . . . . . . . . . . . . Other Countries . . . . . . . . . . . . AUSTRALIA AND OCEANIA . . . . . . . . . . . . . . Australia . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . 45,123 16,975 28,148 10,018 987 1,909 3,114 6,370 1,905 3,845 157,441 25,699 1,179 9,668 13,294 1,558 131,742 4,404 1,354 7,615 100 429 40,426 1,841 1,956 7,432 32,881 33,304 117,183 869 116,314 7,069 6,167 25,124 446 20,050 8,810 20,862 1,230 180 23,132 3,244 6,628 1,985 67 66 2,118 1,066 1,326 16,333 16,333 342,708 295 146 149 3 2 2 4 57 3 67 11 264 121 42 57 11 1 10 143 57 25 4 3 1 7 1 6 34 1 4 59 6 53 8 1 14 1 4 14 3 1 1 5 1 148 1 3 1 129 6 8 14 14 780 15,693 10,498 5,195 1,975 2,311 909 46,384 14,292 3,222 5,508 1,962 3,600 32,092 8,160 1,794 22,138 18,165 2,391 15,774 77 4,246 1,074 10,177 200 4,948 1,985 382 1,320 1,261 51,758 10,320 41,438 12,523 4,890 1,228 6,045 4,547 5,932 6,273 264,600 54,122 187 22,523 24,673 6,739 210,478 12,892 657 6,217 1,353 954 61,363 2,341 3,911 8,631 65,696 46,463 198,024 2,542 195,482 7,056 13,110 30,243 24,080 11,486 62,592 1,538 30,777 14,600 8,154 67 997 1,543 5,547 1,140 1,140 86,330 15,728 15,728 538,264 67,451 20,818 46,633 12,523 1,975 4,890 1,228 8,356 4,547 6,841 6,273 310,984 68,414 3,409 28,031 26,635 6,739 3,600 242,570 21,052 2,451 6,217 1,353 954 61,363 2,341 3,911 30,769 65,696 46,463 216,189 4,933 211,256 7,133 13,110 34,489 1,074 24,080 21,663 62,592 1,538 200 30,777 14,600 13,102 1,985 67 382 2,317 2,804 5,547 16,868 16,868 624,594 10,827 8,775 2,052 987 452 613 11,729 5,738 1,148 2,074 958 1,558 5,991 1,024 971 3,996 6,016 442 5,574 13 1,603 446 3,332 180 3,208 1,985 66 660 497 34,553 7,992 26,561 10,018 1,909 614 2,156 3,182 5,715 2,967 140,947 23,654 31 8,591 12,336 2,696 117,293 3,343 197 6,217 579 286 41,173 585 1,956 3,374 26,279 33,304 103,745 427 103,318 7,056 5,244 23,578 13,558 5,414 20,862 1,230 23,132 3,244 2,488 67 526 569 1,326 709 709 32,489 9,674 9,674 291,407 45,380 16,767 28,613 10,018 987 1,909 614 2,608 3,182 6,328 2,967 152,676 29,392 1,179 10,665 13,294 2,696 1,558 123,284 4,367 1,168 6,217 579 286 41,173 585 1,956 7,370 26,279 33,304 109,761 869 108,892 7,069 5,244 25,181 446 13,558 8,746 20,862 1,230 180 23,132 3,244 5,696 1,985 67 66 1,186 1,066 1,326 10,383 10,383 323,896 Square kilometers. (a) (b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves. 44 The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2016. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same borehole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 9,399 (3,737.6 of which represent Eni’s share). Productive oil and gas wells at Dec. 31, 2016 (a) (units) Oil Wells Natural gas Wells Gross Net Gross Italy ................................................................................ Rest of Europe .................................................................. North Africa ..................................................................... Sub-Saharan Africa ............................................................. Kazakhstan ....................................................................... Rest of Asia ...................................................................... Americas .......................................................................... Australia and Oceania ......................................................... Total including equity-accounted entities .................................... 243.0 395.0 1,813.0 3,020.0 204.0 727.0 264.0 7.0 6,673.0 197.1 72.5 963.8 590.3 54.8 479.1 133.3 3.8 2,494.7 616.0 160.0 225.0 350.0 1,036.0 321.0 18.0 2,726.0 Net 532.4 88.1 98.1 28.8 393.2 98.5 3.8 1,242.9 (a) Multiple completion wells included above: approximateley 2,128 (741.9 net to Eni). Eni’s principal oil and gas properties are described below. In the discussion that follows, references to hydrocarbon production are intended to represent hydrocarbon production available for sale. Italy Eni has been operating in Italy since 1926. In 2016, Eni’s oil and gas production amounted to 127 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley. Eni’s exploration and development activities in Italy are regulated by concession contracts (50 operated onshore and 64 operated offshore) and exploration licenses (12 onshore and 9 offshore). 45 and Ionian The Adriatic Seas represent Eni’s main production area, accounting for 52% of Eni’s domestic production in 2016. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela-Angelina, Hera Lacinia, Bonaccia Garibaldi. (i) Development maintenance and production optimization, mainly at the Barbara, Cervia/Arianna and Morena fields; and (ii) start-up of the Clara NW development project. concerned: activities Porto and Eni is the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano oil center. Southern in On August 12, 2016 the activity of the Val d’Agri Oil Centre in Viggiano gradually restarted following notification by the Italian Public Prosecutor of Potenza that has definitively repealed the plant seizure, with a four-month and half production shutdown, and by the National Mining Office for Hydrocarbons and Earth Resources of the Ministry of Economic Development that has authorized the plant’s operation. The resumption of production is a result of the completion in June 2016 of certain plant upgrading, which do not alter the plant set up, authorized by the in-charge department of the Italian Ministry of Economic Development in order to address the alleged environmental crimes issued by the public prosecutor. Eni operates 12 production concessions onshore and 3 offshore Sicily. The main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2016 accounted for approximately 12% of Eni’s production in Italy. Rest of Europe Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the UK. In 2016, the Rest of Europe accounted for 12% of Eni’s total worldwide production of oil and natural gas. Croatia. Eni has been present in Croatia since 1996. In 2016, Eni’s production of natural gas averaged approximately 24 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula. Exploration and production activities in Croatia are regulated by PSAs. The main producing gas fields are Annamaria, Ivana, Ika & Ida, Ika JZ, Ana, Marica and Katarina and are operated by Eni through a 50/50 joint operating company with the Croatian oil company INA. 46 Norway. Eni has been operating in Norway since 1965. Eni’s activities are in the performed in the Norwegian Sea, Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 131 KBOE/d in 2016. Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions. Eni currently holds interests in 10 production areas in the Norwegian Sea. The principal producing fields are Åsgard (Eni’s interest interest 14.82%), Kristin (Eni’s 8.25%), Heidrun (Eni’s interest 5.17%), interest 14.9%), Tyrihans (Eni’s Mikkel (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2016 accounted for 56% of Eni’s production in Norway. Eni holds interests in 2 production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018, which in 2016 produced approximately 16 KBOE/d net to Eni and accounted for 12% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension. Eni holds interests in 17 exploration and development licenses in the Barents Sea, of which Eni operates 11 licenses. Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest). In March 2016, production start-up was achieved at the Goliat field (Eni operator with a 65% interest) in PL 229 and in 2016 accounted for 25% of Eni’s production in Norway. Field production reached the target of 100 KBOE/d (65 KBOE/d net to Eni) and during the year peak production of approximately 114 KBOE/d (approximately 74 KBOE/d net to Eni) was achieved. The license expires in 2042. Other development activities concerned: (i) the infilling activities in order to support production at the Ekofisk and Eldfisk in the PL 018; and (ii) the maintenance and optimization of the production at the Asgard (Eni’s interest 14.82%), Heidrun (Eni’s interest 5.17%) and Norne Outside (Eni’s interest 11.5%) in the Norwegian Sea. In 2016 Eni was awarded the following exploration licenses: (i) an 11.5% interest in the PL 128D in the Norwegian Sea; (ii) the operatorship and a 70% interest in the PL 816 in the Norwegian section of the North Sea; and (iii) the operatorship and a 65% interest in the PL 229D and a 30% interest in the PL 849 in the Barents Sea. In January 2017, Eni was awarded the PL 28E license (Eni’s interest 11.5%) in the Norwegian Sea and the PL 900 (Eni operator with a 90% interest) and PL 901 (Eni’s interest 30%) in the Barents Sea. At the beginning of 2017, exploration activity yielded positive results with an oil and gas discovery in the PL 128/128D (Eni’s interest 11.5%) in the Norwegian Sea, nearby production facilities of the Norne field (Eni’s interest 6.9%). 47 United Kingdom. Eni has been present in the UK since 1964. Eni’s activities are carried out in the British section of the North Sea and the Irish Sea. In 2016, Eni’s net production of oil and gas averaged 60 KBOE/d. Exploration and production activities in the UK are regulated by concession contracts. Eni currently holds interests in 5 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other fields are Elgin/Franklin (Eni’s interest 21.87%), J Block and Jasmine (Eni’s interest 33%) and Jade (Eni’s interest 7%), which in 2016 accounted for 63% of Eni’s production in the UK. The Phase 2 development activities of the West Franklin field (Eni’s interest 21.87%) was completed and during the year peak production of 61 KBOE/d (13 KBOE/d net to Eni) was achieved. Eni holds interest in 18 exploration licenses, of which 2 are partially in development, with interest ranging from 7% to 100%. Out of the total, 11 are operated by Eni. In 2016, Eni was awarded the operatorship of PL2287, PL2288 and PL2292 licences with a 100% interest in the Irish Sea and Liverpool Bay area, nearby Eni operated production assets. North Africa Eni’s operations are conducted in Algeria, Egypt, Libya and Tunisia. In 2016, North Africa accounted for 37% of Eni’s in North Africa total worldwide production of oil and natural gas. Algeria. Eni has been present in Algeria since 1981. In 2016, Eni’s oil&gas production averaged 85 KBOE/d. Operated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the country: (i) blocks 403a/d (Eni’s interest from 65% to 100%); (ii) block ROM North (Eni’s interest 35%); (iii) blocks 401a/402a (Eni’s interest 55%); (iv) block 403 (Eni’s interest 50%); (v) block 405b (Eni’s interest 75%); and (vi) block 212 (Eni’s interest 22.38%) with discoveries already made. In addition, Eni holds interest in the non-operated block 404 and block 208 with a 12.25% stake. in Exploration and production activities Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts. Production in blocks 403a/d and ROM North comes mainly from the HBN and ROM and satellites fields and represented approximately 21% of Eni’s production in Algeria in 2016. 48 Production in blocks 401a/402a comes mainly from the ROD/SFNE and satellites fields and accounted for approximately 17% of Eni’s production in Algeria in 2016. In 2016, Eni signed with the relevant Authorities a pre-unitization agreement of the SF-SFNE fields and a 10-year extension of the fields in the area. Development activities mainly concerned infilling and optimizations activities at the ROD field (Eni operator with a 66% interest). The main fields in block 403 are BRN, BRW and BRSW, which accounted for approximately 9% of Eni’s production in Algeria in 2016. The main fields in block 404 are HBN and HBNS and satellites, which accounted for approximately 21% of Eni’s production in Algeria in 2016. Production in block 405b comes mainly from MLE and CAFC projects and accounted for approximately 13% of Eni’s production in the country in 2016. Production start-up was achieved at the CAFC oil project at the end of the year, with start-up of 6 wells and linkage at the treatment facilities of the area. The development activities are expected to complete during 2017. Development and optimization activities progressed at the MLE and CAFC gas fields by means of construction and infilling activities, as well as production optimization. The El-Merk field is the main production project in the block 208 and accounted for approximately 18% of Eni’s production in Algeria in 2016. Egypt. Eni has been present in Egypt since 1954. In 2016, Eni’s share of production in this country amounted to 170 KBOE/d and accounted for 10% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Melehia (Eni’s interest 76%) and the Ras Qattara (Eni’s interest 75%) concessions. Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (Eni’s interest 50%), Baltim (Eni’s interest 50%), Ras el Barr (Eni’s interest 50%, non operated) and the Abu Madi West (Eni’s interest 75%), located offshore the Nile Delta. In 2016, production from these large concessions accounted for approximately 98% of Eni’s production in Egypt. Exploration and production activities in Egypt are regulated by Production Sharing Agreements. In February 2016, the Egyptian Ministry of Petroleum and Mineral Resources approved the award to Eni the Zohr Development Lease that allows the start-up of the development program at the Zohr gas field in the operated Shorouk concession (Eni’s interest 100%) and, as a consequence, the FID was sanctioned and added proved undeveloped reserves for the field. The first gas is expected at the end of 2017. Based on the production test, delineation and development drilling activities management believes that this discovery contains a large amount of gas resources. Drilling activities will continue in 2017 together with construction activities of onshore gas treatment plant and offshore facilities installation. In 2016, Eni signed two agreements to sell a 40% overall interest in the Shorouk concession. The agreements concerned the sale of: (i) a 10% interest to BP for a consideration amount of $375 million and the pro-quota reimbursement of past expenditures, which amount so far at approximately $150 million; and (ii) a 30% interest to Rosneft for a consideration amount of $1.125 million and the pro-quota reimbursement of past expenditures, which amount so far at approximately $450 million. In addition, the new partners have an option to buy a further 5% interest under the same terms. In February 2017, Eni signed a deed completing the sale of 10% interest to BP, with all authorizations from Egypt’s authorities. The sale agreement with Rosneft will be finalized in the first half of 2017 and subject to necessary authorizations from the country’s authorities. During the year targeting production of 85.5 KBOE/d net to Eni was achieved at the Nidoco NW field and satellites as a part of the Great Nooros Area project in the Abu Madi West concession. The start-up was achieved in 13 months following the announcement of the commercial discovery in July 2015 by means of the exploration successes in the Nooros area and the drilling of the new development wells. Production plateau of 160 KBOE/d is expected in 2017 with the completion of ongoing development activities. 49 development (i) ongoing activity of activities Other concerned: the sub-sea END Phase 3 development project in the Ras El Barr concession (Eni’s interest 50%) with the drilling and completion of infilling activities and production optimization at the Sinai 12 (Eni’s interest 100%), Ashrafi (Eni’s interest 25%) and Meleiha (Eni’s interest 76%) to support production capacity; (iv) start-up of the in the onshore gas Meleiha concession. treatment plant concessions two wells; (ii) In December 2016 Concession Agreements were ratified for the North El Hammad (Eni operator with a 37.5% interest) and North Ras El Esh (Eni’s located in the interest 50%) blocks, conventional the Mediterranean Sea. offshore of Exploration activity yielded positive results with the delineation drilling activity of the Baltim South West (Eni operator with a 50% interest), nearby the Great Nooros Area. Based on this ongoing activity management believes that this discovery contains an important gas resource. In the medium term, management expects to increase Eni’s production reflecting additions from ongoing development projects. Libya. Eni started operations in Libya in 1959. In recent years, Eni’s production levels in Libya were negatively impacted by an internal revolution and a change of regime in 2011, which led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political development forced Eni to temporarily interrupt or reduce its production activities, negatively affecting Eni’s results of operations and cash flow until the situation began to stabilize. Although our production levels in Libya since 2015 have returned to the levels achieved prior to the outbreak of the civil war, the geopolitical situation remains unstable and unpredictable. In 2016, Eni’s facilities in Libya produced on average 346 KBOE/d, registering a decrease of approximately 3% compared to 2015. For further information on this matter, see “Item 3 – Risk factors”. Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%). In the exploration phase, Eni is operator in the onshore contract Areas A, B and offshore Area D. Exploration and production activities in Libya are regulated by six Exploration and Production Sharing Agreement contracts (EPSA). The licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil&gas properties, respectively. 50 Development activities concerned: (i) planned facilities downtime at the Mellitah treatment plant, the Sabratha production platform and treatment facilities of the Western Libyan Gas Project; (ii) positioning and installation activities as well as linkage of the new FSO unit at the Bouri production field and start-up at the beginning of 2017; (iii) a second development phase of the Bahr Essalam field (Eni’s interest 50%) with the completion of 10 offshore wells of which 9 wells already drilled in 2016. The EPCI contract was awarded to supply and installation of flowlines. First gas is expected in 2018; and (iv) the linkage of one additional production wells at the Wafa field (Eni’s interest 50%) and activities in order to mitigate the natural production decline in the area. Morocco. In March 2016, Eni signed a Farm-Out Agreement (FOA) with Chariot Oil & Gas that includes the operatorship to Eni and a 40% stake enter into Rabat Deep Offshore exploration permits I-VI offshore Morocco. In October 2016, the relevant country’s Authorities approved the agreement. Tunisia. Eni has been present in Tunisia since 1961. In 2016, Eni’s production amounted to 10 KBOE/d. Eni’s activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet. Exploration and production in this country are regulated by concessions. Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni’s interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), Djebel Grouz (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks. Production optimization represents the main activity currently performed in the above listed concessions to mitigate the natural field production decline. Exploration activities yielded positive results with the Larich Est-1 discovery well, which put into production through a tie-in to the existing treatment facilities of the MLD concession. Sub-Saharan Africa Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In 2016, Sub-Saharan Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas. Angola. Eni has been present in Angola since 1980. In 2016, Eni’s production averaged 112 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore. The main Eni’s asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest) with the West Hub project, where production started up in 2014 and the East Hub development project with production start-up achieved in February 2017. Eni participates in other producing blocks: (i) Block 0 in Cabinda (Eni’s interest 9.8%) north of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; (iv) the Lianzi Development Area in the Block 14 K/A IMI (Eni’s interest 10%), where a unitization was implemented with the Congo-Brazzaville area; and (v) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin. Eni retains interests in other non-producing concessions, particularly the Block 35/11 (Eni operator with a 30% interest), Block 3/05-A (Eni’s interest 12%), onshore Cabinda North block (Eni’s interest 15%) and the Open Areas of Block 2 assigned to the Gas Project (Eni’s interest 20%). Exploration and production activities in Angola are regulated by concessions and PSAs. The development program of the West Hub project plans to hook up the Block’s discoveries to the N’Goma FPSO in order to support production plateau. In 2016, production start-up was achieved at the M’Pungi and M’Pungi North fields, with a production ramp-up of approximately 81 KBBL/d (approximately 28 KBBL/d net to Eni) in the area. Planned activities included to be put into production 5 additional discoveries. 51 In 2017, February production start-up was achieved at the East Hub project by means of the linkage of Cabaça South East field to the FPSO Armada Olombendo. In the Block 15/06, with the the East Hub project, completion of production derived from five fields. Management plans to put into production two additions discoveries by the end of 2018. Early production phase started up at the Mafumeira Sul project in the Block 0. Development activities progressed, with the completion expected during 2017 and a peak production of 100 KBOE/d. (i) development the completion of activities Other the concerned: Congo River Crossing project to supply gas production of Block 0 and 14 to Angola LNG liquefaction plant (Eni’s interest 13.6%) which started up in April 2016 with a production of 6 KBOE/d net to Eni; and (ii) development program of the Kizomba satellites Phase 2 (Eni’s interest 20%) which will be started up leveraging on the production and treatment facilities in the area. In the medium term, management expects to increase Eni’s production to 146 KBOE/d reflecting additions from ongoing development projects. Congo. Eni has been present in Congo since 1968. In 2016, production averaged 92 KBOE/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. Eni’s main operated oil producing interests in Congo are the Zatchi (Eni’s interest 56%), Loango (Eni’s interest 42.5%), Ikalou (Eni’s interest 100%), Djambala (Eni’s interest 50%), Foukanda and Mwafi (Eni’s interest 58%), Kitina (Eni’s interest 52%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Nené Marine (Eni 65%), Zingali and Loufika (Eni’s interest 100%) fields. 52 Other relevant not operated producing areas are represented by a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits. Exploration and production activities in Congo are regulated by Production Sharing Agreements. 2016, In December production ramp-up was achieved at the Nené Marine field with the completion of the second development phase, sanctioned in 2015. Development activities progressed at the Litchendjili production field and during the year peak production of approximately 16 KBOE/d was achieved. Gas production feeds the CEC power plant (Eni’s interest 20%). In the medium term, management expects to maintain production on the present level. Ghana. Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni’s interest 44.44%) permits which is regulated by a concession agreement. The license expires in 2036. Development activities concerned the OCTP integrated oil&gas development plan to put into production the Sankofa, Sankofa East and Gye Nyame discoveries. First oil is expected in 2017 and first gas in 2018. In 2016, the drilling activity of 18 development wells was completed and the renovation of a FPSO unit was performed. Contracts were awarded for the installation of sea-lines and the construction of onshore gas plant. In March 2016, Eni was awarded the operatorship of the exploration license Cape Three Points Block 4 (Eni’s interest 42.47%), located in the offshore of the country. Mozambique. Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 located in offshore Rovuma Basin block, the north of the country. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The other partners in Area 4 are Galp, Kogas, ENH with a participating interest of 10% each and 20% indirect CNPC that through its participation in Area participation in the shareholding of Eni East Africa. holds 4 a In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by Anadarko. In 2012, Eni made the Coral gas discovery which falls entirely in Area 4. 53 During the exploration period, which has expired in 2015, six Discovery Areas (DA) were identified in Area 4. Pursuant to the Decree Law 02/2014 multiple 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 Government of Mozambique will give right to a Development and Production Period of the duration of 30 years, further extendable pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law. Eni also operates the exploration offshore Block A-5A (Eni’s interest 34%), in the deep offshore of Zambesi. In March 2017, ExxonMobil and Eni signed sale and purchase agreement to acquire a 25% indirect interest in the Area 4 block, offshore Mozambique. The agreed terms include a cash price of approximately $2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Following completion of the transaction, Eni East Africa will be co-owned by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by CNPC. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore. This operating model will enable the use of best practices and skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project. The first plan of development was submitted to the Government of Mozambique in December 2014 in relation to the initial exploitation of the Coral gas resources. The Coral South Development Plan, which was approved by the Government in February 2016, envisages the installation of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG - FLNG) with a capacity of over 3.3 mmtonnes/y fed by 6 subsea wells. Eni expects to produce up to 5 TCF of gas with a start-up expected in mid-2022. In October 2016, Eni and its Area 4 partners signed a binding agreement with BP for the sale of the entire volumes of LNG produced by the Coral South Project, for a period of over twenty years. In November 2016, Eni’s Board of Directors approved the investment for the first development phase of the Coral discovery. The FID on the project will turn effective once all Area 4 partners sanctioned it and the project financing, which is currently being finalized, will be underwritten. The development plan of the Mamba project, comprises construction of two onshore LNG trains with a combined capacity of 10 mmtonnes/y and the drilling of 16 subsea wells, with start-up in 2023. Eni expects to produce up to 14 TCF of gas according to its independent industrial plan, coordinated with the operator of Area 1 (Anadarko). The FID is expected in 2018. Nigeria. Eni has been present in Nigeria since 1962. In 2016, Eni’s oil&gas production averaged 112 KBOE/d located mainly onshore and offshore the Niger Delta. In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%) and OPL 245 (Eni’s interest 50%), holding interests in OML 118 (Eni’s interest 12.5%) and in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the country, Eni also holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% interest in 2 conventional offshore blocks. In the exploration phase Eni operates offshore OML 134 (Eni’s interest 85%), OPL 2009 (Eni’s interest 49%), and onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in OML 135. Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for State-owned Company. 54 of sitting request issued by Federal On January 27, 2017, subsidiary Nigerian Eni’s Ltd Exploration Agip became aware of an Interim Attachment Order (“Order”) the High Nigerian in Abuja, Court, from the upon Economic and Financial Crime Commission (EFCC), attaching the property OPL 245, pending the Nigerian proceeding. Both Eni and Shell made prompt application to discharge the Order. On March 17, 2017, the Court discharged the Order. On that basis, management has no concluded impairment of the asset was required. After the inception of the judicial proceeding in Italy, which dates back to July 2014, Eni’s Board of jointly Statutory Auditors with the Eni Watch Structure has engaged a US leading law firm to perform an independent review of the issue. Based on the outcome of this review, during which the law firm appointed by Eni has also assessed material and the information made available from the judicial authorities, no wrongdoing has been detected on Eni side in the awarding process to Eni of the license. Nigerian that a The development activities concerned: (i) drilling activity and production start-up of three additional wells, two production and one water-injection, at the Bonga field in the OML 118 block; (ii) the drilling campaign within the integrated project in the Gbaran-Ubie area in the OML 28 block (Eni’s interest 5%), aimed to supply natural gas to the Bonny liquefaction plant. Start-up was achieved in the second half of 2016; and (iii) the OML 43 block (Eni’s interest 5%), where the development plan of the Forcados-Yokri field provides hook-up the last 12 of 23 production wells already drilled, the upgrading of existing flowstations and the construction of transport facilities. Start-up is expected in the first half of 2017. Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant is operational, with a treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. Natural gas supplies to the plant are currently provided under gas supply agreements with an expiring date in fifteen years from the SPDC JV and the NAOC JV (operating the OMLs 60, 61, 62 and 63 blocks) with an average amount of approximately 2,825 mmCF/d for the next four years (approximately 265 mmCF/d net to Eni corresponding to approximately 49 KBOE/d). LNG production is sold under long-term contracts and exported to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co. In January 2017, Eni signed with the Nigerian National Petroleum Corporation (NNPC) a Memorandum of Understanding, which strengthen cooperation in the energy sector. Kazakhstan Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2016, Eni’s operations in Kazakhstan accounted for 6% of its 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 55 the Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources, which will eventually be developed in phases. The NCSPSA expires at the end of 2041. In addition to Eni, the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, CNPC with 8.33%, and Inpex with 7.56%. the partners of On September 28, 2016, production re-started at the Kashagan field with the completion of works to fully replace the damaged pipelines following the gas leak occurred at the end of 2013. The production of 180 KBOE/d was achieved by year-end (31 KBOE/d net to Eni). The production capacity of 370 KBBL/d planned for the Phase 1 is expected to be achieved during 2017, when gas reinjection comes online. The Phase 1 includes a further increase available production capacity up to 450 KBBL/d by installing additional gas compression capacity for reinjection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities. Management believes that significant capital expenditures will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and subsequent to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures. In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets. As of December 31, 2016, Eni’s proved reserves booked for the Kashagan field amounted to 608 mmBOE, barely unchanged from 2015. As of December 31, 2015, Eni’s proved reserves booked for the Kashagan field amounted to 611 mmBOE, recording an increase of 31 mmBBL compared to 2014 mainly due to lower marker Brent price. As of December 31, 2014, Eni’s proved reserves booked for the Kashagan field amounted to 580 mmBOE, barely unchanged compared to 2013. As of December 31, 2016, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.7 billion (€9.2 billion at the EUR/USD exchange rate of December 31, 2016). This capitalized amount included: (i) $7.2 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.5 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years. As of December 31, 2015, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.2 billion (€8.4 billion at the EUR/USD exchange rate of December 31, 2015). This capitalized amount included: (i) $6.8 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.4 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years. 56 in Karachaganak. Located onshore 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 is interest 29.25%. in the Karachaganak project of In 2016, production the Karachaganak field averaged 231 KBBL/d of liquids (61 KBBL/d net to Eni) and 867 mmCF/d of natural gas (230 mmCF/d net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 51%) at the Russian gas plant in Orenburg and the remaining volumes is utilized for re-injecting in the higher layers and the production of fuel gas. Approximately 91% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 250 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara remaining pipeline. The of non-stabilized production liquid (approximately 16 KBBL/d) are marketed at the Russian terminal in Orenburg. volumes The Expansion Project is currently under study. The project targets to install, in stages, the gas treatment plants and re-injection facilities to support liquids’ production profile. The development plan is currently in the phase of technical and marketing definition of its first development phase, aimed to increase the capacity of gas re-injection. As of December 31, 2016, Eni’s proved reserves booked for the Karachaganak field amounted to 613 mmBOE, reporting an increase of 26 mmBOE from 2015 mainly due to lower marker Brent price. As of December 31, 2015, Eni’s proved reserves booked for the Karachaganak field amounted to 587 mmBOE, reporting an increase of 98 mmBOE from 2014 mainly due to lower marker Brent price. As of December 31, 2014, Eni’s proved reserves booked for the Karachaganak field amounted to 489 mmBOE, barely unchanged compared to 2013. Rest of Asia In 2016, Eni’s operations in the Rest of Asia accounted for 7% of its total worldwide production of oil and natural gas. China. Eni has been present in China since 1984 with activities located in the South China Sea. In 2016, Eni’s production amounted to 2 KBOE/d. Exploration and production activities in China are regulated by Production Sharing Agreements. In 2016, hydrocarbons were produced from the offshore Blocks 16/19 through 3 platforms connected to an FPSO. 57 Indonesia. Eni has been present in Indonesia since 2001. In 2016, Eni’s production mainly composed of gas, amounted to 14 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 14 blocks. Exploration and production activities in Indonesia are regulated by PSAs. In 2016 production start-up was achieved at the Bangka project (Eni’s interest 20%) in the East Kalimantan. The ongoing development activities that will ensure gas supplies to the Bontang liquefaction plant include the Jangkrik project (Eni operator with a 55% interest) in the Kalimantan offshore. This project is in the final execution phase with all the deep-offshore development subsea wells already drilled and the Floating Production Unit for gas and condensate treatment in the final stage of construction, as well as the construction of transportation and receiving facilities onshore. Production start-up is planned in 2017. Exploration activities yielded positive results with appraisal activities at the Merakes gas discovery in the deep offshore of the East Sepinggan block (Eni operator with an 85% interest), nearby the Jangkrik project. Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companies and the national oil company Missan Oil, holds a 41.6% interests in the Zubair oil field. Development and production activities at the Zubair field are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to Production Sharing contracts. In 2016, production of the Zubair field averaged 64 KBBL/d net to Eni. At the beginning of March 2016, three new generation plants for the oil, gas and water treatment (Initial Production Facilities - IPF) started. Those plants together with 5 existing restructured and modernized plants increased oil and natural gas treatment capacity of Zubair field to approximately 650 KBBL/d and will ensure the maximization of the associated gas utilization. In addition, these new facilities have also a water re-injection capacity of approximately 300 KBBL/d that will boost the Zubair’s hydrocarbons production and will achieve production plateau. The first stage of development activities (Rehabilitation Plan) of the Zubair field were completed with start-up of these new facilities. Ongoing development (Enhanced Redevelopment Plan) of the Zubair field, to achieve a production plateau of 700 KBBL/d and will ensure the application of associated gas to power generation. concerned an additional development phase activities Myanmar. Eni has been present in Myanmar since 2014. Eni is operator of four Production Sharing Contracts; two onshore blocks RSF-5 and PSC-K (Eni’s interest 90% in both leases) and two offshore blocks MD-02 and MD-04 (Eni’s interest 40% in both leases). The contracts foresee, for the onshore blocks, an exploration period of six years subdivided into three phases and for the offshore blocks a study period of two years, followed by an exploration period of six years, subdivided in 3 phases. Pakistan. Eni has been present in Pakistan since 2000. In 2016, Eni’s production mainly composed of gas amounted to 30 KBOE/d. Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore). Eni’s main permits in the country are Bhit/Bhadra (Eni operator with a 40% interest), Latif (Eni’s interest 33.33%) and Zamzama (Eni’s interest 17.75%), which in 2016 accounted for 79% of Eni’s production in Pakistan. 58 Production optimization through drilling activities of new development wells represents the main activity currently performed in the above listed fields to mitigate the natural field production decline. Russia. Eni has been present in Russia through three joint ventures with Rosneft for the development of Fedynsky and Central Barents licenses (Eni’s interest 33.33%) located in the Russian Barents Sea and Western Chernomorsky license (Eni’s interest 33.33%) in the Black Sea since 2013. Following the adoption of EU sanctions measures relating to the upstream sector in Russia, Eni started the required authorization before competent Authorities of the Member States of the European Union who granted the Company and the joint ventures between Eni and Rosneft certain authorization for the execution and financing of the exploration activities in Russia, under the terms of contracts entered into force before the enactment of the relevant sanctions. The current sanctions have delayed and will continue to affect the timing of implementation of the projects. For further information on this matter, see “Item 3 – Risk factors”. Turkmenistan. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the country. The license expires in 2032. In 2016, Eni’s production averaged 9 KBOE/d. Exploration and production activities in Turkmenistan are regulated by PSAs. Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap arrangement with the Turkmen Authorities, an equivalent amount of oil at the Okarem terminal, close to the South coast of the Caspian Sea. Eni’s entitlement is sold FOB. Associated natural gas is used for gas lift system. The remaining amount is delivered to the national oil company Turkmenneft, via national grid. Production optimization represents the main activity currently performed in the area to mitigate the natural field production decline. Vietnam. Eni has been present in Vietnam since 2012 and is operator of five offshore Production Sharing Contracts, two of which are held with 100% interest (Block 116 and Block 122) and three are in Joint Venture (Block 114 Eni’s interest 50%, Block 120 - Eni’s interest 66.67%, Block 124 - Eni’s interest 60%). Americas In 2016, Eni’s operations in Americas area accounted for 10% of its total worldwide production of oil and natural gas. Ecuador. Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni’s interest 100%) located in the Oriente Basin, in the Amazon forest. In 2016, Eni’s production averaged 11 KBBL/d. Exploration and production activities in Ecuador are regulated by a service contract that expires in 2033. Block 10 production is processed by a Central Production Facility and transported to the Pacific Coast through a pipeline network. In December 2016, development activities of the Villano Phase VI project started up with the drilling of the first of two infilling wells. 59 Mexico. Eni has been present in Mexico since 2015. Eni is operator of the Block 1 (Eni’s interest 100%) to develop the Amoca, Miztón and Tecoalli fields, located in the Gulf of Mexico shallow waters. The delineation campaign of the fields was submitted to the Mexican Authorities in the first quarter of 2016 and plans the drilling of four wells track and synergic in order to define a fast development plan. In January 2017, the delineation campaign started with the first well. Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2016, Eni’s production averaged 70 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block, located offshore North of Trinidad. Exploration and production activities in Trinidad and Tobago are regulated by PSAs. Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields. Production is supported by two fixed platforms linked to the Hibiscus processing facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant on Trinidad’s coast and it is sold under long-term contracts with prices linked to the United States, as well as alternative destinations markets. United States. Eni has been present in the United States since 1968. Activities are performed in the shallow and deep offshore of the Gulf of Mexico, onshore and offshore in Alaska, and in Texas onshore. In 2016, Eni’s oil&gas production was 91 KBOE/d mainly from the Gulf of Mexico and Alaska fields. Exploration and production activities in the United States are regulated by concessions. Eni holds interests in 84 exploration and production blocks in the Gulf of Mexico, of which 44 are operated by Eni. The main operated fields are Allegheny and Appaloosa (Eni’s interest 100%), Pegasus (Eni’s interest 85%), Longhorn, Devils Towers and Triton (Eni’s interest 75%). Eni also holds interests in Europa (Eni’s interest 32%), Hadrian South (Eni’s interest 30%), Medusa (Eni’s interest 25%), Lucius (Eni’s interest 8.5%), K2 (Eni’s interest 13.4%), Frontrunner (Eni’s interest 37.5%) and Heidelberg (Eni’s interest 12.5%) fields. 60 During the year, production start-ups were achieved in the Gulf of Mexico at: (i) the Heidelberg field (Eni’s interest 12.5%) in the deep-water Gulf of Mexico, with a production of approximately 3 KBOE/d net to Eni. During 2017 planned development activities will be completed; (ii) the Phase 2 development of Lucius field (Eni’s interest 8.5%) with production ramp-up to 100 KBOE/d (8 KBOE/d net to Eni); and (iii) the Devil’s Tower South-West production well within the development program of the operated Devil’s Tower field, with a production of approximately 2 KBOE/d. To achieve the highest safety standards of operations, Eni became a member of the HWCG Consortium of Gulf of Mexico operators. The HWGC provides resources, coordination and performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. For further information on this matter, see “Item 3 – Risk factors”. Eni holds interests in 43 exploration and development blocks in Alaska, with interests ranging from 30 to 100%; Eni is the operator in 27 of these blocks. Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) fields with a 2016 overall net production of approximately 24 KBBL/d. In Texas onshore, Eni’s production comes from the Alliance Area (Eni’s interest 27.5%). Venezuela. Eni has been present in Venezuela since 1998. In 2016, Eni’s production averaged 60 KBOE/d. Activity is concentrated both offshore (Gulf of Venezuela and Gulf of Paria) and onshore in the Orinoco Oil Belt. Exploration and production of the oil Junin 5 and Corocoro fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP). The Perla gas field is operated by Cardon IV, a joint venture 50%-50% Eni and Repsol. Eni’s production comes from the giant Perla gas field (Eni’s interest 50%), in the Gulf of Venezuela, the Corocoro field (Eni’s interest 26%), in the Gulfo de Paria, and the Junin 5 oil field (Eni’s interest 40%), located in the Orinoco Oil Belt. Development activities performed in 2016 were: (i) ongoing drilling activities at the Junin 5 oil field. The production level at year-end was approximately 18 KBBL/d at 100%. Possible optimization of development program is currently under evaluation; and (ii) the completion of the first development phase at the Perla field. The six wells currently on stream are producing approximately 540 mmCF/d at 100%. The gas will be mainly used by PDVSA for the domestic market, under the Gas Sales Agreement in place until 2036. The Perla project includes two additional development phases to achieve a production plateau of approximately 1,200 mmCF/d. Eni is also participating with a 19.5% interest in Petrolera Güiria for oil exploration and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest for gas exploration, both located offshore in the eastern Venezuela. Australia and Oceania Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2016, the area of Australia and Oceania accounted for 1% of Eni’s total worldwide production of oil and natural gas. Australia. Eni has been present in Australia since 2001. In 2016, Eni’s production of oil and natural gas averaged 23 KBOE/d. Activities are focused on conventional and deep offshore fields. 61 Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs. The main production blocks in which Eni holds interests are WA-33-L (Eni’s interest 100%) and JPDA 03-13 (Eni’s interest 10.99%). In the appraisal and development phase Eni holds interests in NT/RL8 (Eni’s interest 100%) and NT/RL7 (Eni’s interest 32.5%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment” Disclosure pursuant to Section 13(r) of the Exchange Act The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. As of December 31, 2016, Eni outstanding trade receivables amounted to $278 million towards the National Iranian National Oil Co (NIOC) which were recorded in connection with the settlement agreement recognized in 2015. This amount was curtailed from the amount outstanding at December 31, 2015 ($339 million). The State counterparties expressed their willingness to negotiate a repayment plan of overdue receivables based on arrangements relating the sale of volumes of the Iranian counterpart equity crude and the attribution to Eni of a percentage of the sale proceeds. This agreement has been enacted in the last months of 2016 with a reimbursement to Eni of $44 million. Negotiations are underway to identify additional crude volumes to be marketed, some of which have already been awarded to Eni in early 2017, fully recovering the overdue amounts. Eni had no payables towards NIOC as of with the aim of December 31, 2016. Eni made payments in the region of $1 million to the Iranian Social Security Organization in connection to health and social security insurance for which Eni retains at the balance sheet date a residual payable amounting to $10 million date, which will be settled upon termination of our presence in the country. Gas & Power Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply/marketing and trading. This segment also includes the activities of electricity generation. In 2016, Eni’s worldwide sales of natural gas amounted to 88.93 BCM, including 2.62 BCM of gas sales made directly by Eni’s Exploration & Production segment. Sales in Italy amounted to 38.43 BCM, while sales in European markets were 42.43 BCM that included 4.37 BCM of gas sold to certain importers to Italy. In the Gas & Power segment we expect a continuing weak outlook for natural gas sales and prices due to structural headwinds in the industry as we forecast oversupplies and strong competition across all of our main markets in Europe, including Italy. Supply of natural gas In 2016, Eni’s consolidated subsidiaries supplied 82.64 BCM of natural gas, down by 2.75 BCM, or 3.2% from 2015. Gas volumes supplied outside Italy (76.64 BCM from consolidated companies), imported 62 in Italy or sold outside Italy, represented approximately 93% of total supplies, down by 2.02 BCM, or 2.6% compared to the previous year, due to lower volumes purchased in Libia (down 2.38 BCM), Russia (down 2.34 BCM) and in the Netherlands (down 2.13 BCM), partly offset by higher volumes purchased in Algeria (up 6.85 BCM). Supplies in Italy (6.00 BCM) decreased from 2015 (down 0.73 BCM or 10.8%) due to the production shutdown in the Val d’Agri district during the period April-August 2016. In 2016, main gas volumes from equity production derived from: (i) Italian gas fields (4.5 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.2 BCM); (iii) Libyan fields (1.5 BCM); (iv) the United States (1.4 BCM); and (v) other European areas (0.2 BCM). Considering also direct sales of the Exploration & Production segment and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 15.02 BCM representing 17% of total volumes available for sale. The table below sets forth Eni’s purchases of natural gas by source for the periods indicated. Natural gas supply 2014 2015 2016 Italy .................................................................................................... Outside Italy ........................................................................................ Russia ................................................................................................. Algeria (including LNG) ........................................................................ Libya .................................................................................................. the Netherlands ..................................................................................... Norway ............................................................................................... the United Kingdom .............................................................................. Hungary .............................................................................................. Qatar (LNG) ....................................................................................... Other supplies of natural gas ................................................................... Other supplies of LNG ........................................................................... Total supplies of subsidiaries ................................................................... Withdrawals from (input to) storage ....................................................... Network losses, measurement differences and other changes ...................... Volumes available for sale of Eni’s subsidiaries .......................................... Volumes available for sale of Eni’s affiliates .............................................. E&P volumes ........................................................................................ (BCM) 6.73 78.66 30.33 6.05 7.25 11.73 8.40 2.35 0.21 3.11 7.21 2.02 85.39 (0.34) 85.05 2.67 3.16 6.92 75.99 26.68 7.51 6.66 13.46 8.43 2.64 0.38 2.98 5.56 1.69 82.91 (0.20) (0.25) 82.46 3.65 3.06 6.00 76.64 27.99 12.90 4.87 9.60 8.18 2.08 0.02 3.28 5.81 1.91 82.64 1.40 (0.21) 83.83 2.48 2.62 Total volumes available for sale ............................................................... 89.17 90.88 88.93 Sales of natural gas In 2016, natural gas sales amounted to 88.93 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico), representing a decrease of 1.95 BCM, or 2.1% from the previous year. Sales in Italy were barely unchanged (38.43 BCM); lower volumes in the wholesale and residential segment were partly offset by higher spot volumes. Sales in the European markets were 38.06 BCM, down by 0.6% from 2015. Direct sales of Exploration & Production segment in Europe and the Gulf of Mexico (2.62 BCM) decreased by 0.54 BCM due to lower volumes marketed in the United Kingdom and the United States, partially offset by higher sales in Norway. Sales to long-term buyers were down by 5.2% compared to the previous year, due to shorter availability of Libyan output as well as lower sales to Extra European markets (down by 14.7%) driven by lower LNG volumes marketed in the Far East, due to the lack of contracts renewal. 63 The tables below set forth Eni’s sales of natural gas by principal market for the periods indicated. Natural gas sales by entities 2014 2015 2016 Total sales of subsidiaries ....................................................................... Italy (including own consumption) ........................................................... Rest of Europe ...................................................................................... Outside Europe ..................................................................................... Total sales of Eni’s affiliates (Eni’s share) ................................................. Italy .................................................................................................... Rest of Europe ...................................................................................... Outside Europe ..................................................................................... Total sales of G&P ................................................................................ E&P in Europe and in the Gulf of Mexico(a) ............................................ Worldwide gas sales ............................................................................... 81.73 34.04 43.07 4.62 4.38 3.15 1.23 86.11 3.06 89.17 (BCM) 84.94 38.44 41.14 5.36 2.78 1.75 1.03 87.72 3.16 90.88 83.34 38.43 40.52 4.39 2.97 1.91 1.06 86.31 2.62 88.93 (a) E&P sales include volumes marketed by the Exploration & Production segment in Europe (2.60, 2.75 and 2.32 BCM in 2014, 2015 and 2016, respectively) and in the Gulf of Mexico (0.46, 0.41 BCM and 0.30 in 2014, 2015 and 2016, respectively). Natural gas sales by market 2014 2015 2016 ITALY ................................................................................................ Wholesalers ......................................................................................... Italian gas exchange and spot markets ..................................................... Industries ............................................................................................ Medium-sized enterprises and services .................................................... Power generation .................................................................................. Residential ........................................................................................... Own consumption ................................................................................ INTERNATIONAL SALES .................................................................. Rest of Europe ...................................................................................... Importers in Italy ................................................................................. European markets ................................................................................ Iberian Peninsula .................................................................................. Germany/Austria .................................................................................. Benelux ............................................................................................... Hungary .............................................................................................. United Kingdom/Northern Europe ........................................................... Turkey ................................................................................................. France ................................................................................................. Other .................................................................................................. Extra European markets ........................................................................ E&P in Europe and in the Gulf of Mexico ................................................ WORLDWIDE GAS SALES ................................................................ 34.04 4.05 11.96 4.93 1.60 1.42 4.46 5.62 55.13 46.22 4.01 42.21 5.31 7.44 10.36 1.55 2.94 7.12 7.05 0.44 5.85 3.06 89.17 (BCM) 38.44 4.19 16.35 4.66 1.58 0.88 4.90 5.88 52.44 42.89 4.61 38.28 5.40 5.82 7.94 1.58 1.96 7.76 7.11 0.71 6.39 3.16 90.88 38.43 3.83 17.08 4.54 1.72 0.77 4.39 6.10 50.50 42.43 4.37 38.06 5.28 7.81 7.03 0.93 2.01 6.55 7.42 1.03 5.45 2.62 88.93 European markets A review of Eni’s presence in the key European markets is presented below. 64 Benelux. Eni holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, through the Belgium Gas & Power branch, and its significant exposure to spot markets in Western Europe. Furthermore Eni operates in the retail and middle market through its subsidiary. In 2016, sales in Benelux amounted to 7.03 BCM (7.94 BCM in 2015), down by 0.91 BCM, or 11.5%. France. Eni sells natural gas to industrial clients and wholesalers, as well as to the segments of retail and middle market. Eni is present in the French market through its direct commercial activities and through its subsidiary. In 2016, sales in France amounted to 7.42 BCM (7.11 BCM in 2015), an increase of 0.31 BCM, or 4.4%, from a year ago. Germany-Austria. Eni operates in Germany-Austria through its direct commercial activities and through its subsidiaries. In 2016, total sales in Germany-Austria amounted to 7.81 BCM, an increase of 1.99 BCM, or 34.2%. The LNG business Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from Qatar, Nigeria, Oman and Algeria. In the plan period, Eni intends to develop its LNG business leveraging on the integration with the E&P segment and the valorization of the equity gas. In 2017, the G&P LNG business will start marketing volumes of gas produced at the E&P large Jangkrik gas complex, off Indonesia. Final markets of that gas include the Chinese market and other areas. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities. LNG sales 2014 2015 2016 G&P sales ........................................................................................... Rest of Europe ..................................................................................... Extra European markets ........................................................................ E&P sales ............................................................................................ Liquefaction plants: - Soyo (Angola) .................................................................................... - Bontang (Indonesia) ........................................................................... - Point Fortin (Trinidad & Tobago) ......................................................... - Bonny (Nigeria) ................................................................................. - Darwin (Australia) .............................................................................. (BCM) 9.0 4.8 4.2 4.5 0.5 0.7 2.8 0.5 8.9 5.0 3.9 4.4 0.1 0.5 0.6 2.8 0.4 8.1 5.2 2.9 4.3 0.1 0.4 0.7 2.6 0.5 13.3 13.5 12.4 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 middle to large industrial users, the Company has been developing a commercial offer that provides the combined supply of gas, power and fuels. In 2016, power sales (37.05 TWh) were directed to the free market (74%), the Italian Power Exchange (15%), industrial sites (9%) and others (2%). Compared to 2015, electricity sales were up by 6.2%, due to higher volumes sold to wholesalers and middle market, partially offset by lower volumes traded to small and medium size enterprises and large clients. 65 Power availability 2014 2015 2016 Power generation sold ........................................................................... Trading of electricity (a) ......................................................................... Power sales by market Free market (a) ..................................................................................... Italian Exchange for electricity ............................................................... Industrial plants ................................................................................... Other (a) .............................................................................................. (TWh) 20.69 14.19 34.88 25.90 5.09 3.23 0.66 34.88 19.55 14.03 33.58 24.86 4.71 3.17 0.84 33.58 21.78 15.27 37.05 27.49 5.64 3.11 0.81 37.05 (a) Include positive and negative imbalances (differences between power introduced in the grid and the one planned). Power generation Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. In 2016, power generation was 21.78 TWh, up by 1.09 TWh, or 5.3% from 2015, mainly due to higher production at Brindisi, Ferrara, Ferrera Erbognone and Ravenna plants following increasing demand. As of December 31, 2016, installed operational capacity was 4.7 GW (4.9 GW as of December 31, 2015). Electricity trading reported an increase to 15.27 TWh, due to higher purchases on the spot market (up 7.6%) reflecting the optimization of inflows and outflows of power. Site Brindisi ............................................................................. Ferrera Erbognone ............................................................. Livorno (a) ......................................................................... Mantova ........................................................................... Ravenna ............................................................................ Ferrara (b) ......................................................................... Bolgiano ........................................................................... Total installed capacity in 2016 (GW) 1.3 1.0 - 0.8 1.0 0.4 0.1 4.7 Technology Fuel gas CCGT CCGT gas/syngas gas/fuel oil gas gas gas gas Power station CCGT CCGT CCGT Power station (a) (b) Since March 1, 2016 Livorno was tranferred to R&M segment. Eni’s share of capacity. Power generation 2014 2015 2016 Purchases Natural gas .................................................................................. Other fuels ................................................................................... - of which steam cracking ............................................................... Production Electricity .................................................................................... Steam ......................................................................................... Installed generation capacity .......................................................... (mmCM) (ktoe) (TWh) (ktonnes) (GW) 4,074 338 104 19.55 9,010 4.9 4,270 313 87 20.69 9,318 4.9 4,334 360 105 21.78 7,974 4.7 66 International transport Eni has transport rights on a large European network of integrated infrastructures for transporting natural gas, which links key consumption markets with the main producing areas (Russia, Algeria, Libya and the North Sea). Eni pays 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 to 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 (units) TTPC (Oued Saf Saf-Cap Bon) ............... 2 lines of km 370 5 lines of 155 TMPC (Cap Bon-Mazara del Vallo) .......... GreenStream (Mellitah-Gela) .................. 1 line of km 520 Blue Stream (Beregovaya-Samsun) ............ 2 lines of km 387 Total length Diameter Transport capacity(1) Transit capacity(2) Compression stations (km) 740 775 520 774 (inch) 48 20/26 32 24 (BCM/y) 34.3 33.5 8.0 16.0 (BCM/y) 33.2 33.5 8.0 16.0 (No.) 5 1 1 (1) (2) Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline. The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline. International transport activities The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometer long with a transport capacity of 34.3 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 BCM/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system. The GreenStream pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 BCM/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system. Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”. Refining & Marketing & Chemicals Refining & Marketing Eni’s Refining & Marketing business engages in the supply and refining of crude oil, as well as in the marketing of refined products primarily in Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. Company operations are fully integrated through refining, supply, logistics and marketing in order to maximize cost efficiencies and operational effectiveness. 67 In 2016 refining margins in the Mediterranean area decreased by approximately 50% y-o-y due to a high level of inventories of gasoline and gasoil because of a high utilization rate of refineries as well as availability of products coming from the Middle East. Looking forward, management believes that refining margins in the medium term will remain stable on the 2016 level; in the longer term, margins will improve as a result of the 2020 IMO legislation, which will lead to the substitution of bunker fuel oil with cleaner fuels (gasoil and LNG). In marketing, competition remains tough, in particular from unbranded and large retailers. Supply In 2016, a total of 23.35 mmtonnes of crude were purchased (compared with 24.80 mmtonnes in 2015), of which 3.43 mmtonnes by equity crude oil. The breakdown by geographic area was the following: approximately 43% of purchased crude came from Russian Commonwealth, 30% from the Middle East, 12% from Italy, 11% from North Africa, 1% from West Africa, 1% from North Sea and 2% from other areas. Refining In 2016, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 KBBL/d), with a conversion index of 50%. Conversion index is a measure of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 KBBL/d), with a 49% conversion index. In 2016, Eni’s refineries throughputs in Italy and outside Italy were 24.52 mmtonnes. Refining system in 2016 Balanced refining capacity (Eni’s share) (KBBL/d) Ownership (%) Utilization rate (Eni’s share) (KBBL/d) Conversion index(1) (%) Fluid catalytic cracking (FCC)(2) (KBBL/d) Residue conversion(2) (KBBL/d) Hydro- cracking(2) (KBBL/d) Visbreaking/ Thermal Cracking(2) (KBBL/d) Wholly-owned refineries Italy Sannazzaro Taranto Livorno Partially owned refineries Italy Milazzo Germany Vohburg/Neustadt (Bayernoil) Schwedt Total 100 100 100 50 20 8.33 388 200 104 84 160 100 41 19 548 90 98 73 91 93 90 96 100 90 49 71 38 11 52 60 36 42 50 34 34 143 45 49 49 177 16 16 0 25 25 41 90 51 39 75 32 43 165 29 29 0 27 27 56 (1) (2) Conversion index: catalytic cracking equivalent capacity/topping capacity (%wt). Conversion unit capacities are 100%. Italy Eni’s refining system in Italy is composed of the wholly-owned refineries of Sannazzaro, Livorno and Taranto, as well as its 50% stake in the Milazzo refinery in Sicily. Eni’s refineries operate to maximize asset value according to market conditions and the integration with marketing activities. The Sannazzaro refinery has a balanced capacity of 200 KBBL/d and a conversion index of 71%. Located in the Po Valley, in the center of the Northern Italy, Sannazzaro is one of the most efficient 68 refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%. The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 38%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni 60.77%) through a pipeline. The main equipments are a topping-vacuum unit, a hydrocracking, a platforming unit and two desulphurization units. The Livorno refinery, with a balanced refining capacity of 84 KBBL/d and a conversion index of 11%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a topping-vacuum unit, a platforming unit, two desulphurization units and a dearomatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and dewaxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants. The Milazzo refinery (Eni 50%) has a balanced capacity of 200 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipments in the refinery are: two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracker (HdC), one reforming unit and one LC fining (ebullated bed residue conversion). Outside Italy In Germany, Eni owns an interest of 8.33% stake in the Schwedt refinery (PCK) and an interest of 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni’s refining capacity in Germany is 60 KBBL/d to supply Eni’s distribution network in the country. Green refineries Wholly-owned Ownership share (%) Capacity (2016) (ktonnes/y) Capacity (at regime) (ktonnes/y) Throughput (2016) (ktonnes/y) Venezia ...................................................................... Gela .......................................................................... Total green refineries ....................................................... 100 100 360 360 560 750 1,310 212 212 Green Refining Eni fully owns the green refinery of Venice and the site of Gela, where another green refinery will be realized. The Venice green refinery entered into production in June 2014, with a production capacity of 360 ktonnes/y. The refinery exploits the proprietary EcofiningTM technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At regime, the production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing the CO2 emission. The Gela refinery is located on the Southern coast of Sicily. The refinery was shut-down in March 2014 and in November 2014, Eni signed a Memorandum of Understanding for the reconversion 69 into a bio-refinery with the Ministry for Economic Development and Local Authorities. In 2016 Eni’s activities continued in line with the commitments foreseen in the Memorandum of Understanding. In April 2016 Eni began the construction activities at the Green Refinery project. The refinery will have a capacity of 750 ktonnes/y. The conversion will leverage on the application of ecofining proprietary technology, developed and patented by Eni, to convert unconventional and second generation raw materials into green diesel, a highly sustainable biofuel. Gela reconversion represents the first integrated and cross businesses’ project which Eni is developing in Italy to combine the needs of the business and those of the communities living in the area. The agreement foresees also: • the launch of new hydrocarbon exploration and production activities in the Region of Sicily and the offshore area; the realization of a modern hub for shipping locally produced crude oil and green fuel produced on the site; a feasibility study, to identify LNG and CNG storage and transport infrastructure in Gela, as well as the realization of a project for the production of natural latex from natural products with the relative development of the agricultural supply chain; the set-up of a competence center focused on safety issues; a plan for the environmental remediation of plants and areas that will gradually lose their industrial destination. • • • • The table below sets forth Eni’s products availability figures for the periods indicated. Availability of refined products ITALY Refinery throughputs At wholly-owned refineries ................................................................... Less input on account of third parties .................................................... At affiliated refineries ........................................................................... Refinery throughputs on own account ....................................................... Consumption and losses ....................................................................... Products available for sale ..................................................................... Purchases of refined products and change in inventories ........................... Products transferred to operations outside Italy ....................................... Consumption for power generation ........................................................ Sales of products .................................................................................. OUTSIDE ITALY Refinery throughputs on own account ....................................................... Consumption and losses ....................................................................... Products available for sale ..................................................................... Purchases of finished products and change in inventories ......................... Products transferred from Italian operations ........................................... Sales of products .................................................................................. Refinery throughputs on own account ....................................................... of which: refinery throughputs of equity crude on own account ..................... Total sales of refined products ................................................................ Crude oil sales ..................................................................................... TOTAL SALES .................................................................................. 2014 2015 2016 (mmtonnes) 16.24 (0.58) 4.26 19.92 (1.33) 18.59 7.19 (0.72) (0.57) 24.49 5.11 (0.21) 4.90 4.48 0.72 10.10 25.03 5.81 34.59 0.33 34.92 18.37 (0.38) 4.73 22.72 (1.52) 21.20 6.22 (0.48) (0.41) 26.53 3.69 (0.23) 3.46 4.77 0.48 8.71 26.41 5.04 35.24 0.27 35.51 17.37 (0.27) 4.51 21.61 (1.53) 20.08 6.28 (0.39) (0.37) 25.60 2.91 (0.22) 2.69 4.72 0.40 7.81 24.52 3.43 33.41 0.20 33.61 In 2016, refining throughputs were 24.52 mmtonnes, down by 7.2 % from 2015 due to lower availability of domestic crude oil driven by the shutdown of the Val d’Agri field at the Taranto plant during the period of April - August 2016, as well as other planned maintenance turnarounds (Livorno and Milazzo), partially offset by higher volumes processed at Sannazzaro despite the incident occurred in December 2016. On a homogeneous basis, when excluding the impact of the disposal of CRC refinery in Czech Republic finalized on April 30, 2015, refining throughputs reported a decrease of 4.5% compared to the 2015. 70 Outside Italy, Eni’s refining throughputs were 2.91 mmtonnes, down by 0.78 mmtonnes or 21.1% from previous year, mainly due to the above-mentioned divestment in the Czech Republic finalized in the second quarter of 2015. Total throughputs in wholly-owned refineries were 17.37 mmtonnes, down by 1 mmtonne, or 5.4% compared with 2015, determining a refinery utilization rate (ratio between throughputs and balanced capacity) of 89.5%. Approximately 14.8% of processed crude was equity, down by approximately 6 percentage points from 2015 (20.4%). Logistics Eni is a leading operator in the Italian oil and refined products storage and transportation business. It owns an integrated infrastructure consisting of 17 directly managed depots and a network of oil and refined products pipelines. Eni logistic model is organized in three hubs (North, Central and South Italy). These hubs manage the product flows in order to guarantee high safety and technical standards, as well as cost effectiveness. Eni is also in joint venture with other Italian operators to optimize its logistic footprint and increase efficiency. Other depots are operated by seven different joint ventures (Sigemi, Petrolig, Petroven, Petra, Seram, Disma, Toscopetrol). Since the beginning of 2017 Petrolig joint venture ends. Eni transports oil and refined products: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through a proprietary pipeline network extending approximately 1,462 kilometers. Secondary distribution to retail and wholesale markets is outsourced to independent tanker carriers. 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 Italy Retail .................................................................................................. Wholesale ............................................................................................ Petrochemicals ..................................................................................... Other sales ........................................................................................... Total ................................................................................................... Outside Italy Retail .................................................................................................. Wholesale ............................................................................................ Other sales ........................................................................................... Total ................................................................................................... 2014 2015 2016 (mmtonnes) 6.14 7.57 13.71 0.89 9.89 24.49 3.07 5.03 8.10 2.00 10.1 5.96 7.84 13.8 1.17 11.56 26.53 2.93 4.25 7.18 1.53 8.71 5.93 8.16 14.09 1.02 10.49 25.6 2.66 3.61 6.27 1.54 7.81 TOTAL SALES ................................................................................... 34.59 35.24 33.41 In 2016, sales volumes of refined products (33.41 mmtonnes) were down by 1.83 mmtonnes or by 5.2% from 2015, mainly due to the assets disposal in the Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungary in the second half of 2016. 71 Retail sales in Italy In 2016, retail sales in Italy were 5.93 mmtonnes, with a decrease compared to 2015 (about 30 ktonnes from 2015 or 0.5%) due to a reduction of sales in Eni highway segment, partially offset by an increase in owned stations. Average gasoline and gasoil throughput (1.551 kliters) decreased by approximately 20 kliters from 2015. Eni’s retail market share in 2016 was 24.3%, down by 0.2 percentage points from 2015 (24.5%). As of December 31, 2016, Eni’s retail network in Italy consisted of 4,396 service stations, lower by 24 units from December 31, 2015 (4,420 service stations), resulting from the release of low throughput stations (27 units), offset by positive balance of acquisitions/releases of lease concessions (3 units). Retail sales in the rest of Europe Eni’s strategy in the rest of Europe is focused on selectively growing its presence, particularly in Germany and Austria leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities. In 2016, retail sales of refined products in the rest of Europe (2.66 mmtonnes), recorded a reduction from 2015 (down by 9.2%). This result reflected mainly the assets disposal in the Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungary in the second half of 2016. These negatives were partially offset by higher volumes traded in France, Austria and Germany. On a homogeneous basis, when excluding the impact of the assets disposal in Eastern Europe, sales increased by 1%. At December 31, 2016, Eni’s retail network in the Rest of Europe consisted of 1,226 units, decreasing by 200 units from December 31, 2015, due to the service stations disposal above mentioned. Average throughput (2,340 kliters) increased by 68 kliters compared to 2015 (2,272 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 is supported by a widespread commercial and logistical organization presence throughout Italy and articulated in local marketing offices and a network of agents and concessionaires. In 2016, sales volumes on wholesale markets in Italy (8.16 mmtonnes) increased by 0.32 mmtonnes or 4.1% from the previous year, mainly due to higher volumes marketed of jet fuel, gasoil and fuel oil partly offset by lower sales of bunkering. Wholesale sales in the Rest of Europe were 3.18 mmtonnes, down by 17% from 2015 due to the above-mentioned asset disposals. On a homogeneous basis, sales are barely unchanged from 2015. Supplies of feedstock to the petrochemical industry (1.02 mmtonnes) decreased by 12.8%. Other sales in Italy and outside Italy (12.03 mmtonnes) decreased by approximately 1.05 mmtonnes or 8%, mainly due to lower sales volumes to oil companies. LPG The marketing of LPG in Italy is supported by the refining production and a logistic network made of five bottling plants, 1 owned storage site and coastal storage sites located in Livorno, Naples and Ravenna. LPG is used as heating and automotive fuel. In 2016, Eni share of LPG market in Italy was 17.5%. 72 Outside Italy, the main market of Eni is Ecuador, with a market share of 38%. Lubricants Eni operates six (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, USA, Africa and in the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of the art know how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases, manufactured at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero. In 2016, Eni’s share of lubricants market in Italy was 21%, in Europe 3% and on a worldwide base 0,6%. 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 1 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 80% of oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 20% is purchased. Chemicals Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production sites are located in Italy and Western Europe. These are predominantly oil-based businesses with a history of losses and poor growth prospects. In fact, we face structural headwinds in our legacy basic petrochemicals and plastics businesses due to the commoditized nature of our products, low entry barriers, lack of scale, exposure to the volatility in the costs of oil-based feedstock, cyclicality in demand, and strong competitive pressures from operators with lower cost structure especially from the Middle and Far East and other weaknesses. Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. See “Item 3 – Risk factors”. In 2016 sales of chemical products amounted to 3,759 ktonnes, decreased from 2015 (down by 42 ktonnes, or 1.1%) mainly due to the stagnation of demand in Europe. The declines were registered in polyethylene (down by 9.8%) and styrene (down by 9.1%) following the shutdown of Ragusa and Mantova, partly offset by higher volumes in derivatives among intermediates (up by 14.8%) and elastomers (up by 6.7%), driven by demand increase in the Tyre sector. Petrochemical production of 5,646 ktonnes decreased by 54 ktonnes (down by 0.9%). Higher decreases occurred in polyethylene (down by 8.6%) due to a weak demand and in styrene (down by 7.2%) due to planned and unplanned Mantova standstills. Derivatives productions increased (up by 10.2%) as well as elastomers (up by 7.1%) due to the recovery in sales volumes from the lower levels registered in 2015. The main decreases in production were registered at the Ragusa site (down by 45%), due to a malfunctioning occurred at the plant, as well as Ravenna and Dunkerque (olefins), Ferrara (elastomers) and Mantova sites (styrene) due to planned shutdowns of the plants. The productions of Brindisi plant increased (up by 15.7%) as well as Grangemouth site (up by 20.7%), for the start-up of the new butadiene-based rubber production line. Nominal capacity of plants barely unchanged from the previous year, with an average plant utilization rate calculated on nominal capacity of 71.4% reporting a slight decrease from 2015 (72.7%). 73 The table below sets forth Eni’s main chemical products availability for the periods indicated. Intermediates ....................................................................................... Polymers ............................................................................................. Total production ................................................................................... Consumption and losses ........................................................................ Purchases and change in inventories ....................................................... Year ended December 31, 2014 2015 2016 (ktonnes) 3,334 2,366 5,700 2,972 2,311 5,283 (2,292) 472 3,463 (1,908) 9 3,801 3,417 2,229 5,646 (2,410) 523 3,759 The table below sets forth Eni’s main petrochemical products revenues for the periods indicated. Year ended December 31, 2014 2015 2016 Intermediates ....................................................................................... Polymers ............................................................................................. Other revenues ..................................................................................... Total revenues ....................................................................................... 2,310 2,800 174 5,284 (€ million) 1,899 2,690 127 4,716 1,688 2,380 128 4,196 Intermediates Intermediates revenues (€1,688 million) decreased by €211 million from 2015 (down by 11.1%) reflecting the lower commodity prices scenario that influences average intermediates prices. Sales increased by 4.6%, in particular for ethylene business (up by 19.3%). Derivatives sales registered an increased (up by 14.8%) driven by the combined effect of a higher demand and a higher availability of product. Average unit prices decreased by 11.1%, with aromatics price lowered by 7% (benzene), derivatives prices by 7.7% and olefins prices by 17.8% driven by the weakness of the market and overcapacity in Europe. Intermediates production (3,417 ktonnes) registered an increase of 2.5% from the last year due to increases in aromatics (up by 2.7%) and in derivatives (up by 10.2%). Olefins barely unchanged (up by 0.8%). Polymers Polymers revenues (€2,380 million) decreased by €310 million or 11.5% from 2015 due to average unit prices (down by 5.5%) and sold volumes decrease (down by 6.7%), driven by continuing weakness of automotive sectored demand and low prices of Asian producers. These negatives were further exacerbated by the decrease of average styrenics prices (down by 6.3%) and sold volumes down by 9.1%, also due to lower production availability following the Mantova shutdown. Polyethylene volumes (down by 9.8%) and average prices (down by 3.2%) recorded a decrease. Polymers production (2,229 ktonnes) decreased by 5.8% from 2015. Styrene productions decreased (down by 7.2%) due to the planned Mantova standstill with lower production of styrol (down by 6.4%) and compact polystyrene (down by 11.2%) partly offset by higher productions of ABS/SAN (up by 9.9%). Polyethylene productions decreased (down by 8.6%) driven by scheduled standstills of Ragusa, Ferrara and Dunkerque partly offset by higher productions of HDPE (up by 9.4%). Elastomers productions increased (up by 7.1%), especially in BR segment (up by 15.2%), driven by higher volumes sold compared to 2015. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”. 74 Corporate and Other activities These activities include the following businesses: • • the “Other activities” segment comprises results of operations of Eni’s subsidiary Syndial which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and the “Corporate and financial companies” segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, 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. legal affairs, 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 that are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa. Research and development Technology research and development (R&D) and continuous innovation are key factors in successfully implementing Eni’s business strategies and in supporting mid and long-term performances. The Company believes that the oil&gas industry will have to face several challenges: • • uncertainty about oil&gas prices and demand; limited access to new low-cost hydrocarbon resources, with increasing role of unexplored oil&gas basins; need of a more efficient exploitation of conventional fossil sources; strong request of stakeholders for a reduction of GHG emissions; and safety of operations as a crucial point for business success. • • • In order to address the above challenges, Eni will pursue the following technological targets in the next future: • • • • • reducing operational risk and maximizing operational efficiency by development of new tools for prevention and response to blow outs (mechanical barriers and equipment for the capture of subsea oil eruption) and development of tools for vessel maintenance and restoring clogged pipes; strengthening technological leadership in exploration by continuously development of proprietary tools; maximizing the recovery factor of reservoirs aiming at innovative enhanced oil recovery techniques sustainable also in low oil price scenarios; focusing on conversion and processing of stranded gas resources and the development of proprietary technologies in the sector of renewable energies; further development of Eni’s Green Refinery processes with innovative solution for the conversion of conventional refineries into bio-refineries; 75 • • • • formulations of innovative fuels, lubricants and bitumen that comply with European regulations and new motor specifications; development of new technologies for the separation, conversion, transportation and utilization of natural gas; commitment to transfer quickly the relevant results achieved by research and development to business units, also to the new appointed energy solution one; and development of innovative environmental technologies for in situ monitoring and remediation. In 2016, Eni filed 52 patent applications (33 in 2015). In 2016, Eni’s overall expenditure in R&D amounted to €161 million which were almost entirely expensed as incurred (€176 million in 2015 and €174 million in 2014). Exploration & Production • Oxy-Combustion. As part of the zero-flaring strategy, Eni is assessing through a pilot installation at the New Oil Center of Gela, a technology for oxy-combustion, which allows to exploit low calorific tail gas by production of electricity with CO, NOX and hydrocarbons emissions essentially absent. • MAREnergy. Project aiming at the exploitation of renewable energy in the sea (from waves and wind) to support upstream activities through the development of hybrid solutions capable of minimizing the typical variability of renewable sources in energy generation. • CO2 -to-Oil. Project aiming to reduce Eni’s carbon footprint using a technology that captures CO2 to produce a third generation bio-fuel. The emerging technology is based on the cultivation of micro-algae inside bio-reactors in order to produce a bio-algal oil suitable to feed Eni’s Green Refineries. The technology pilot plant has being built in Ragusa with start-up scheduled for March 2017. • Chemical EOR. In 2016, in Egypt three chemical EOR pilots (chemical and low salinity injection) were started in Belayim giant field. First results of the polymer injection in two producing wells confirmed the forecasted improved recovery allowing the booking of additional reserves. • Drilling Safety Technologies. Project aiming to reduce by two orders of magnitude the risk of blowout occurrence compared to OGP reference. To achieve this goal, new technologies able to improve well integrity both during drilling and well productive life have been developed. In 2016 the first test of a casing valve activated without control line and therefore suitable to be used in subsea wells, was performed; beginning of 2017 a first application in a well will be carried out. Refining & Marketing • Eni Green Diesel+. A new premium diesel containing 15% of Hydrotreated Vegetable Oil (HVO), produced in Venice bio-refinery using Eni/UOP’s Ecofining™ process, was launched in January with sales increase by about 20%. In November the winter diesel (Eni Green Diesel + Alpino) was also launched. • Energy Saving Lubricants. In collaboration with GE a new lubricant oil for gas turbines has been developed. Its use will allow Eni to save 790 MMscf of gas and 44’000 tons of CO2 emissions per year. Renewable Energy & Environment • Concentrated Solar Power. Since some years, Eni is engaged in an R&D project for the development of innovative components and engineering solutions for Concentrated Solar Power (CSP) in order to reduce capital investment and operation costs for thermal energy production via solar. In partnership with Massachusetts Institute of Technology it has been developed an innovative, low cost parabolic solar collector, easy to manufacture and assembly. The latter feature will allow the manufacture in the same countries where they will be installed, fostering local employment and economic development. In 2016 a full-scale prototype was built in Politecnico of Milan University. 76 • Waste to Fuel. Eni is evaluating a Waste-to-Fuel process able to transform wet domestic waste into bio-oils suitable to feed Eni’s biorefineries to obtain second-generation biofuels. The pilot scale development phase of the technology has been completed. • Monitoring of Pollution and Remediation of Soils. Eni R&D has been active for years in the development of devices and protocols able to characterize polluted sites and monitor their remediation. Eni in collaboration with Massachusetts Institute of Technology, Consiglio Nazionale delle Ricerche, University of Piemonte Orientale, University of Rome “Tor Vergata” and Syndial, has developed and validated some original passive biomimetic samplers to determine the available fraction of organic contaminants. The devices consist of low-density polyethylene films. In 2016 the application protocol of those devices was validated as official method of analysis by the Italian institute for the research on water (CNR-IRSA). Energy Transition In 2016 Eni launched the “Energy Transition” R&D program with the aim of developing new technologies to promote the widespread use of natural gas, making easier its production and transport, widening its uses and to decarbonize the whole value chain. In particular, the research deals with three areas of interest: • Natural Gas Transportation and Conversion. Transportation and use of natural gas including the development of materials suitable to take the Adsorbed Natural Gas (ANG) technology to an industrial scale, and the development of processes for the conversion of natural gas to methanol. The latter seen as an important vector for the production of low environmental impact liquid fuels and chemical products (olefins and aromatics). • Hydrogen Sulfide. Development of new technologies for the separation and use of H2S, both in fertilizer products and in materials and plastics containing sulfur. • Carbon Dioxide. Development of new technologies for the separation and use of CO2 comprising on-board capture of generated CO2 in motor vehicles and use of CO2 for production of plastics, fibers and building materials. Petrochemicals • 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. • 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. The Tire Technology Committee has awarded this project with the “Environmental Achievement Award”. 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. 77 Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni uses insurance companies who it believes are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however, underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.2 billion for offshore events and $1.4 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1,250 million for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment and time charters; $1 billion for FPSOs used by the Exploration & Production segment for developing offshore fields. Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See “Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas”. Environmental matters Environmental regulation Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in the certain protected areas or provide special measures to be adopted to protect health and safety at workplace and health of communities that could have been affected by the Company’s activities. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. See “Item 3 – Risk factors”. We believe that the Company will continue incurring significant amounts of expenses to comply with pending regulations in the matter of environmental, health and safety protection and safeguard, particularly 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. European Union Environmental Laws Framework In 2016, the main environmental efforts of the European Union continued to focus on the air quality, energy transition, circular economy and Climate Change matters. On November 4, 2016, the Paris Agreement entered into force, exactly 30 days after the date on which the last of at least 55 Parties to the Convention accounting in total for at least an estimated 55% of the total 78 global greenhouse gas emissions have deposited their instruments of ratification. To date, the 123 Parties have ratified the Convention. This important step in the common international Climate Change strategy sets out a global action plan to put the world on track to avoid dangerous climate change by limiting global warming to well below 2°C. By the ratification of the Convention, the governments agreed to limit the increase to 1.5°C, since this would significantly reduce risks and the impacts of climate change. On October 4, 2016, the European Parliament approved the ratification of the Paris Agreement by the European Union. The Paris Convention vindicates the EU strategy in climate change defined in October 2014, when the European Council agreed on the 2030 climate and energy policy framework. In this strategy the EU stated an ambitious economy-wide domestic target of at least 40% GHG reduction for the period up to 2030 (below 1990 levels) and to a 27% share of renewable energy in final energy consumption. On November 30, 2016, the following step of this strategy was written down, when the EU Commission presented the Clean Energy for All Europeans (so called “Winter Package”). By this proposal, the EU is consolidating the enabling environment for the transition to a low carbon economy through a wide range of interacting policies and instruments reflected under the Energy Union Strategy, one of the 10 priorities of the Juncker Commission. The Winter Package has three main goals: putting energy efficiency first (setting a binding 30% energy efficiency target), achieving global leadership in renewable energies and providing a fair deal for consumers. The Package includes some legislative proposals such as revision of Renewable Energy Directive (“RED”) - (Directive 2009/28/CE) and revision of the Energy Efficiency Directive. For Eni’s strategies and policy on biofuels, a revision of RED has a particular importance. In order to foster the de-carbonization and energy diversification the RED revision proposal introduces an obligation on European transport fuel suppliers to provide an increasing share of renewable and low-carbon fuels, including advanced biofuels, renewable transport fuels of non-biological origin (e.g. hydrogen), waste-based fuels and renewable electricity. The level of this obligation is progressively increasing from 1.5 percent in 2021 (in energy terms) to 6.8 percent in 2030, including at least 3.6 percent of advanced biofuels. It also introduces a cap on the contribution of first generation biofuels (so called “food-based” biofuels) in transport sector towards the EU renewable energy target, starting at 7 percent in 2021 and going down progressively to 3.8 percent in 2030 to minimize the Indirect Land-Use Change (ILUC) impacts. An important part of EU Climate Strategy is covered by the Emission Trading System (ETS), which is now in the III phase (2013-2020). The Commission has already brought forward key proposals to implement the EU’s target to reduce greenhouse gas emissions by 2030. In July 2015, it presented a proposal to reform the EU Emission Trading System (ETS) – phase IV (2021-2030) to ensure the energy sector and energy intensive industries deliver the emissions reductions needed. In summer 2016, the Commission brought forward proposals for accelerating the low-carbon transition in other key sectors of the European economy. To achieve the at least 40% EU target, the sectors covered by the ETS have to reduce their emissions by 43% compared to 2005. To this end, the overall number of emission allowances will decline at an annual rate of 2.2% from 2021 onwards, compared to 1.74% currently. Currently around 49% of Eni’s direct GHG emissions are included within the Carbon Pricing Scheme by its participation in the EU ETS. The air quality remains at the center of the European environmental policies and strategies. On December 18, 2013, the European Commission adopted a package of proposals to improve air quality in the EU, which updated the air policy objectives for 2020 and 2030. The package includes a long-awaited revision of the National Emission Ceilings (NEC) Directive, a proposal to address emissions from medium scale combustion plants (MCP) and a proposal for ratification of the recently amended Gothenburg Protocol. On December 31, 2016, the new National Emissions Ceilings (NEC) Directive entered into force. The NEC directive, based on a Commission proposal sets 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 NEC Directive must be transposed by the Member states by 30 June 2018. The new NEC directive repeals and replaces Directive 2001/81/EC. Each EU Member State is required to produce a National Air Pollution Control Program by 31 March 2019 setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments. On December 18, 2015, the Directive No. 2015/2193/EU on the limitation of emissions of certain pollutants into the air from medium combustion plants entered into force. The Medium Combustion Plant 79 Directive (MCP Directive) regulates pollutant emissions from the combustion of fuels in plants with a rated thermal input equal to or greater than 1 megawatt (MWth) and less than 50 MWth. The MCP Directive is a part of the Clean Air Policy Package adopted on December 18, 2013 and it regulates emissions of SO2, NOX and dust into the air with the aim of reducing those emissions and the risks to human health and the environment they may cause. The MCP Directive will have to be transposed by Member States by December 19, 2017. The MCP Directive also ensures implementation of the obligations arising from the Gothenburg Protocol under the UNECE Convention on Long-Range Trans-boundary Air Pollution. 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 30 May 2016 establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU, for common wastewater and waste gas treatment/management systems in the chemical sector. Currently the exchange of views between the Commission and the Technical Working Group on the Large Combustion Plant Best Available Technique reference document (LCP BREF) under the Emission Directive is taking place. By the end of 2017, the adoption of final LCP BREF with revised BAT conclusions is expected. The updated LCP BREF 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. 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. Moreover, in October 2016 the Kigali amendment to the Montreal Protocol (on Substances that Deplete the Ozone Layer) was signed in Rwanda. The Amendment adds powerful greenhouse gases hydrofluorocarbons (HFCs) to the list of substances controlled under the Protocol to be phased down. HFC phasedown is expected to avoid up to 0.5 degree Celsius of global temperature rise by 2100, while continuing to protect the ozone layer. In 2015 the European Commission adopted the Circular Economy Package, which includes revised legislative proposals on waste to stimulate Europe’s transition towards a circular economy which emphasizes the need to move towards a lifecycle-driven ‘circular’ economy, with a cascading use of resources and residual waste that is close to zero. The O&G sector will have to put a significant effort to follow the “circular philosophy” by investing in the innovative technological solutions, optimization of the water use, energy efficiency and the green procurement. A new integrated EU policy for the Arctic Region has been adopted in 2016. The policy defines the 39 tackling climate change, enhancing focusing on strengthening international cooperation, actions environmental protection and promoting sustainable development. 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 80 agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees. On June 1, 2007, the REACH Regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed 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 European Chemicals Agency (ECHA) how the substance can be safely used and they must communicate the risk management measures to the users. If the risks cannot be managed, Authorities can restrict the use of substances in different ways. Over time, the hazardous substances should be substituted with less dangerous ones. The deadline of REACH registration depends on the tonnage band of a substance and the classification of a substance; next and last deadline is 2018. Eni recognizes the importance of the Regulation EC No. 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA which regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspect that concerns the exchange of information between producers and importers, as well as the users of chemical substances (“downstream users”). The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation EC No. 1272/2008 on the classification, labeling and packaging of substances and mixtures), and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. The Regulation will replace two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. There is a transition period until 2015. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them. Following the incident at the Macondo well in the Gulf of Mexico, the U.S. Government and other governments have adopted more stringent regulations targeting safety and reliable oil&gas operations in the United States and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. Italian Authorities as well have passed legislation with Law Decree No. 128 on June 29, 2010 that introduces certain restrictions to activities for exploring and producing hydrocarbons that have been confirmed and further geographically limited by the successive Law Decree No. 134 of August 7, 2012 and by the Ministerial Decree of September 4, 2013. European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction. On June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The main elements of the EU Directive are the following: • The Directive introduces licensing rules for 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. 81 • • • • • • • Independent national competent authorities, responsible for the safety of installations, are in charge to verify the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards. Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities. Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation. Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents. Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities. Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore). Operators working in the EU are accident-prevention policies overseas as they apply in their EU operations. required to demonstrate they apply the same We believe that Eni operations are currently in compliance with all those regulations in each European country whose they have been enacted. Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will likely 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 performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. As to major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015). The main changes in comparison to the previous Seveso Directive are: • technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures; expanded public information about risks resulting from Company activities; modified rules in participation by the public in land-use planning projects related to Seveso plants; and stricter standards for inspections of Seveso establishments. • • • Eni has carried out specific activities aimed at guaranteeing the compliance of its own industrial sites. HSE activity for the year 2016 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. 82 In 2016, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 304, of which: • • • • 99 certifications according to the ISO 14001 standard; 10 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union); 18 certifications according to the ISO 50001 standard (certification for an energy management system); 103 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements). In 2016 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 97% for the standard OHSAS 18001 and 95% for the ISO 14001 standard. In 2016, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,102 million, increasing by 3.3% from 2015. Environment. In 2016, Eni incurred total expenditures of €588.65 million for the protection of the environment (with a reduction of 5.9% with respect to 2015). Environmental expenditures are mainly related to remediation and reclamation activities (€233.9 million), waste management (€133.8 million), water management (€62 million), air protection (€47.2 million) and spill prevention (€37.1 million). Safety. Eni is committed to safeguarding the safety of its employees, contractors and all people living in the areas where its activities are conducted and its assets located. In 2016, the new legislation didn’t impact significantly procedures already in place for safety in the workplace. The dissemination of safety culture is a primary target for Eni. In 2016, in order to increase safety’s culture in the workforce, awareness-raising initiatives continued. Road Shows and Safety Day were organized with the aim of sharing performance, target, new projects and safety vision between Eni’s top management and employees and contractors. In order to keep developing new awareness raising actions regarding safety at work, in 2016 two new initiatives were launched: • • “Inside Lesson Learned Project” to share lessons learned using video clips made by internal resources and inspired by real events occurred in the company; “Eni in Safety 2” to increase safety culture with workshops finalized to discuss safe behaviors, responsibility and leadership in safety. The new projects will be roll out in 2017 involving employees and contractors. In 2013, Eni launched an initiative aimed at issuing work permits in electronic form for standardizing and improving the related risk assessment process. The initiative is progressively involving all the operating sites. In 2015, Eni developed the Company Process Safety Management System for increasing the safety of its operations through still higher technical and management standards. Starting from 2016 and in following years these standards will be applied progressively in all operating activities. Results of efforts to achieve a better safety in all activities brought an improvement of Eni workforce total recordable injury rate (0.35), decreased by 21% compared to 2015. As to emergency preparedness, Eni has joined the Oil Spill Response-Joint Industry Project (OSR-JIP I & II) launched in December 2011 by International Association of Oil&Gas Producers (IOGP) and International Petroleum Industry Environmental Conservation Association (IPIECA) and concluded in 2016. The JIP executed the outstanding recommendations from the report produced by the Global Industry Response Group (GIRG) set-up after the Macondo accident. The JIP aimed at: • • providing a forum for industry to share knowledge on the science, tools and techniques; representing the industry on approaches for oil spill preparedness and response, working closely with other associations on communications with both national and global regulatory groups; engaging pro-actively in broader outreach and communication. • 83 The OSR-JIP carried out specific projects dealing with exercise planning, in situ burning, dispersants advocacy-subsea, efficacy-post spill monitoring, upstream risk assessment and response capability, etc., publishing 11 Research Reports, 9 Technical Reports and 24 Good Practice Guidance (two are already available in Italian). Costs incurred in 2016 to support the safety levels of operations and to comply with applicable rules and regulations were €287.8 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: • • • • • • • plant and facility efficiency and reliability; promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment; certification programs of management systems for production sites and operating units; identified indicators in order to monitor exposure to chemical and physical agents; strong engagement in health protection for workers operating worldwide also with the support of international health providers capable of guaranteeing a prompt and adequate response to any emergency; identification of an effective and reliable health providers, in Italy and abroad; training programs for medics and paramedics. In order to protect the health and safety of its employees, Eni relies on a network of health care facilities located in its main operating areas. A set of international agreements with the best local and international health providers ensures efficient services and timely responses to emergencies. Eni is engaged to the elaboration of HIA and relative standards to be applied to all new projects of evaluation of working exposure to environment, in Italy and abroad. The main aim of HIA is to avoid any negative impacts and maximize any positive impacts of the project on the host community and it is usually carried out as part of/or in conjunction with the Health, Environmental and a Social Impact Assessment process. Its results are used to develop appropriate mitigation measures and an improvement plan with the host community. In 2016, Eni incurred total expenses of €47.9 million, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health, which will be in line with 2016 levels in future years. Managing GHG emissions 2016 was a relevant year for the international climate change debate, mainly due to the entry into force of the Paris Agreement on 4th November. The Paris Agreement and its early entry into force represents for Eni a very positive step toward a low carbon energy transition. As a major international energy company, Eni is actively involved to play a leading role to contrast climate change. Eni recognizes indeed the scientific evidences presented in the IPCC Fifth Assessment Report and the necessity to limit the rise of the global temperature below 2 °C above pre-industrial levels. In line with this long term target, Eni has developed an integrated climate strategy with the aim of advance in the transition towards a low-carbon energy future while fulfilling the growth of energy demand. Eni’s climate strategy is composed of three main pillars: reducing and offsetting its greenhouse gas (GHG) emissions; developing a low-carbon portfolio; and committing on renewables and low carbon R&D. Regarding the reduction of greenhouse gas (GHG) emissions, since 2010 years Eni reached important results, such as an absolute reduction of 31% in total direct GHG emissions, together with a 30% reduction in the carbon intensity of the Upstream business. These results were mainly driven by flaring down projects, methane monitoring campaign and energy efficiency efforts. 84 In order to strengthen this engagement and with a forward looking perspective, in 2015 Eni launched a strategic internal Program on Climate Change aimed at developing a medium and long term roadmap able to drive Eni towards a low carbon future. In line with this Program and the abovementioned strategy, Eni published its targets and established the new “Energy Solutions” business line in order to integrate traditional energy sources with the production of energy from renewable sources. In particular, by 2025 we have confirmed three main commitments focused on improving our GHG performance: to reduce by -43% vs 2014 the GHG emission intensity of our production, to reach zero routine gas flaring and to abate by 80% the fugitive emissions coming from our Upstream business. In addition to these operational actions and commitments, Eni actively participates in primary international climate initiatives. In particular, in 2016 Eni contributed to further develop the “Oil and Gas Climate Initiative” (OGCI), a voluntary CEO led initiative launched in 2014 along with other companies in the oil&gas sector (currently, the ten OGCI member companies represent about 25% of global HC production). On November 4, 2016, during a high-level event in London, OGCI CEOs announced an investment of $1 billion over the next ten years to develop and accelerate the deployment of innovative low emissions technologies able to improve the management of GHG emissions and contain climate impacts of the Oil&Gas sector. In 2016, Eni has continued its efforts in two international Public-Private Initiatives focused on operational efficiency: the “zero routine gas flaring at 2030” program of the World Bank’s “Global Gas Flaring reduction partnership” and the “Clean Air and Climate initiative - Oil & Gas Methane Partnership”, aimed at reducing methane emissions in the oil&gas value chain. About this important topic, in October 2016 was published the first report of the initiative, with details and information on Eni methane LDAR monitoring campaign during the first year of the initiative. Thanks to its climate strategy and the ambitious targets for the future, in 2016 Eni has been recognized by the CDP as a global leader for its actions and strategies in response to climate change and was included in the prestigious A-list of CDP. Eni was the only oil & gas major achieving this high recognition. Another acknowledgment of Eni’s climate leadership was the invitation to take part in the works of the Task Force on Climate Related Disclosures of the Financial Stability Board, which has the aim of develop voluntary, consistent climate-related financial risk disclosures for use by companies in providing effective information to investors. Regarding Eni’s own GHG emissions management, with the aim of ensuring a comprehensive, transparent and accurate reporting for GHG emissions, in 2005 Eni introduced its own Protocol for accounting and reporting GHG emissions (GHG Accounting and Reporting Protocol), integrated in 2013 by a procedure on reporting and accounting methodologies on indirect emissions scope 3 types. This procedure was updated in 2015. According to the Eni methodology for accounting and reporting Scope 3 GHG, Eni estimates the indirect GHG emissions generated by several emission categories (e.g. purchased goods and services, use of sold hydrocarbon products, business travel, franchising, etc.) in line with the WBCSD-WRI Protocol “Corporate Value Chain (Scope 3) Accounting and Reporting Standard”. Eni documents are an essential requirement for emissions certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to GHG, the definition of objectives and the assessment of progress. Eni GHG Protocol has been updated in 2016 to be in compliance with the National and European Guidelines (Regulation No. 601/2012) and with the best practices reference document (American Petroleum Industry Compendium). For safer and more accurate management of GHG emissions and more effective reporting, Eni provided all its business units with a dedicated database, in order to gather and report GHG emissions according to the Protocol and to ensure completeness, accuracy, transparency and consistency of GHG accounting as required by certification needs. In order to improve the Eni accounting and reporting process, Eni confirmed independent verification of its 2016 equivalent CO2 emissions data (Scope 1, 2 and 3 emissions), as submitted to the CDP, and obtained the verification statement in accordance with ISAE 3410. In Europe, Eni is subject to the European Union Emission Trading Scheme (EU-ETS) that was established by Directive No. 2003/87/EC. Effective from January 1, 2005, EU-ETS is the largest carbon market in the world for exchanging emission allowances targeting industrial installations with high carbon 85 dioxide emissions. The EU-ETS Directive states that any operator, who produces GHG emissions in excess of the amounts allowed on the basis of the national allocation plan, is required to acquire allowances on the market to cover the excess emissions or to pay a penalty. Currently, Eni participates in the ETS with 41 plants, mostly located in Italy, which collectively represent 49% of all direct GHG emissions generated by Eni’s plants worldwide. Due to stricter allocation rules in the third phase (2013-2020) of the Emissions Trading Scheme, Eni has been receiving a lower amount of free allowances in comparison with the second phase (2008-2012). As a consequence, in the next four-year period (2017-2020), Eni will buy on the market an amount of allowances to cover GHG emissions of its industrial plants. The large majority of the deficit is concentrated in the power sector due to European allocation rules. For additional information on Eni’s climate strategy and GHG management, please refer to the latest Eni’s Corporate Sustainability Report (“Enifor”) or to the Eni’s CDP climate change questionnaire response, both published on Eni’s website (www.eni.com). Regulation of Eni’s businesses Overview The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. Regulation of exploration and production activities Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See “Regulation of the Italian hydrocarbons industry” and “Environmental matters” for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities. Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any royalties that are payable in-kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in-kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. In production sharing agreements, entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies holding the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (Profit Oil). A similar scheme to PSA applies to Service and “buy-back” contracts. In general, Eni is required to pay income tax on income generated from production activities (whether under a license or PSA). The taxes imposed upon oil&gas production profits and activities may be substantially higher than those imposed on other businesses. 86 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. 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 and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with fixed amount of exemption. Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties are equal to 20% for oil&gas, with no exemptions). Gas & Power Natural gas market in Italy Legislative Decree No. 130 of August 13, 2010 containing measures for increasing competition in the natural gas market and transferring the ensuing benefits to final customers and Law Decree of December 23, 2013 containing measures to promote gas market liquidity In 2011, Legislative Decree No. 130 of August 13, 2010 titled “New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers” became effective. This new regulation replaced the previous system of gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 by introducing a 40% ceiling to the wholesale market share of each Italian gas operator who inputs gas into the Italian backbone network. In the frame of Legislative Decree No. 130/2010 Eni built new storage capacity for about 2.64 BCM; as a consequence the above mentioned cap to its market share in Italy rises from 40% to 55%. In the case of violations of the mandatory threshold, Eni is obliged to execute gas release measures at regulated prices up to 4 BCM over a two-year period following the ascertainment of the breach. Access to the new storage capacity was reserved to industrial customers. The Law Decree of December 23, 2013, converted into Law on February 21, 2014, establishes that any operator with a wholesale market share higher than 10% is obliged to offer on the natural gas forward market a volume of natural gas corresponding to 5% of the annual imported volumes. The obligation to offer should be combined with a corresponding obligation to bid on the same market; the spread between bid and ask prices has to be lower than an amount defined by the Minister of Economic Development, based on a proposal by the AEEGSI. AEEGSI also defines the modalities for the fulfillment of the above mentioned obligation. 87 Eni’s management is monitoring these issues with a view of assessing any possible financial or economic impact associated with the enacted measures and their evolution. Management also believes that these regulations will increase competition in the wholesale natural gas market in Italy leading to further margin pressures. Law Decree No. 1 of January 24, 2012 for new liberalization measures in Italy Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so-called Liberalization Decree was converted to Law No. 20 on March 24, 2012. This law aimed to: • • enhance competitiveness in gas tariffs to residential customers and in the distribution of refined products. The AEEGSI, in charge with setting pricing mechanisms for supplies to final users, starting from the second quarter of 2012 updated the indexation mechanism by gradually increasing the weight of spot prices in the indexation of the supply costs of gas that previously used to be oil-linked; and reform the storage system introducing market-based mechanisms for the allocation of storage capacity, moving away from the traditional “pro-rata”/tariff system, and with the aim to reduce the cost of natural gas for industrial customers. In particular: - for an amount determined by the Ministry itself, storage capacity is primarily reserved for the offer to industrial sector of an integrated service (international transport of liquefied natural gas, regasification and storage) allowing them to supply natural gas directly from abroad in the form of liquefied natural gas; and the remaining amount of storage capacity is assigned via auction procedures devoted to the modulation needs. - Based on the principles described above, the Minister of Economic Development and the AEEGSI establish every year the detailed criteria for the allocation of gas storage capacities. In 2016, 1BCM of bundled storage and regasification capacity was offered to the industrial sector. Negotiation platform for gas trading and gas balancing market In compliance with the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry of Economic Development published a decree that implements a trading platform for natural gas from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform (MGAS) are entrusted to an independent operator, the Gestore dei Mercati Energetici (GME), an Italian agency. In the MGAS, parties authorised to carry out transactions at the “Punto di Scambio Virtuale” (PSV - Virtual Trading Point) may make forward and spot purchases and sales of volumes of natural gas. In the MGAS, GME plays the role of central counterparty to the transactions concluded by Market Participants. In October 2016 the new gas balancing regime - an evolution of the one already in place - has entered into force in the Italian system in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by Snam Rete Gas about the daily gas consumption. The new gas balancing regime provides for: • • the possibility for shippers to modify intra-day the gas nominations; the possibility for shippers 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) the incentive for shippers to balance their position via penalizing imbalance prices. • To foster market liquidity, starting from April 2017 all of the above-mentioned gas trading activities will be concentrated on the MGAS, managed by GME, as one single platform. Management believes that these measures have increased, and will further increase, the level of liquidity in the Italian spot market of gas. 88 Natural gas prices Following the liberalization of the natural gas sector introduced in 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the AEEGSI holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the AEEGSI) and Legislative Decree No. 164/2000. Furthermore, the AEEGSI is still entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by AEEGSI beside their own price proposals. In 2013, a new tariff regime was enacted for Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the AEEGSI are residential clients (including residential buildings consuming less than 200,000 CM/y). With Resolution No. 196 effective from October 1, 2013, the AEEGSI reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices versus the previous 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 by introducing a pricing component intended to cover the risks and costs of the supplies to wholesalers. Furthermore, it was provided a stability mechanism whereby a wholesaler part of a long-term, take-or-pay gas supply contract may opt for being reimbursed of the possible negative difference between the oil-linked costs of gas supplies and spot prices in the two thermal years following the new regime implementation; conversely, in case spot prices fall below the oil-linked cost of gas supplies in the following two thermal years, the same wholesaler had to refund customers of the difference. Based on this compensation mechanism, which run out after September 2016, Eni totalled about €160 million of reimbursement over three thermal years, starting in October 2013 and ending in September 2016. This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed. Furthermore, the new tariff mechanism indexed to TTF (Title Transfer Facility) for residential clients will be applicable until the end of thermal year 2017 - 2018. However, a Law Decree still under discussion at the Italian Parliament, is expected to increase competitive pressure with the abrogation of the tariffs for gas and power effective from July 1, 2018. Referring to the electricity market, residential customers would choose tariffs on the free market, potentially, lower than the regulated ones. For the gas market, similar competitive impact cannot be excluded following the adoption of the same price regulation regime. Similarly other Regulatory Authorities in European countries where Eni is present have issued regulations referring to hub component in the pricing formulas related to retail clients, as well as measures to boost liquidity and competitiveness in the gas market. Refining and marketing of petroleum products Refining. The regulations introduced with Law No. 9/1991 and No. 239/2004 (Article 1, paragraphs 56, 57 and 58) significantly changed the norms introduced in the 1930’s that required that any refining activity be handled under a concession from the state. Today an authorization is required to set up new processing and storage plants and for any change in the capacity of mineral processing plants, while all other changes that do not affect capacity can be freely implemented. Another simplification measure was introduced by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as “strategic settlements” that need authorization from the State, in agreement with the relevant Region, and imposes a single process of authorization that must be closed within 180 days. Management expects no material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium term. 89 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 supply freely up to 50% of their requirements. In such case the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing Eni’s market share in Italy. Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) upon the closure of at least 7,000 service stations, the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third party access to unused storage capacity for petroleum products. With the same goal of renewing the Italian distribution network, Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities. After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/ 2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012 all service stations must be provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations which might prejudice 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. Management believes that those measures will favor competition in the Italian retail market and support efficient operators. Petroleum product prices. Petroleum product prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Productive Activities; such recommendations are considered by service station operators in establishing retail prices for petroleum products. Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 (“Decree 22/2001”) enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain 90 minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain. As of December 31, 2016, Eni owned 5.2 mmtonnes of oil products inventories, of which 3.6 mmtonnes as “compulsory stocks”, 1.4 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.2 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (37%), light and medium distillates (37%), refinery feedstock (19%), fuel oil (5%) and other products (2%) were located throughout the Italian territory both in refineries (80%) and in storage sites (20%). Competition Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts does not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions: • • • • requiring that an infringement be brought to an end; ordering interim measures; accepting commitments; and imposing fines, periodic penalty payments or any other penalty provided for in their national law. National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the “EEA Agreement”), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among 91 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. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’ worldwide proved oil&gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas. Organizational structure Eni SpA is the parent company of the Eni Group. As of December 31, 2016, there were 218 subsidiaries and 103 associates, joint ventures and joint operations that were accounted for under the equity or cost method or in accordance to Eni’s share of revenues, costs and assets of the joint operations calculated based on Eni’s working interest. Information on Eni’s investments as of December 31, 2016 is provided in Note 48 to the Consolidated Financial Statements. Item 4A. UNRESOLVED STAFF COMMENTS None. 92 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 factors that could cause actual results to differ materially from those expressed in the important forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii. Executive summary Key consolidated financial data Net sales from operations from continuing operations ................................... Operating profit (loss) from continuing operations ........................................ Net profit (loss) attributable to Eni from continuing operations ...................... Net profit (loss) attributable to Eni from discontinued operations ................... Net profit (loss) attributable to Eni ............................................................. Net cash provided by operating activities - continuing operations ................... Capital expenditures - continuing operations ................................................ Investments and purchases of consolidated subsidiaries and businesses ............ Shareholders’ equity including non-controlling interest at year end ................. Net borrowings at year end ........................................................................ Net profit (loss) attributable to Eni basic and diluted from continuing operations .......................................................... Net profit (loss) attributable to Eni basic and diluted from discontinued operations ................................................................................................ Net profit (loss) attributable to Eni basic and diluted .................................... Dividend per share .............................................................. (€ per share) Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage)(1) ................................................................................... (€ per share) 2014 2015 2016 (€ million) 72,286 (3,076) (7,952) (826) (8,778) 12,875 10,741 228 57,409 16,871 98,218 8,965 1,720 (417) 1,303 14,469 11,178 408 65,641 13,685 55,762 2,157 (1,051) (413) (1,464) 7,673 9,180 1,164 53,086 14,776 0.48 (2.21) (0.29) (0.12) 0.36 1.12 (0.23) (2.44) 0.80 (0.12) (0.41) 0.80 0.21 0.29 0.28 (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. In 2016, Eni reported a net loss pertaining to continuing operations of €1,051 million, with a significant improvement compared to last year’s loss of €7,952 million. The operating profit was €2,157 million compared to an operating loss of €3,076 million a year ago. The recovery in oil markets, that has begun in the second half of 2016 favorably affected the full-year results of operations and the assets carrying amounts. Better market fundamentals were factored in an upward revision to management’s long-term price assumption for the benchmark Brent to 70$ per barrel (in 2020 real terms), which was adopted in the financial projections of the 2017-2020 industrial plan and in assessing the recoverability of the Group assets carrying amounts as of December 31, 2016. In 2015, management assumed a long-term Brent price of 65$ per barrel. This upward revision triggered the reversal of prior impairment losses for €1,005 million post-tax at oil&gas properties, which helped mitigate impairment losses due to a lowered outlook for gas prices in Europe and other drivers, as well as other non-recurring charges for an overall negative impact of €831 million. On the contrary, the FY 2015 result was negatively affected by the recognition of material, post-tax charges of €8.5 billion. Those comprised impairment losses of upstream assets (€3.9 billion) and the 93 write-off of deferred tax assets for €1.8 billion due to a lowered profitability outlook. Furthermore, the 2015 charges included the impairment of the Chemical business (€1 billion), the carrying amount of which was aligned to the expected fair value based on a negotiation then ongoing to establish a joint venture with an industrial partner. Subsequently, Eni and the potential buyer failed to close the negotiation. Finally, other extraordinary charges of €1.8 billion were incurred mainly in the G&P segment (for more information about extraordinary charges of G&P segment, see the paragraph “Operating profit by segment”). Nevertheless, the 2016 underlying performance was negatively affected by a continued slump in commodity prices especially in the first half of the year which determined y-o-y declines in average crude oil prices (down by 16.7%, from 52.5 $/b reported in 2015, to 43.7 $/b in 2016), gas prices (down by 28.2%) and refining margins (down by 49.4%). These declines drove a 23% reduction in the Group consolidated turnover. Other factors negatively affecting the performance were a four and half-month shutdown of the Val d’Agri oil complex in Italy and lower one-off gains in the Gas&Power segment in connection with an ongoing renegotiation process of its long-term gas supply contracts. Management implemented a number of initiatives to withstand the negative trading environment, including tight investment selection, with capex down by 15% (19% y-o-y at constant exchange rates), control of E&P operating expenses (down by 17%), optimizations of plant setup at refineries and chemical plants, savings on energy consumptions and logistic costs and G&A cuts. All these measures improved operating profit by around €1.7 billion. Finally, income taxes declined by €1,186 million due to the above mentioned extraordinary drivers. The tax rate was affected by the high relative incidence on taxable profit of results earned at PSA contracts, which are characterized by higher-than-average rates of taxes. Overall management estimated that the increase in the Group operating results of approximately €5.2 billion (from an operating loss of €3.08 billion in 2015 to a profit of €2.16 billion in 2016) was due to the following factors: • • a positive €1.7 billion gain associated with efficiency initiatives, cost reductions, depreciation and amortization, as well as a decreased exploration expenditure; lower a positive €8.6 billion effect due to lower asset impairments and lower other extraordinary charges as well as a lower inventory holding valuation allowance; These positives were partly offset by: • • • a negative €3.3 billion impact due to lower commodity prices and margins; a negative €0.6 billion effect due to the four and a half months shutdown of operations at the Val d’Agri profit centre (see Item 4 – Exploration & Production – Eni’s principal oil&gas properties) and in the Gas & Power segment lower one-off gains related to the renegotiations of gas contracts; a negative €1.2 billion associated with the accounting of Saipem as discontinued operation in 2015. Due to this accounting method, the 2015 result of the continuing operations benefitted from the elimination upon consolidation of then intercompany purchases of capital goods and other services, mainly oilfield services to the E&P segment. This reflected the fact that in 2015 for accounting purposes Saipem was a fully consolidated subsidiary as Eni still exercised control at the balance sheet date. In 2016 due to the loss of control, Saipem was derecognized from the beginning of the year. Therefore, in 2016 the purchases of capital goods and services from Saipem were accounted as expenses from third parties incurred by the continuing operations. In FY 2016, the Group net loss pertaining to Eni’s shareholders amounted to €1,464 million. This included a loss in the discontinued operations of €413 million relating to an impairment charge taken to align the book value of Eni’s retained interest in Saipem to its fair value, equal to the market capitalization at the date of loss of control (January 22, 2016) with a charge of €441 million. 94 The table below sets forth for the reported periods details of certain, identified gains and charges included in net loss. These gains and charges mainly related to inventory holding gains and losses, asset impairments, reversals of prior impairment losses, estimate revisions, risk and other provisions, write downs of deferred tax assets, capital gains on investments and other tangible assets. Eni Group Year ended December 31, 2014 2015 2016 (€ million) (Profit) loss on inventory ........................................................................ Environmental provisions ....................................................................... Impairment losses (impairment reversals), net ........................................... Impairment of exploration projects ......................................................... Net gains on disposal of assets ................................................................ Risk provisions ..................................................................................... Provision for redundancy incentives ......................................................... Fair value gains/losses on commodity derivatives ....................................... Reclassification of currency derivatives and translation effects to management measure of business performance ......................................... Estimate revision of revenues accrued in the gas retail business ................... Valuation allowance of disputed receivables .............................................. Write-off of the damaged units of the EST conversion plant at the Sannazzaro refinery ............................................................................... Provision for removal and clean-up of EST conversion plant ...................... Compensation gain on part of a third-party insurer relating to the EST plant incident ....................................................................................... Other ................................................................................................... 1,460 179 1,272 (24) (35) 4 (16) 229 1,136 225 6,534 169 (407) 211 30 164 (63) 484 303 301 Total net charges (gains) in operating profit ............................................... 3,372 8,784 Capital gains on disposal of investments .................................................. Write downs of investments and financing receivables ................................ Write down of deferred tax assets/utilization of deferred tax liabilities ......... Gain on a tax dispute relating to the Libyan Tax ....................................... Tax effects on the above listed items and other items .................................. Tax effects on (profit) loss on inventory .................................................... (159) (38) 1,045 (824) (13) (452) (33) 506 1,740 (1,321) (354) (175) 193 (459) 7 (10) 151 47 (427) (19) 161 410 193 24 (217) 279 158 (57) 483 170 (98) 55 Net (charges) gains in net profit ............................................................... 2,931 9,322 711 Net (charges) gains attributable to non-controlling interest ......................... 452 53 Net (charges) gains attributable to Eni ...................................................... 2,479 9,269 711 In evaluating the Company’s underlying performance and with the objective of better explaining year-on-year changes, management has considered to separate from the other drivers of the Group performance the impact of the following items: • • the above listed gains and charges amounting to a post-tax loss of €9,269 million and €711 million in 2015 and in 2016, respectively, which include an inventory holding post-tax loss of €782 million in 2015 and a post-tax profit of €120 million in 2016; and profit on intercompany transactions with the discontinued operations for €514 million in 2015, which are eliminated upon consolidation. On that basis, management has calculated a Non-GAAP measure of operating profit that would amount to €2,315 million for 2016, down by €2,171 million from 2015. A low commodity price environment accounted for a decline of €3.3 billion, while a four-month and half shutdown of operations at Val d’Agri and lower non-recurring gains in G&P accounted for €0.6 billion. Efficiency gains and a 95 reduced cost base, mainly in the E&P segment, helped mitigate the negative factors and improved the performance by €1.7 billion. The corresponding Non-GAAP measure of net loss would amount to €340 million, down by €1,143 million from 2015 due to a lower operating performance, declining results from equity-accounted entities reflecting weak commodity prices and a higher Group tax rate mainly driven by the E&P segment. Adjusted operating profit (or loss) and adjusted net profit (or loss) provide management with an understanding of the results from our base operations by excluding the effects of certain disposals and special charges or gains that do not reflect the ordinary results of our operations. Adjusted measures of profitability are used to evaluate our period-over-period operating performance, as management believes these provide a more comparable measure as they adjust for disposals and special charges or gains not reflective of the normal trend results of our business. These Non-GAAP performance measures may be useful to an investor in evaluating the underlying operating performance of our business, because the items excluded from the calculation of such measures can vary substantially from company to company depending upon accounting methods, management’s judgement, book value of assets, capital structure and the method by which assets were acquired, among other factors. The table below provides a reconciliation of those Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS. GAAP measure of operating profit of continuing operations .................... Identified net charges and inventory holding gains and losses ................ Elimination upon consolidation of intercompany transactions with discontinued operations .................................................................... Non-GAAP measure of operating profit of continuing operations ............. GAAP measure of net profit of continuing operations ............................. Identified net charges and inventory holding gains and losses ................ Elimination upon consolidation of intercompany transactions with discontinued operations .................................................................... Non-GAAP measure of net profit of continuing operations ...................... GAAP measure of net cash provided by operating activities from continuing operations ......................................................................... Elimination upon consolidation of intercompany transactions with discontinued operations .................................................................... Non-GAAP measure of net cash provided by operating activities from continuing operations ......................................................................... Year ended December 31, 2014 2015 2016 (€ million) 8,965 3,372 (3,076) 8,784 2,157 158 (1,114) 11,223 1,720 2,479 (476) 3,723 (1,222) 4,486 (7,952) 9,269 (514) 803 2,315 (1,051) 711 (340) 14,469 12,875 7,673 (925) (720) 13,544 12,155 7,673 Hydrocarbons production was substantially stable y-o-y in spite of a 19% reduction in capital expenditures. Project re-phasing and the renegotiation of contracts for the supply of plants and equipment drove the capital reduction. The Group replaced 193% of the reserves produced due to progress in development activities, exploration success and the FID taken at the Zohr gas project, off Egypt. The effectiveness of our exploration activity was proven by the finalization of the transactions to dispose of a 40% interest in the Zohr discovery, with a value to Eni of approximately €2 billion, which includes the reimbursement of the cost incurred in 2016 for developing and operating activities. Even discounting the Zohr 40% disposal, our proved reserve replacement ratio would remain significant at 139%. In 2016, we started several new capital projects, including Goliat in the Barents Sea and Kashagan in Kazakhstan. In 2017, we expect new large field start-ups, including the OCTP oilfield in Ghana, the East Hub project in Angola, started up in February 2017, the Jangkrik gas complex in Indonesia and the Zohr project. In 2017, we forecast a production growth of approximately 5% due to the full ramp-up of fields started in 2016 and new projects coming on stream. In 2016, net cash provided by operating activities from continuing operations amounted to €7,673 million. The closing of the Saipem transaction generated approximately €5.2 billion of proceeds and was 96 one of the main drivers in the Group’s net borrowings reduction y-o-y; other disposals amounted to €0.6 billion. These inflows funded part of financial requirements for capital expenditure (€9,180 million), the payment of Eni’s dividend (the final dividend for fiscal year 2015 and the 2016 interim dividend totaling €2,881 million) and finally the amount cashed out to subscribe the share capital increase of Saipem (€1,069 million). Management also assessed the Group net cash provided by operating activities excluding the negative effect of the Val d’Agri shutdown, which amounted to €0.2 billion, the reimbursement in-kind of certain financing receivables due by a joint venture to Eni with trading receivables, which negatively impacted the operating cash flow for €0.3 billion, while changes in working capital due to the sale of the 40% interest in Zohr would have improved cash flow by €0.1 billion. On that basis, net cash provided by operating activities would have funded a large part of 2016 capital expenditure of €9.2 billion, particularly when considering that approximately €0.5 billion of capex incurred in the year will be reimbursed to Eni because of the Zohr transaction in 2017. The Group’s net debt decreased by €2,095 million to €14,776 million. The Group ratio of finance debt to total equity at year-end 2016 was 0.51. However, in assessing the Group financial structure, management is using a measure of indebtedness which subtracts cash and cash equivalents and other very liquid financial assets from finance debt. This Non-GAAP measure of indebtedness is defined “net borrowings” (see Glossary). The ratio of net borrowings to total equity is defined “Leverage” (see Glossary) and is commonly used by management in assessing the Group financial condition (see paragraph “Financial condition” below). Leverage at year-end 2016 decreased to 0.28 down from 0.29 at the end of 2015 and was below the 0.30 threshold set by management in spite of a two-year downturn in crude oil prices. In 2017, we are projecting a capital expenditure budget of approximately €7.6 billion, 18% lower than in 2016 at constant exchange rates, while confirming an increase in production by approximately 5% compared to 2016. We also plan to preserve our liquidity by leveraging on the timely development of capital projects in the Exploration & Production in order to achieve the scheduled time-to-market of our reserves, on cost efficiencies across all businesses and on strengthening profitability at our Gas & Power and Refining & Marketing and Chemical segments. We plan to generate additional funds through our asset disposal program, which will mainly comprise the dilution of our working interests in certain of our exploration discoveries. In March 2017, we signed a preliminary agreement to divest to ExxonMobil a stake of 25% in our exploration asset Area 4 in Mozambique for a cash consideration of $2.8 billion. Finally, notwithstanding a weak commodity prices environment, we are planning to confirm our base dividend of €0.8 per share for fiscal year 2017. Trading environment Average price of Brent dated crude oil in U.S. dollars(1) ............................ Average price of Brent dated crude oil in euro(2) ...................................... Average EUR/USD exchange rate(3) ....................................................... Standard Eni Refining Margin (SERM)(4) .............................................. Euribor - three month euro rate %(3) ...................................................... 2014 2015 2016 98.99 74.48 1.329 3.2 0.21 52.46 47.26 1.110 8.3 (0.02) 43.69 39.47 1.107 4.2 (0.26) (1) (2) (3) (4) Price per barrel. Source: Platt’s Oilgram. 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). Source: ECB. In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields. When the term margin is used in the following discussion, it refers to the difference between the average selling prices and reflects the trading environment and are, 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 97 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”. In 2016, the trading environment was characterized by a continued weakness in crude oil prices, particularly in first half of the year due to oversupplies. In the second half of the year, market conditions started to improve and oil prices recovered part of first-half losses. This was driven by a better balance between global demand and supplies on the back of the agreement reached by OPEC Countries at the end of November 2016 to reduce the output of the cartel, joined also by certain non OPEC countries (among which Russia). Despite this recovery, the average price for the Brent crude oil benchmark declined by 17% y-o-y. A weak commodity scenario (mainly in the United States and in Europe) affected gas realizations on equity production, also reflecting time lags in oil-linked price formulas. Eni’s refining margins (Standard Eni Refining Margin - SERM) that represents the benchmark for the level of profitability of Eni’s refineries before fixed cash expenses, halved from a year ago (down by 49.4%) to $4.2 per barrel due to structural headwinds in the European refining industry. The Company managed to reduce its breakeven margin and to align it with the current trading environment, exceeding the planned breakeven target of $4.5 per barrel. Gas prices in the Company’s Gas & Power segment declined y-o-y driven by continued oversupplies, weak demand growth and the constraints connected minimum off-take obligations provided by long-term gas purchase contracts with take-or-pay clause. In addition to declining spot sale prices, in 2016 also the differential between Italian hub prices and European hub ones (PSV vs. TTF) contracted and negatively affected the G&P segment’s results. The exchange rate of euro against the dollar was 1.107, stable compared to the average exchange rate recorded in 2015. Critical accounting estimates The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the carrying amounts of assets and liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience or other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas assets, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, pensions and other post-retirement benefits, and recognition of environmental liabilities. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates is provided in “Item 18 – note 6 – of the Notes on Consolidated Financial Statements”. 2014-2016 Group results of operations Adoption of the Successful effort method (SEM) Effective January 1, 2016, management elected to change the criterion to recognize exploration expenses adopting the successful-effort-method (SEM). The successful-effort method is largely adopted by oil&gas companies, to which Eni is increasingly comparable given the recent re-focalization of the Group activities on its core upstream business. Under the SEM, geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an unproved tangible 98 asset until the drilling of the well is completed and the results have been evaluated. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an unproved asset. If it is determined that development will not occur then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons are initially capitalized as an unproved tangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to proved property. In accordance to IAS 8 “Accounting policies, Changes in accounting estimates and Errors”, the retrospective application of the SEM has required adjustment of the opening balance of several items as of January 1, 2014. Specifically, the opening balance of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items. In the table below, the key line items of the profit and loss and balance sheet are presented with reference to the full years 2014 and 2015 previously reported, and as restated in accordance with the application of SEM and the cessation of the accounting of Eni’s Chemical segment as a disposal group held for sale. In 2015, the Chemical segment was presented as discontinued operations due to an ongoing negotiation at the 2015 balance sheet date designed to establish an industrial joint venture with a third party who had expressed an interest in acquiring a majority stake of Eni’s chemical arm. In 2016 Eni and the potential buyer could not come to an agreement and the accounting of Versalis as discontinued operation ceased with retroactive effects to the date of initial recognition as discontinued operations. Full year 2014 Operating profit (loss) - continuing operations ............................................. Operating profit (loss) E&P ....................................................................... Net profit (loss) attributable to Eni’s shareholders - continuing operations ....... Total assets .............................................................................................. Eni’s shareholders equity ........................................................................... Net cash flow ........................................................................................... Full year 2015 Operating profit (loss) - continuing operations ............................................. Operating profit (loss) E&P ....................................................................... Net profit (loss) attributable to Eni’s shareholders - continuing operations ....... Total assets .............................................................................................. Eni’s shareholders equity ........................................................................... Net cash flow ........................................................................................... AS PREVIOUSLY REPORTED AS RESTATED (€ million) 7,585 10,766 101 146,207 59,754 1,183 (2,781) (144) (7,680) 134,792 51,753 (1,414) 8,965 10,727 1,720 150,366 63,186 1,183 (3,076) (959) (7,952) 139,001 55,493 (1,405) 99 Overview of the profit and loss account for three years ended December 31, 2014, 2015 and 2016 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. Net sales from operations ................................................................. Other income and revenues(1) ........................................................... Total revenues ................................................................................. Operating expenses ......................................................................... Other operating (expense) income ..................................................... Depreciation, depletion and amortization .......................................... Impairment losses (impairment reversal), net ..................................... Write-off ....................................................................................... OPERATING PROFIT (LOSS) ....................................................... Finance income (expense) ................................................................ Income (expense) from investments ................................................... PROFIT (LOSS) BEFORE INCOME TAXES .................................. Income taxes .................................................................................. Net profit (loss) - continuing operations ............................................... Net profit (loss) - discontinued operations ............................................ Year ended December 31, 2014 2015 2016 98,218 1,079 99,297 (80,333) 145 (7,676) (1,270) (1,198) 8,965 (1,167) 476 8,274 (6,466) 1,808 (949) (€ million) 72,286 1,252 73,538 (59,967) (485) (8,940) (6,534) (688) (3,076) (1,306) 105 (4,277) (3,122) (7,399) (1,974) 55,762 931 56,693 (47,118) 16 (7,559) 475 (350) 2,157 (885) (380) 892 (1,936) (1,044) (413) Net profit (loss) ............................................................................... Attributable to: Eni’s shareholders: .......................................................................... - continuing operations .................................................................... - discontinued operations ................................................................. Non-controlling interest: ................................................................. - continuing operations .................................................................... - discontinued operations ................................................................. 859 (9,373) (1,457) 1,303 1,720 (417) (444) 88 (532) (8,778) (7,952) (826) (595) 553 (1,148) (1,464) (1,051) (413) 7 7 (1) Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income. The table below sets forth certain income statement items as a percentage of net sales from operations for the periods indicated. Year ended December 31, 2014 2015 2016 (%) Operating expenses ....................................................................................... Depreciation, depletion, amortization, impairments (reversal of assets) net, write-off ...................................................................................................... OPERATING PROFIT ................................................................................ 81.8 83.0 84.5 10.3 9.1 22.4 (4.3) 13.3 3.9 2016 compared to 2015. See management discussion under paragraph “Executive summary” on page 90 for an overview of the Group’s results from continuing operations. Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €1,464 million for 2016. The loss of the discontinued operations pertaining to Eni’s shareholders (€413 million) was affected by the recognition of a charge of €441 million due to the 100 alignment of Eni’s retained interest in Saipem with its market value the date of the loss of control (January 22, 2016). The market value of the retained interest in the former subsidiary was the carrying amount of such interest upon initial recognition for the subsequent accounting under the equity method (€564 million to which a share capital increase of €1,069 million is to be added). 2015 compared to 2014. Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €8,778 million for 2015. The loss of the discontinued operations pertaining to Eni’s shareholders was negatively affected by the recognition of an impairment loss on the disposal group Saipem the net assets of which were aligned to the lower of their carrying amounts and fair value. Eni’s net asset in Saipem were aligned to the share price at the reporting date, recording an impairment charge of €393 million. Partly offsetting, a fair-valued derivative gain of €49 million was recorded for Saipem due to the difference between the transaction price (€8.39 per share) and the market price at the reporting date (€7.49 per share) relating the stake under disposal. Discontinued operations The table below sets forth net profit (loss) attributable to discontinued operations for the periods indicated. Net profit - discontinued operations ........................................................... attributable to: - Eni .................................................................................................... - non-controlling interest ........................................................................ Year ended December 31, 2014 2015 2016 (€ million) (949) (1,974) (413) (417) (532) (826) (1,148) (413) Based on the accounting of IFRS 5 for disposal groups, gains and losses pertaining to the discontinued operations include only those earned from transactions with third parties. Until such time as Saipem was a subsidiary of the Eni Group (i.e. end of the reporting period 2015), gains and losses on intercompany transactions have been eliminated upon consolidation. These comprised mainly revenues earned by Saipem for the supply of capital goods and maintenance services to Eni’s Group companies, which were eliminated upon consolidation, positively affecting results of the continuing operations, while negatively affecting the results of operations of the discontinued operations. This effect did not recur in 2016 due to the derecognition of Saipem effective January 1, 2016. Furthermore, the 2015 loss from discontinued operations included the alignment of Saipem’s net assets to its market capitalization at the balance sheet date leading to a loss of €393 million. Analysis of the line items of the profit and loss account of continuing operations a) Total revenues Eni’s revenues from continuing operations were €56,693 million, €73,538 million and €99,297 million for the years ended December 31, 2016, 2015 and 2014, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations from continuing operations amounted to €55,762 million, €72,286 million and €98,218 million for the year ended December 31, 2016, 2015 and 2014, respectively, and its other income and revenues totaled €931 million, €1,252 million and €1,079 million, respectively, in these periods. 101 Net sales from operations from continuing operations The table below sets forth, for the periods indicated, the net sales from operations from continuing operations generated by each of Eni’s business segments including intragroup sales, together with consolidated net sales from operations. Year ended December 31, 2014 2015 2016 Exploration & Production ............................................................... Gas & Power .................................................................................. Refining & Marketing and Chemicals ................................................ Corporate and other activities .......................................................... Impact of unrealized intragroup profit elimination(1) ........................... Consolidation adjustment(2) ............................................................. 28,488 73,434 28,994 1,429 54 (34,181) (€ million) 21,436 52,096 22,639 1,468 16,089 40,961 18,733 1,343 (25,353) (21,364) NET SALES FROM OPERATIONS ............................................... 98,218 72,286 55,762 (1) (2) This item mainly concerned intra-group sales of goods, services and capital assets recorded at period end in the assets of the purchasing business segment. Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The largest intragroup sales are recorded by the Exploration & Production segment. “Item 18 – note 46 – of the Notes on Consolidated Financial Statements” for a breakdown of intragroup sales by segment for the reported years. 2016 compared to 2015. Eni’s net sales from operations (revenues) from continuing operations for 2016 (€55,762 million) decreased by €16,524 million from 2015 (or down 22.9%) primarily reflecting lower realizations on oil, products and natural gas due to significantly lower commodity prices. Changes in sales volumes of products sold were immaterial. Revenues generated by the Exploration & Production segment (€16,089 million) decreased by €5,347 million (or down by 24.9%). This was due to lower average realizations on equity hydrocarbons (down by 20.1% on average in dollar terms) driven by declining prices for the marker Brent (down by 16,7%) and gas benchmarks in Europe, in the United States and elsewhere also considering the time lags in oil-linked formulas. The reduction was also negatively affected by the Val d’Agri shutdown, which lasted four and half months. The negative price impact was mainly recorded at concession contracts, while PSA contracts are insulated from the scenario due to the cost recovery mechanism. Revenues generated by the Gas & Power segment (€40,961 million) decreased by €11,135 million (or down by 21.4%). The reduction reflected lower gas and power selling prices as well as lower commodity prices in the business of crude oil and refined products trading, which impact was however offset at the operating profit level by a corresponding decrease in the supply costs of the commodities. Furthermore, revenues were also negatively affected by a downward revision of revenues accrued on the sale of gas and power to retail customers in Italy (€161 million) dating back to past reporting periods prior to 2015. Revenues generated by the Refining & Marketing and Chemical segment (€18,733 million) decreased by €3,906 million (or down by 17.3%) mainly reflecting lower average selling prices driven by weaker commodity prices. The average selling prices in the Chemical business declined by 10% due to lower price of polymers (down by 6.7% and down by 6.3% the average price of elastomers and styrenics, respectively), reflecting the impact of scenario and competitive pressure. 2015 compared to 2014. Eni’s net sales from operations (revenues) from continuing operations for 2015 (€72,286 million) decreased by €25,932 million from 2014 (or down by 26.4%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms due to significantly lower commodity prices. This negative trend was partially offset by a favorable exchange rate environment and increased sales volumes in the Exploration & Production segment, as well as higher Eni’s refining throughputs. Revenues generated by the Exploration & Production segment (€21,436 million) decreased by €7,052 million (or down by 24.8%) due to lower oil&gas realizations in dollar terms (down by 44.3% on average) reflecting the lower price for the marker Brent and lower gas prices in Europe and in the United States. 102 Lowered hydrocarbons realizations in dollars reduced reported revenues by approximately €12 billion. This effect was partly offset by favorable exchange rate differences in translating dollar-denominated revenues into the euro representation currency for €3.3 billion and higher production volumes sold for €1.6 billion. The negative price impact was mainly recorded at concession contracts, while PSA contracts are insulated from the scenario due to the cost recovery mechanism. Revenues generated by the Gas & Power segment (€52,096 million) decreased by €21,338 million (or down by 29.1%). The reduction reflected lower commodity prices in the business of crude oil and refined products trading, which impact was however offset by a corresponding decrease in the supply costs of the commodities. Furthermore, gas selling prices continued to deteriorate reflecting, in addition to the commodity price environment, weak gas demand and increasing competitive pressure. Revenues were also impacted an estimate revision of revenues accrued on the sale of gas (€346 million) and power (€138 million) to retail customers in Italy dating back to the past reporting periods. Revenues generated by the Refining & Marketing and Chemicals segment (€22,639 million) decreased by €6,355 million (or down by 21.9%) mainly reflecting lower average sales prices products driven by lower commodity prices. b) Operating expenses The table below sets forth the components of Eni’s operating expenses for the periods indicated. Year ended December 31, 2014 2015 2016 Purchases, services and other ............................................................ Payroll and related costs .................................................................. 77,404 2,929 (€ million) 56,848 3,119 44,124 2,994 Operating expenses .......................................................................... 80,333 59,967 47,118 2016 compared to 2015. Operating expenses from continuing operations for 2016 (€47,118 million) decreased by €12,849 million y-o-y, down by 21.4%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale). Purchases, services and other costs included €360 million relating mainly to environmental provisions ((€436 million in 2015). Payroll and related costs (€2,994 million) decreased by €125 million from 2015, down by 4%, due to lower average number of employees outside Italy. 2015 compared to 2014. Operating expenses from continuing operations for 2015 (€59,967 million) decreased by €20,366 million from 2014, down by 25.4%, primarily reflecting lower supply costs of raw materials (natural gas under long-term contracts, refinery feedstock and hydrocarbons purchased for resale) due to underlying trends in the energy scenario partially offset by negative exchange rate effects. Purchases, services and other costs included €436 million relating to environmental and other risk provisions, net of reversal of unused provisions. In addition, an allowance to the provision for doubtful accounts was recognized in 2015 in the retail Gas & Power business to take in account an estimate revision of revenues accrued on the sale of natural gas and electricity (€226 million; €130 million for gas sale and €96 million for electricity) to retail customers in Italy dating back to past reporting periods. Payroll and related costs (€3,119 million) increased by €190 million from 2014, up by 6.5%, due to the appreciation of the U.S. dollar against the euro. These effects were partially offset by lower average number of employees. 103 c) Depreciation, depletion, amortization, impairments (impairments reversal) net and write-off The table below sets forth a breakdown of depreciation, depletion, amortization, impairments (impairments reversal) net and write-off for the periods indicated. Exploration & Production .................................................................... Gas & Power ....................................................................................... Refining & Marketing and Chemicals ..................................................... Corporate and other activities ............................................................... Impact of unrealized intragroup profit elimination(1) ................................ Total depreciation, depletion and amortization .......................................... Impairment losses ................................................................................ Reversals of impairment losses .............................................................. Write-off ............................................................................................ Year ended December 31, 2014 2015 2016 (€ million) 8,080 363 454 71 (28) 8,940 6,537 (3) 688 6,916 335 381 70 (26) 7,676 1,334 (64) 1,198 6,772 354 389 72 (28) 7,559 1,067 (1,542) 350 Total depreciation, depletion, amortization, impairment losses (impairment reversals), net and write off .................................................................... 10,144 16,162 7,434 (1) This item concerned mainly intra-group sales of goods and capital, recorded at period end in the assests of the purchasing business segment. 2016 compared to 2015. In 2016, depreciation, depletion and amortization charges (€7,559 million) decreased by €1,381 million from 2015, or 15.4%, mainly in the Exploration & Production segment (with a decrease of €1,308 million) reflecting lower capital expenditures of the year (down by 16.2%) and the lower carrying amounts of certain oil&gas properties following the impairment losses booked in 2015 (€5,212 million). In 2016, the Group recorded reversals of prior impairment losses at oil&gas properties for €1,440 million. These were determined by an upward revision to the long-term price of the benchmark Brent to 70 $/barrel, up from the previous 65 $/barrel assumption, which drove the financial projections of the 2017-2020 industrial plan and the recoverability of oil&gas assets carrying amounts in the 2016 financial statements. These reversals were partly offset by impairment losses related to gas properties in the upstream business driven by a lowered price outlook in Europe and other oil&gas properties due to contractual changes, reserves revision and a higher country risk (overall amount of €756 million). Finally, investments made for compliance and stay-in-business purposes were fully impaired at cash generating units previously written-off in the Refining & Marketing and Chemicals segment, which were confirmed to lack any prospects of profitability (€104 million), while the Gas&Power segment recorded €81 million related to a gas transport infrastructure and LNG carriers. The write-off amounting to €350 million, mainly related to the costs of exploratory wells lacking the requisites for continuing capitalization because they did not encounter commercial quantities of hydrocarbons or due to lack of management commitment. The item also comprised the write-off of the damaged units of the EST conversion plant at the Sannazzaro Refinery due to the accident occurred in December 2016 (€193 million). 2015 compared to 2014. In 2015, depreciation, depletion and amortization charges (€8,940 million) increased by €1,264 million from 2014, or 16.5%, mainly in the Exploration & Production segment (increasing by €1,164 million) reflecting the appreciation of the U.S. dollar against the euro and higher production volumes. In 2015, impairment charges of €6,534 million related to oil&gas properties (€5,212 million) driven by the projections of lower hydrocarbon prices in the medium to long-term, which affected their recoverable amounts. The most notable impairments refer to certain assets, which were acquired by the Group following business combinations in previous reporting periods (Algeria, Congo and Turkmenistan) and to CGUs which are currently operating in high-cost areas (United States, United Kingdom, Norway and Angola). Furthermore, investments made for compliance and stay-in-business purposes were written off at 104 cash generating units previously written-off in the Refining & Marketing and Chemicals segment, which were confirmed to be lacking any prospects of profitability. Finally, impairment losses were recorded at the Group power plants in the G&P segment due to a weak margins scenario. The amount of write-offs of exploration project was also mainly driven by management’s decision to cease committing funds to certain projects in light of the deteriorated oil price environment. d) Operating profit (loss) by segment The table below sets forth Eni’s operating profit from continuing operations by business segment for the periods indicated. Exploration & Production .................................................................. Gas & Power .................................................................................... Refining & Marketing and Chemicals .................................................. Corporate and other activities ............................................................ Impact of unrealized intragroup profit elimination ................................ Year ended December 31, 2014 2015 2016 (€ million) (959) (1,258) (1,567) (497) 1,205 10,727 64 (2,811) (518) 1,503 2,567 (391) 723 (681) (61) Operating profit (loss) ........................................................................ 8,965 (3,076) 2,157 The table below sets forth operating profit (loss) from continuing operations for each of Eni’s business segments as a percentage of each segment’s net sales from operations from continuing operations (including intragroup sales) for the periods presented. Year ended December 31, 2014 2015 2016 Exploration & Production ................................................................................. Gas & Power .................................................................................................... Refining & Marketing and Chemicals ................................................................. 37.7 0.1 (9.7) (%) (4.5) (2.4) (6.9) 16.0 (1.0) 3.9 Group ............................................................................................................. 9.1 (4.3) 3.9 Exploration & Production. In 2016, the Exploration & Production segment reported an operating profit of €2,567 million, with an increase of €3,526 million from the operating loss of €959 million reported in 2015. This change mainly reflected the impairment charges of €5,212 million recorded in 2015 due to a downward revision of the oil scenario, while in 2016 net impairment reversals of €684 million were recorded due to a hike in management long-term oil price assumptions. In 2016, the Company’s liquids and gas realizations decreased on average by 20.1% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude prices decreased by 16.7%). Eni’s average oil realizations decreased on average by 15.4%. Eni’s average gas realizations decreased by 28.2% and were negatively impacted by the weak scenario and time lags in oil-linked formulas. In 2015, the Exploration & Production segment reported an operating loss of €959 million, with a decrease of €11,686 million from 2014. The decline was principally due to reduced oil&gas realizations in dollar terms (down 44.3% on average) and increased impairment charges (up by €4,361 million). The negative impacts were only partially offset by a favorable exchange rate environment, higher production volumes and reduced operating expenses. In 2015, the Company’s liquids and gas realizations decreased on average by 44.3% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude price decreased by 47%). Eni’s average oil realizations decreased on average by 47.8%. Eni’s average gas realizations decreased by 33.8%. 105 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 core business performance across reporting periods. Excluding the below-listed gains and charges, the E&P segment reported a Non-GAAP operating profit of €2,494 million, with a decrease of €1,688 million from 2015, or 40.4%. The decrease was driven by a weak commodity environment which drove reduced oil&gas realizations in dollar terms (down by 20.1% on average) and a four-month and half production shutdown at the Val d’Agri site. These negatives were partly offset by higher production in other areas and lower operating expenses and DD&A driven by continuing efficiency initiatives and optimization, as well as lower carrying amounts of oil&gas assets due to the impairments recorded in 2015. Exploration & Production GAAP operating profit (loss) ................................................................. Impairment losses (impairment reversals), net ......................................... Risk provisions ................................................................................... Impairment of exploration projects(1) ..................................................... Net gains on disposal of assets .............................................................. Provision for redundancy incentives ....................................................... Fair value gains/losses on commodity derivatives ..................................... Reclassification of currency derivatives and translation effects to management measure of business performance ....................................... Valuation allowance of disputed receivables ............................................ Other ................................................................................................. Year ended December 31, 2014 2015 2016 (€ million) (959) 5,212 0 169 (403) 15 12 10,727 853 (5) (70) 24 (28) 6 (59) 172 195 2,567 (684) 105 7 (2) 24 19 (3) 410 51 Total gains and charges ......................................................................... Non-GAAP operating profit (loss) .......................................................... 952 11,679 5,141 4,182 (73) 2,494 (1) Management has separately disclosed the results of the impairment review conducted at certain ongoing exploration projects where management ceased its commitment due to a deteriorated commodity price environment. Gas & Power. In 2016, the Gas & Power segment reported an operating loss of €391 million, improving by €867 million compared to 2015 when the segment reported an operating loss of €1,258 million. The 2015 result was negatively affected by a downward estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). In 2016, accrued revenues were revised lower by €161 million relating reporting periods prior to 2015. Furthermore, commodity derivatives lacking criteria for being accounted as hedges generated approximately €500 million of higher gains in 2016. In 2015, the Gas & Power segment reported an operating loss of €1,258 million, down by €1,322 million from 2014 when the segment reported an operating profit of €64 million. The change reflected one-off gains associated to certain contracts renegotiation recorded in 2014, as well as the negative outcome of a commercial arbitration in 2015. Furthermore, the 2015 result was affected by an estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). Management estimates revenues accrued in the retail sales business utilizing data communicated by market operators that are responsible for verifying actual consumptions with the possibility to review their measurements until the fifth subsequent reporting period. In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating loss of €390 million, with a decline of €264 million from 2015. This negative trend was due to lower margins in the LNG business on sales to premium markets and lower one-off benefits from contracts renegotiations, partly offset by logistics costs optimizations and better performance in trading activities. The retail segment reported lower results due to unusual winter weather conditions. 106 The items excluded from GAAP operating profit in determining the Non-GAAP measure of profitability mainly include certain fair-valued derivatives and accruals measurements. Particularly, we enter into commodity and currency derivatives to reduce our exposure to (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas and power or to lock in a commercial margin once a sale contract has been signed or it is highly probable, and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge net Group exposure to commodities and exchange rates but do not meet the requirements for being accounted as hedges in accordance to IFRS. Therefore in explaining year-on-year charges and in evaluating the business performance management believes that is appropriate to identify the fair value of commodity derivatives because they relate to transactions that will close in subsequent reporting periods or we estimate the portion of gains and losses on the settlement of certain commodity derivatives which underlying physical transaction has yet to be settled with the delivery of the underlying commodity. Furthermore, albeit the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivable and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and alignment differences of our trade payables and receivables as part of the underlying business performance. Finally, management has excluded from GAAP operating profit the remeasurement of revenues accrued in the retail gas and power business because they relate to past reporting periods. Gas & Power GAAP operating profit (loss) ................................................................... (Profit) loss on inventory ........................................................................ Impairment losses .................................................................................. Risk provisions ..................................................................................... Allowance for doubtful accruals in the retail G&P ..................................... Provision for redundancy incentives ......................................................... Fair value gains/losses on commodity derivatives ....................................... Reclassification of currency derivatives and translation effects to management measure of business performance ......................................... Revision of estimate revenues accruals in the retail G&P ............................ Other ................................................................................................... Total gains and charges ........................................................................... Non-GAAP operating profit (loss) ............................................................ Year ended December 31, 2014 2015 2016 (€ million) (1,258) 132 152 226 6 90 (9) 484 51 1,132 (126) 64 (119) 25 (42) 9 (38) 205 64 104 168 (391) 90 81 17 4 (443) (19) 161 110 1 (390) Refining & Marketing and Chemicals. In 2016, the Refining & Marketing and Chemicals segment reported an operating profit of €723 million, reversing an operating loss of €1,567 million reported in 2015. The improvement of €2,290 million was mainly due to lower assets impairments because a €1 billion charge was recognized in 2015 at the Chemical business to align its carrying amount with the expected fair value based on a sale transaction then ongoing designed to establish an industrial joint venture. Furthermore, in 2015 an inventory write-down of €877 million (pre-tax) was accounted for in the profit and loss because of the fall in oil commodity prices to align the net realizable value of the inventories to prices current at the balance sheet date. In 2016, following a late-year recovery in price scenario, the write down resulted in a gain on stock. The 2016 operating profit in the Refining & Marketing and Chemicals segment was also negatively affected by the write-off related to the EST conversion plant, at Sannazzaro Refinery, following an event occurred in December 2016, and the provision for removal and clean-up (a total amount of €217 million), partially offset by the recognition of third-party insurance compensation (€122 million) In 2015, the Refining & Marketing and Chemicals segment reported an operating loss of €1,567 million, thereby reducing operating losses by €1,244 million compared to 2014, when this segment reported an operating loss of €2,811 million. The losses reported in 2014 and in 2015 were due to inventory write-down of €1,746 million (pre-tax) in 2014, and of €877 million in 2015, as a consequence of the fall in commodity prices. Both losses included a charge to align the net book value of inventories to their net realizable values at the reporting date, as well as the difference between the current cost of supplies and the one used for IFRS inventory accounting based on the weighted average cost. 107 Results in 2015 improved compared to 2014 also for a positive refining scenario. The Eni benchmark for refining margins (Standard Eni Refining Margin – SERM) improved from 3.2 $/BBL to 8.3 $/BBL. Results benefited from initiatives to optimize operations, to reduce costs and to improve energy efficiency. The main item excluded from GAAP operating profit in determining the Non-GAAP measure of profitability is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies. In 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 gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the R&M and Chemical segment reported a Non-GAAP operating profit of €583 million, with a reduction of €112 million from 2015. The segment base performance in 2016 was negatively affected by an unfavorable margin scenario, as the Eni benchmark for refining margins, the Standard Eni Refining Margin – SERM was down by 49%, from 8.3 $/BBL in 2015 to 4.2 $/BBL in 2016. Other negative drivers were a planned shutdown of the Livorno refinery for extensive maintenance and the shutdown of EST plant at the Sannazzaro refinery due to the accident occurred at the beginning of December 2016. Moreover, marketing recorded lower results reflecting weaker margins due to stronger competitive pressure and asset disposals in Slovenia and Hungary. These negative trends were counteracted by continuing efficiencies and plant optimization, which drove a reduction in the refining breakeven margin down to $4.2 per barrel. The Chemical business’ results were affected by an unfavorable trading environment, which hit commodity margins. Refining & Marketing and Chemicals GAAP operating profit (loss) .................................................................. (Profit) loss on inventory ....................................................................... Environmental provisions ...................................................................... Impairment losses ................................................................................ Net gains on disposal of assets ............................................................... Risk provisions .................................................................................... Provision for redundancy incentives ....................................................... Fair value gains/losses on commodity derivatives ..................................... Reclassification of currency derivatives and translation effects to management measure of business performance ........................................ Other .................................................................................................. Year ended December 31, 2014 2015 2016 (€ million) (2,811) 1,746 138 380 43 (4) 41 18 37 (1,567) 877 137 1,150 (8) (5) 8 68 5 30 723 (406) 104 104 (8) 28 12 (3) 3 26 Total gains and charges ......................................................................... Non-GAAP operating profit (loss) ........................................................... 2,399 (412) 2,262 695 (140) 583 108 Corporate and Other activities. These activities are mainly cost centers comprising holdings and treasury, headquarters, central functions like information technology, human resources, self-insurance activities, as well as the Group environmental clean-up and remediation activities performed by the subsidiary Syndial. The aggregate Corporate and Other activities reported an operating loss of €681 million in 2016 representing an increase of €184 million from 2015, or 37%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures. The aggregate Corporate and Other activities reported an operating loss of €497 million in 2015 representing a decrease of €21 million from 2014, or 4.1%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures. e) Net finance expenses The table below sets forth a breakdown of Eni’s net financial expenses for the periods indicated: Net finance expense Gain (loss) on derivative financial instruments ................................................. - Options ............................................................................................... - Derivatives on exchange rate .................................................................. - Derivatives on interest rate ..................................................................... Exchange differences, net ............................................................................... Net income from financial activities held for trading ......................................... Interest income ............................................................................................ Finance expense from banks on short and long-term debt ................................. Finance expense due to the passage of time ..................................................... Other finance income and expense, net ............................................................ Finance expense capitalized ........................................................................... Year ended December 31, 2014 2015 2016 (€ million) 160 33 96 31 (354) 3 19 (838) (291) (171) (1,472) 166 165 68 51 46 (415) 24 19 (871) (293) 41 (1,330) 163 (482) 24 (494) (12) 676 (21) 15 (757) (312) (110) (991) 106 (1,167) (1,306) (885) 2016 compared to 2015. In 2016, net finance expenses were €885 million, down by €421 million compared to 2015 reflecting the recording of currency gains partly offset by negative fair value adjustments on currency derivatives (for a net positive effect of €440 million), with the latter lacking the formal criteria to be designated as hedges under IFRS. Furthermore, lower finance expense on debt were recorded due to the reduction in net borrowings and to lower interest rates reflecting accommodative monetary policies adopted by the Central Banks worldwide. These positives were partly offset by impairment losses on certain financing receivables granted to equity-accounted entities which are currently executing industrial projects on Eni’s behalf (€121 million). Furthermore, a discount expense of €129 million was recognized relating to certain receivable in the E&P segment owed by certain NOCs due to agreements to repay the overdue amount in instalments with the proceeds associated with mineral initiatives. On that basis, the discount rate utilized reflected also the mineral risk. 2015 compared to 2014. In 2015, net finance expenses were €1,306 million, up by €139 million compared to 2014. The higher gains on derivatives on exchange rate (up €45 million) which did not meet the formal criteria to be designated as hedges under IFRS were more than offset by the negative effect of the impairment of receivables and securities for financing operating activities related to a Nigerian project following the revision of the commodity price scenario. The balance of net expenses was helped by a reduction in the liability relating to the fair-valued options (€33 million) embedded in the convertible bond relating to Snam shares. The reduction reflected the exercise of the option to convert the bond in Snam shares for approximately 6% of the share capital of the investee, with the remaining portion of the bond corresponding to approximately 2% of the share capital closer to maturity. 109 f) Net income from investments 2016 compared to 2015. In 2016 the Group reported a net loss from investments of €380 million and mainly related to: (i) results of equity-accounted entities (an overall net loss of €326 million), mainly reported by the Exploration & Production segment due to a weaker commodity scenario and the economic difficulties recorded in certain Countries with a negative impact on the level of inflation and exchange rates. Particularly, the segment incurred a loss of €144 million mainly related to our joint ventures in Venezuela (PetroSucre, which book value was completely written off, Cardón IV and PetroBicentenario) driven by changed economics due to the local currency devaluation and rising inflation leading to escalating operating costs. (ii) a loss of €144 million was recorded on the equity-accounted interest retained in Saipem. This was driven by the recognition of asset impairment charges and other extraordinary expenses accounted for in Saipem’s results due to the impairment review performed by the investee at its CGUs based on its updated industrial plan. That plan, announced in October 2016, factored in a slower recovery in the oil market and in investment plans of the international oil companies; (iii) net losses on the divestment of interests (€14 million) mainly relating to the disposal of the residual 2.22% interest in Snam (€32 million), offset by gains on the divestment of interests (€18 million) mainly of the 100% share in Slovenija doo, Eni Hungaria Zrt and other non-core interests; (iv) other losses mainly relating to an impairment charge recorded in G&P related to the interest in Unión Fenosa Gas SA (€84 million) due to a reduced profitability outlook and the impairment of receivables in the E&P segment owed by the equity-accounted PetroSucre SA for dividends resolved but yet to be paid (€65 million). These losses were partly offset by dividends received from entities accounted for at cost (€143 million) relating to Nigeria LNG Ltd (€76 million) and Saudi European Petrochemical Co (€45 million). 2015 compared to 2014. Net income from investments in 2015 was a net gain of €105 million and mainly related to: (i) dividends received from entities accounted for at cost (€402 million), relating to Nigeria LNG Ltd (€222 million) and Snam SpA (€72 million); (ii) gains on disposal of investments (€164 million) which related to a gain recorded on the sale of an 8% interest in Galp (€98 million), gains on the divestment of a 6.03% interest in Snam (€46 million), gains on the divestment of refining infrastructures in Eastern Europe (€70 million), as well as the loss (€47 million) related to the divestment of minor assets in the Gas & Power business in Argentina; and (iii) other net gains including the alignment to stock price at December 31, 2015 of the Snam stock prices pertaining to Eni after the exercise of the conversion right by the bondholders (€49 million calculated on the 2.22% interest owned by Eni at the closing date). Those gains were partly offset by impairment losses registered in the business: (i) E&P relating to Angola LNG Ltd amounting to €469 million, including production and operating costs related to the start-up of liquefaction plant due to the revision of commodity scenario; and (ii) Gas & Power related to the interest on Unión Fenosa Gas SA (€49 million). These gains are further explained in “Item 18 – note 20 – Investments – of the Notes on Consolidated Financial Statements”. g) Taxes 2016 compared to 2015. In 2016, income taxes amounted to €1,936 million, down by €1,186 million compared to 2015, or 38%. These lower charges mainly reflected lower write-downs of deferred tax assets in connection with improved projections of future taxable profit against which those assets would be utilized compared to 2015. Particularly, in 2015 deferred taxes were written down by €1,740 million relating to foreign subsidiaries of the E&P segment and Italian subsidiaries due to a deteriorated profitability outlook. By contrast, the write-downs of deferred tax assets in 2016 were offset by write-ups. In addition, considering the expected outcome of ongoing negotiations to settle disputed receivables owed by the Nigerian national oil company, the Company utilized a provision for deferred tax liabilities for €380 million as those receivables were considered tax-deductible. 110 In 2015 and in 2016, the Group reported tax rate was much higher than the Group historical tax rates. This negative trend was negatively affected by the increased share of taxable profit earned in PSA contracts which bear higher-than-average rates of tax. Furthermore, in many jurisdictions where the Group reported pre-tax losses, the Company was not in the position of recognizing deferred tax assets, due to lack of sufficient future taxable profit against which those tax assets would be utilized. Management is estimating that in the four-year plan 2017-2020 the Group tax rate will progressively normalize in line with an expected recovery in the E&P results in concession contracts and an expected recovery in the pre-tax profit of Italian subsidiaries due to the ongoing upgrading plans at our G&P, R&M and Chemical businesses. 2015 compared to 2014. In 2015, income taxes amounted to €3,122 million, down by €3,344 million compared to 2014, or 51.7%, mainly reflecting lower income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to a declining taxable profit. In spite of the fact that in 2015 Eni’s group pre-tax earnings were a loss, the Group incurred a net tax expense. This negative development was influenced by a higher tax rate in E&P. The main drivers of this were three. First, the segment’s taxable profit was mainly earned in PSA contracts, which, although more resilient in a low-price environment due to the cost recovery mechanism, nonetheless bear higher-than-average rates of tax. Secondly, there was higher incidence of certain non-deductible expenses on the pre-tax profit lowered by the scenario. In addition, the tax rate was impacted by lower recognition of deferred tax assets relating operating losses due to a reduced profitability outlook (€1,058 million). The Group tax rate was also impacted by the write-off of Italian deferred tax assets and other changes of €1,607 million in the full year due to projections of lower future taxable profit at Italian subsidiaries and the reduction of the statutory tax rate from 27.5% to 24%, which was considered as substantially enacted at the reporting date. Liquidity and capital resources Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures and acquisitions over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of non-strategic assets. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and balanced financing structure. 111 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. Net profit - continuing operations ................................................................ 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 ...................................................................... - net gains on disposal of assets .................................................................. - dividends, interest, taxes and other changes ............................................... Changes in working capital related to operations .......................................... Dividends received, taxes paid, interest (paid) received during the period ......... Net cash provided by operating activities - continuing operations ...................... Year ended December 31, 2014 2015 2016 (€ million) 1,808 (7,399) (1,044) 10,898 (224) 6,600 2,199 (6,812) 14,469 17,216 (577) 3,215 4,781 (4,361) 12,875 7,773 (48) 2,229 2,112 (3,349) 7,673 Net cash provided by operating activities - discontinued operations ................ Net cash provided by operating activities ....................................................... 273 14,742 (1,226) 11,649 Capital expenditures - continuing operations .................................................. Capital expenditures - discontinued operations ............................................. Capital expenditures .................................................................................. Investments and purchases of consolidated subsidiaries and businesses ........... Disposals of consolidated subsidiaries, businesses, tangible and intagible assets and investments .................................................................................... Other cash flow related to investing activity (*) (**) ...................................... Changes in short and long-term finance debt ............................................... Dividends paid and changes in non-controlling interests and reserves ............. Effect of changes in consolidation, exchange differences and cash and cash (11,178) (694) (11,872) (408) (10,741) (561) (11,302) (228) 7,673 (9,180) (9,180) (1,164) 3,684 21 (628) (4,434) 2,258 (1,651) 2,126 (3,477) 1,054 5,736 (766) (2,885) equivalents related to discontinued operations .......................................... 78 (780) (3) Change in cash and cash equivalents for the year ............................................ 1,183 (1,405) 465 Cash and cash equivalents at the beginning of the year ................................. Cash and cash equivalents at year end ......................................................... 5,431 6,614 6,614 5,209 5,209 5,674 (*) For 2016, the item also includes the reimbursement of intercompany financing loans owed to Eni by Saipem for € 5,818 million. (**) Net cash used in investing activities included investments in and divestments of certain financial assets (mainly bank deposits) to absorb temporary surpluses of cash or as part of our ordinary management of financing activities. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. Furthermore, due to the Company’s decision to retain a cash reserve by investing the proceeds of the disposal plan in the purchase of held-for-trading securities, net cash used in investing activities also includes investments and divestments of those securities. Also these held-for-trading financial assets are netted against finance debt in determining the Group net borrowings. For more information on their composition see Note No. 9 to the Consolidated Financial Statements. For the definition of net borrowings, see “Financial Condition” below. Cash flows of such investments were as follows: (€ million) 2014 2015 2016 Investing activity: - securities ................................................................................... - financing receivables ................................................................... Disposal: - securities ................................................................................... - financing receivables ................................................................... Net cash flows used in investing activity ............................................ (19) (519) (538) 32 92 124 (414) (140) (343) (483) 1 182 183 (300) (1,317) (272) (1,589) 6,860 6,860 5,271 112 The table below sets forth the principal components of Eni’s change in net borrowings (1) for the periods indicated. Year ended December 31, 2014 2015 2016 Net cash provided by operating activities ..................................................... Capital expenditures ............................................................................... Acquisitions of investments and businesses ................................................ Disposals ............................................................................................... Other cash flow related to capital expenditures, investments and divestments .. Net borrowings(1) of acquired companies .................................................. Net borrowings(1) of divested companies ................................................... Exchange differences on net borrowings and other changes .......................... Dividends paid and changes in minority interest and reserves ....................... 14,742 (11,872) (408) 3,684 435 (19) (850) (4,434) (€ million) 11,649 (11,302) (228) 2,258 (1,351) 7,673 (9,180) (1,164) 1,054 465 83 (818) (3,477) 5,848 284 (2,885) Change in net borrowings(1) ...................................................................... 1,278 (3,186) 2,095 Net borrowings(1) at the beginning of the year ............................................ Net borrowings(1) at year end ................................................................... 14,963 13,685 13,685 16,871 16,871 14,776 (1) Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below. Analysis of certain components of Eni’s change in net borrowings In 2016, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization, impairment charges and reversals and the write-off of tangible and intangible assets (€7,434 million). Adjustments to net profit also included accrued income taxes (€1,936 million) and interest expense (€645 million), which were more than offset by amounts actually paid (€2,941 million and €780 million, respectively). In 2015, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization, impairment charges (impairment reversals, net) and write-off of tangible and intangible assets (€16,162 million). Adjustments to net profit also included gains on disposals (€577 million) relating mainly to the sale of a number of oil&gas properties in Nigeria, accrued income taxes (€3,122 million) and interest expense (€659 million) more than offset by amounts actually paid (€4,295 million and €692 million, respectively). Cash-outs for income taxes were partly offset by the reimbursement and the disposal to financing institutions of certain tax receivables due to the parent company (approximately €900 million). a) Changes in working capital related to operations In 2016, working capital generated an inflow of €2,112 million. This was mainly due to a positive balance between trade receivables collected and trade payables paid (a net inflow of €2,781 million) which reflected the higher volume of trade receivables due subsequently to the reporting date which were sold to financing institutions compared to the previous reporting period (about €1 billion). This inflow was partly offset by utilizations of the risk provision for €1,043 million, part of which related to the settlement of obligations towards third parties mainly in the G&P segment also in relation to the final award of an arbitration procedure involving a long-term gas buyer. Conversely an advance made to the same buyer in the previous reporting period was utilized. Finally the working capital inflow was partly absorbed by a reimbursement in-kind of a financing receivable due by an equity-accounted entity operating a gas field in Venezuela with trading receivables (€300 million) due by the Venezuelan state-owned oil company (PDVSA). Finally a positive adjustment related the item other current assets and liabilities (up by €647 million) which mainly reflected the impairment of receivables owed by National Oil Companies due to the expected outcome of ongoing negotiations to settle disputed amounts. The G&P segment was the main driver of the cash inflow from working capital in 2016, reflecting also non-recurring trends. We expect that the G&P working capital contribution will normalize going forward. 113 In 2015, changes in working capital were positive for €4,781 million as a result of: (i) a positive balance between trade receivables collected and trade payables paid (a net inflow of €2,602 million), which was mainly driven by a positive performance in the Gas & Power segment; (ii) decreasing inventories (a positive €1,638 million) as a result of the alignment of the book value of crude oil and products to market prices (this item being an adjustment of the inventory loss recorded in net profit and as such is not a cash item), as well as reduced inventory levels in R&M due to optimizations measures; and (iii) a positive inflow related to other current assets and liabilities (up by €498 million) which mainly reflected a net positive inflow in the Gas & Power segment due to the collection of pre-paid volumes of gas under take-or-pay contracts and the collection of receivables from supplied long-term customers. These inflows were partly offset by a greater exposure of the E&P segment towards joint venture partners. b) Investing activities Exploration & Production ......................................................................... Gas & Power ............................................................................................ Refining & Marketing and Chemicals .......................................................... Corporate and other activities .................................................................... Impact of unrealized intragroup profit elimination ....................................... Capital expenditures - continuing operations .................................................. Capital expenditures - discontinued operations ............................................. Capital expenditures .................................................................................. Acquisitions of investments and businesses ..................................................... Year ended December 31, 2014 2015 2016 (€ million) 9,980 154 628 64 (85) 10,741 561 11,302 228 10,156 172 819 113 (82) 11,178 694 11,872 408 8,254 120 664 55 87 9,180 9,180 1,164 12,280 11,530 10,344 Disposals ................................................................................................. (3,684) (2,258) (1,054) Capital expenditures totaled €9,180 million and €11,302 million, respectively in 2016 and in 2015. For a discussion of capital expenditures by business segment and a description of year-on-year changes see below “Capital expenditures by segment”. Acquisition of investments and businesses totaled €1,164 million in 2016 and €228 million in 2015. In 2016, they comprised the subscription of the share capital increase of Saipem (€1,069 million) and minor contribution to equity-accounted entities. In 2016, disposals amounted to €1,054 million and mainly related to: (i) the divestment of the 12.503% interest in Saipem SpA to CDP Equity SpA in January 2016 (€463 million), an interest in Snam due to exercise of the conversion right by bondholders (€332 million) as well as fuel distribution activities in Eastern Europe. In 2015, disposals amounted to €2,258 million and mainly related to: (i) the divestment of an available-for-sale interest in Snam due to exercise of the conversion right by bondholders (€911 million); (ii) an available-for-sale interest in Galp Energia (€658 million) in order to reimburse an out-of-the-money convertible bond which was due in 2015; and (iii) the divestment of non-strategic assets in the Exploration & Production and in the R&M businesses. In 2016, other cash flow related to investing activities were positive for €465 million and included the reimbursement in-kind of a financing receivable owed by our equity-accounted entity Cardon IV for €300 million. Cardon IV reimbursed Eni with a trade receivable due by the Venezuelan State-owned oil company (PDVSA) on the supplies of gas volume produced at the Perla project. Furthermore, the production restart of the Kashagan field and the achievement of a production milestone in the fourth quarter of 2016 triggered the reimbursement of the first instalment of a receivable of the divestment of an interest of 1.71% of the project to the Kazakh national oil company occurred in 2008, with a cash-in of €152 million. 114 c) Dividends paid and changes in non-controlling interests and reserves In 2016, dividends paid and changes in non-controlling interests and reserves (€2,885 million) related almost exclusively to cash dividends to Eni shareholders (€2,881 million, of which €1,441 million relating to the 2016 interim dividend and €1,440 million to the final dividend for fiscal year 2015. In 2015, dividends paid and changes in non-controlling interests and reserves (€3,477 million) mainly related to: (i) cash dividends to Eni shareholders (€3,457 million, of which €1,440 million relating to 2015 interim dividend and €2,017 million to the balance dividend for fiscal year 2014); and (ii) the distribution of dividends to non-controlling interests by other consolidated subsidiaries (€21 million). Financial condition Management assesses the Group’s capital structure and capital condition by tracking net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. The Company is retaining a liquidity reserve, which comprises very liquid investments, mainly sovereign and corporate securities which management has selected based on their creditworthiness. This cash reserve was established by investing part of the proceeds from the disposal plan carried out in the latest years. Those securities amounted to €6,404 million as of end of 2016 and were accounted as mark-to-market financial instruments. For further information see “Item 18 – note 9 – 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. 115 The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure. As of December 31, 2015 2016 Short-term Long-term Total Short-term Long-term Total Finance debt (short-term and long-term debt) . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Securities held for trading and other securities held for non operating purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non operating financing receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,396 (5,209) (5,028) (685) 19,397 (€ million) 27,793 (5,209) (5,028) (685) 6,675 (5,674) (6,404) (385) 20,564 27,239 (5,674) (6,404) (385) Net borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,526) 19,397 16,871 (5,788) 20,564 14,776 Shareholders’ equity including non-controlling interest as per Eni’s (€ million) Consolidated Financial Statements prepared in accordance with IFRS .. Ratio of finance debt to total shareholders’ equity including non-controlling interest ... Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest .................. Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) ....................................................................................................... As of December 31, 2015 2016 57,409 0.48 53,086 0.51 (0.19) (0.23) 0.29 0.28 In 2016, net borrowings amounted to €14,776 million, representing a €2,095 million decrease from 2015. This reduction was driven by repayment of debt due to the net cash flows provided by operating activities of continuing operations (€7,673 million) and the closing of the Saipem transaction, which entailed net proceeds of €5.2 billion. These latter comprised the reimbursement of financing receivables due to Eni by the former subsidiary (€5,818 million), the proceeds of the disposal of a 12.503% interest in the entity (€463 million), net of the cash-out to subscribe pro-quota Saipem’share capital increase (€1,069 million). Other divestment for the year amounted to €0.6 billion and mainly related to an interest in Snam due to exercise of the conversion right by bondholders (€332 million) as well as fuel distribution activities in Eastern Europe. These inflows funded cash outflows relating to capital expenditures totaling €9,180 million and dividend payment to Eni shareholders amounting to €2,881 million, with the surplus used to pay down finance debt. Furthermore, the change in the Group net borrowing y-o-y was influenced by the reclassification of financial assets held by the Group captive insurance company as non operating assets, which have been netted against finance debt in determining the Group net borrowings (with a positive effect of €0.6 billion). In previous reporting periods, those financial assets were committed to fund the loss provision and as such were part of capital employed. The change in classification reflects new regulatory requirements applicable to the exercise of the insurance activity from January 1, 2016, based on the provisions of EU Solvency II Directive (the so-called Minimum Capital Requirement – MCR – and Solvency Capital Requirement – SCR). The new rules require that insurance companies meet certain capital and solvency ratios as minimum requirements to continue performing the insurance activity. Therefore, it is no longer necessary to commit the financial assets of the insurance company to funding the loss provisions. Accordingly, those assets, which mainly comprise available-for-sale securities and bank deposits, have ceased to be classified as held for operating purposes. The ratio of finance debt to total equity was 0.51 at 2016 year-end. The Group Non-GAAP measure of its financial condition “Leverage” was 0.28 at December 31, 2016 reporting a decrease from 0.29 as of the end of 2015. This decline was driven by lower net borrowing, the effects of which were partly offset by a reduction in the Group total equity as explained below. 116 Total equity decreased by €4,323 million from December 31, 2015. This was due to the net loss (€1,457 million), the derecognition of Saipem non-controlling interest (€1,872 million), as well as dividend distribution of €2,885 million (including the 2015 balance and the 2016 interim dividends paid to Eni’s shareholders amounting to €2,881 million). These effects were partially offset by a positive change in the cash flow hedge reserve (€883 million) and positive foreign currency translation differences (€1,198 million) due to the 3.2% depreciation of the euro against the US dollar at year end (down by 3.2% due to the exchange rate recorded on December 31, 2016 at 1.054 euro, compared to 1 euro = 1.089 US$ at December 31, 2015). Total debt of €27,239 million consisted of €6,675 million of short-term debt (including the portion of long-term debt due within twelve months equal to €3,279 million) and €20,564 million of long-term debt. Total debt included unsecured bonds for €19,003 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €3,724 million (including accrued interest and discount). Bonds issued in 2016 amounted to €2,984 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (90%), U.S. dollar (7%), British pound (2%) and 1% in other currencies. Capital expenditures by segment Exploration & Production. In 2016, capital expenditures of the Exploration & Production segment amounted to €8,254 million, mainly related to the development of oil&gas reserves (€7,770 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, Angola, Kazakhstan, Indonesia, Iraq, Ghana and Norway. Development expenditures in Italy also comprised the upgrading of certain plants at the Viggiano oil center in Val d’Agri, which did not alter the plant set up. This upgrading addressed certain objections made by jurisdictional Authorities about the proper function of the plants and were duly authorized by the competent department of the Italian Ministry of Economic Development. Due to this upgrading, plant activities were regularly restarted following notification by the public prosecutor that it has definitively repealed the plant seizure. (see – Item 4 – Exploration & production segment – Italy) as well as sidetrack and workover activities in mature fields. Exploration expenditures (€417 million) were directed in particular in Egypt, Indonesia, Libya and Angola. In 2015, capital expenditures of the Exploration & Production segment amounted to €9,980 million, mainly related to the development of oil&gas reserves (€9,341 million). Significant expenditures were directed mainly outside Italy, in particular Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia and the United States. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri, as well as sidetrack and infilling activities in mature fields. Exploration expenditures amounting to €566 million were directed outside Italy, in particular in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia. Gas & Power. In 2016, capital expenditures in the Gas & Power segment totaled €120 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (€41 million) and to develop the gas marketing activity (€69 million). In 2015, capital expenditures in the Gas & Power segment totaled €154 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (€69 million) and to develop the gas marketing activity (€69 million). Refining & Marketing and Chemicals. In 2016, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €664 million and regarded mainly: (i) refining activities in Italy and outside Italy (€298 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; (ii) marketing activity, mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the Rest of Europe (€123 million); (iii) upgrading and maintenance at petrochemical plants (€200 million). In 2015, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €628 million and regarded mainly: (i) refining activities in Italy and outside Italy (€282 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; (ii) upgrading and rebranding of the refined product retail network in Italy (€75 million) and in the Rest of Europe (€51 million); (iii) upgrading and maintenance at petrochemical plants (€177 million). 117 Recent developments The table below sets forth certain indicators of the trading environment for the periods indicated: Average price of Brent dated crude oil in U.S. dollars(1) .................... Average EUR/USD exchange rate(2) .............................................. Standard Eni Refining Margin (SERM)(3) ...................................... Three months ended December 31 2016 49.46 1.078 4.7 Three months ended March 31, 2016 33.89 1.102 4.2 January 1 through March 17, 2017 54.66 1.063 4.2 (1) (2) (3) Price per barrel. Source: Platt’s Oilgram. Source: ECB. In $/BBL, FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields. In the period January 1 – March 17, 2017 the Brent crude oil price was 54.66$/BBL on average, 61% higher than in the first quarter of 2016 and 10% higher than in the fourth quarter 2016. This trend will positively affect reported revenues, profitability and cash flow of our Exploration & Production segment. Significant transactions On March 9, 2017, Eni and ExxonMobil signed sale and purchase agreement whereby ExxonMobil is going to acquire a 25% indirect interest in the Area 4 block, offshore Mozambique. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The agreed terms include a cash price of approximately $2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore. This operating model will enable the use of best practices and skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project. The Company’s Annual General Shareholders Meeting scheduled on April 13, 2017, has been convened to approve the full year dividend proposal of €0.80 per share of which 0.4 paid as interim dividend in September 2016. Eni expects to pay the balance of the dividend for fiscal year 2016 amounting to €0.40 per share in April 2017. The total cash out is estimated at approximately €1.4 billion. Management’s expectations of operations Exploration & Production Management intends to boost the cash generation in the E&P segment leveraging on profitable production growth, capital discipline and strict control of operating expenses and project execution. Exploration activities will continue to be key to the Company’s growth prospects in the short and long-term. The Company is leveraging on its dual exploration model, which envisages both the rapid development of the discovered resources and the divestment of stakes of our exploration discoveries in order to accelerate the conversion of our resources into cash. The effectiveness of our dual exploration model has been proven by the divestment of a 40% interest in the Zohr gas discovery off Egypt, with a value to Eni of approximately €2 billion including the reimbursement of the capital expenditure incurred in 2016 to develop the prospect, as well as by the preliminary agreement signed for the divestment of a 25% interest in Area 4, offshore Mozambique with an expected cash consideration of approximately $2.8 billion. 118 We expect to increase our hydrocarbons production at an average rate of 3% across the 2017-2020 plan period. This growth target factors in the effects associated with our planned disposals. For 2017, we expect a production growth of approximately 5%. This grow will be fuelled organically by new fields start-ups, full production at the Goliat and Kashagan projects and the ramp-up of the other fields started in 2016, the recovery of the full plateau at the Val d’Agri profit center and continuing production optimization to fight fields natural decline. The main start-ups of 2017 include the Zohr gas field off Egypt expected at year-end, the oil&gas project of Offshore Cape Three Points in Ghana, the East Hub of Block 15/06 off Angola and the Jangkrik gas project in Indonesia. The East Hub project has already achieved first oil in February 2017. In subsequent years, we are planning new project start-ups in Egypt, Angola, Algeria and Norway. New field start-ups, production ramp-ups and continuing production optimization will add approximately 850 KBOE/d in 2020. We believe that those production targets have good visibility because they related to already-sanctioned projects, mostly of which are operated. Our production plans includes assumptions relating to production levels in Libya and Nigeria, which are exposed to risks of disruptions and political instability. In 2016, Libya represented approximately 20% of the Group total hydrocarbons productions for the year and going forward the contribution of Libya to our future production levels albeit slowing down will remain significant. To factor in possible risks of unfavorable geopolitical developments mainly in Libya but also elsewhere in other countries of Eni presence, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, social unrest, clashes and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. However, this contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. Our production plans are incorporating our Brent price scenario of 55 $/BBL in 2017 and a gradual recovery in the subsequent years up to our long-term case of 70 $/BBL in 2020 and going forwards (on constant monetary term compared to 2020, i.e. from 2020 onwards crude oil prices will grow in line with a projected inflationary rate). See “Item 4 – Exploration & Production”. Our recovery assumptions are based on the progressive rebalancing of global oil markets, which will be supported by the OPEC agreement reached in November 2016 to cut the cartel output joined also by non-Opec members and the effects of the curtailment in expenditures made by international oil companies during the downturn. However, there are some risks to this outlook, including effective compliance of OPEC member countries with the planned production quotas and the pace at which unconventional oil producers in the US will be able to bring production back to markets, leveraging the short-cycle nature of this business and rising productivity. Oil price assumptions are particularly significant when it comes to assessing the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. In 2016, the Company estimated that production entitlements in its portfolio of PSAs increased by approximately 20 KBOE/d, or 1,900 BBL/d for each $1 change in oil prices compared to 2015. We note that in case oil prices differ significantly from our own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different. Due to those risks and uncertainties, management intends to retain a strong focus on capital discipline, project execution and cost control. First, our capital budget in the E&P segment for the four-year plan 2017-2020 is estimated 13% lower than the previous capital plan 2016-2019 (in each cases net of the capex associated with planned disposals). In spite of an expected reduction in capital spending, our growth targets in 2017-2020 are above our previous planning assumptions relating the period 2016-2019 due to our phased approach in developing our production projects. This approach will enable the Company to reduce financial exposure and to accelerate production start-ups. Secondly, we intended to be more selective on investment options. Thirdly, we plan to seek opportunities for further reductions in our development and operating costs by renegotiating contracts for the supply of upstream plants, equipment and other infrastructures as well as the supply of oilfield services and drilling rates considering the uncertainties surrounding a recovery in expenditures by oil companies. Finally, management will focus on delivering the planned projects on time and on budget. Some of our projects are complex due to scale and reach of operations, environmentally-sensitive locations, external conditions, including offshore operations, industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. Furthermore, in the past we experienced delays and cost overruns at certain projects, which were caused by 119 (i) poor execution by our EPC contractors. We plan to mitigate those risks in the future by continuing deployment of our capabilities and by means of: in-sourcing critical engineering and project increasing direct control and governance on construction activities; (ii) management activities; (iii) deploying our employees and competences to manage hook-up and commissioning; and (iv) entering into framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants and increasing focus on supply chain programming to optimize order flows. Effective project execution has been boosted in recent years by our changed approach in exploration activities, which have been redirected towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies. Furthermore, phased project development and strict integration between exploration and development have improved the overall project execution and cost efficiency. 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. Management also plans to increase the share of operated production in the Company’s portfolio. We expect to operate more than 74% of the plan period production. Project operatorship enables the Company to better schedule and control project execution, expenditures and timely achievement of project milestones and to mitigate the operational risk associated with drilling activities at high pressure-high temperature wells and at deep waters well by deploying our technologies and competences. Eni estimates that these wells will represent approximately 13.5% of the planned wells to be drilled in 2017. In the next four years, our exploration activities will focus on supporting the replacement of produced reserves and on contributing to cash generation. Our exploration investment will be mainly directed to: i) Appraisal of the recent discoveries and near-field plays, where in case of success we can leverage on existing infrastructures in order to readily put into production the discovered resources; ii) Initiatives in new areas in proximity to end markets, targeting conventional prospects with high interests in order to implement our dual exploration model in case of material discoveries. Gas & Power We expect a weak outlook in the Gas & Power segment due to structural headwinds in the industry as we forecast sluggish demand growth, oversupplies and strong competition across all of our main markets in Europe, including Italy. We project a flat trend in gas demand in Europe and in Italy over the next four-year plan. Demand growth will be dampened by sluggish economic growth, rising competition from renewables and increasing energy efficiency. On the supply side, the growing importance of liquid hubs and large availability of LNG will drive continuing competition and pricing pressure. Going forward LNG supplies will be fueled by the coming on stream of several export terminals in the United States which will monetize the country’s large reserves of shale gas and the start-up of important LNG projects in the Pacific area. 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. Against this scenario, the Company priority in its Gas & Power business is to achieve structural profitability and retain positive cash generation. Our strategy in the Gas & Power sector will leverage on the renegotiations of our long-term gas supply contracts in order to align pricing and volume terms to current market conditions and dynamics, optimization of logistic costs, the development of our portfolio of highly profitable businesses and cost efficiencies and operational streamlining. Our take-or-pay, long-term supply contracts include revisions clauses whereby each counterpart has right to renegotiate the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Leveraging on recent renegotiations, 90% of our portfolio of supply contracts is currently indexed to HUB prices and will benefit the 2017 performance. Looking forward, we expect to fully align our supply portfolio to market conditions and dynamics in terms of both pricing and volumes. Our renegotiation efforts will seek to obtain cost indexation that will track our pricing formulas, to align our procurement costs to prices prevailing in the wholesale market, which includes sales to large industrial and 120 power companies and resellers, and to match our minimum contractual take with the dimension of our addressable market. The renegotiation strategy is subject to the constraints dictated by availability of the contractual windows. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will ultimately be achieved and the timing of recognition in profit. In case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration procedure could be commenced to solve the commercial dispute. Furthermore, Eni’s suppliers may file a counterclaim to dismiss Eni’s request for a price review or renewed contractual terms. These possible developments increase the risks and uncertainties relating the outcome of those renegotiations. Therefore, future results of the gas marketing activities are subject to increasing volatility and unpredictability. The expected termination of certain long-term gas supply contracts with take-or-pay clause will reduce Eni’s contractual minimum take and will add flexibility to Eni’s portfolio and renegotiation strategy. Furthermore, we plan to almost complete the recovery of our pre-paid gas volumes due to the triggering of the take-or-pay clause in past reporting periods. This asset amounted to €0.3 billion at 2016 year-end. We expect to improve profitability in gas marketing through initiatives intended to reduce logistic costs by reselling unutilized transport capacity to other operators and by possibly benefitting from expected liberalization measures in the European gas system designated to increase the liquidity of spot markets. The Company intends to grow its presence in market segments where margins can be sustained in the long-term. As part of this plan, we intend to strengthen our role as a global player in LNG trading where we plan to achieve steady profitability, also leveraging on integration with our upstream operations by marketing equity gas. We will seek to preserve margins on sales to large accounts by leveraging on the Company’s multiple presence across various markets and expertise in delivering innovative and tailor-made offering structures to best suit customers’ needs by providing complex pricing formulas, hedging against the commodity risk and flexibility in volumes collection. In the retail segment, our priority is to maximize profitability and cash generation through more effective and efficient operations. We will closely monitor the level of working capital and we will be more selective in new customer additions in order to reduce the portfolio risk and counterparty losses. We intend to increase the weight in our portfolio of customers who are willing to sign supply contracts in the open market rather than opting to use the regulated tariffs established by Italian gas authorities. The Company’s marketing effort will address retail customers in Italy and in the main European markets in order to valorize the existing customer base against the backdrop of escalating competitive pressures. This will be achieved by the offer of new products and services, brand identity, the administrative advantages of the dual offer of gas and electricity, a competitive cost to serve and continuing innovation in processes, promotion and customer care and post-sale assistance. We believe that offering a wide range of valuable services with the selling of the commodity will underpin the profitability of our retail operations considering that the regulatory modifications to the indexation of the raw material cost have substantially flatten the margin on the commodity. Management will also seek to improve profitability by means of cost efficiencies particularly by streamlining business support activities and reducing general and administrative costs. Finally, the Company intends to capture margins improvements by means of trading activities by entering into derivative contracts both in the commodity and the financial trading venues in order to capture possible favorable trends in market prices, within the limits set by internal policies and guidelines that define the maximum tolerable level of market risk. As part of this strategy, the Company intends to improve results of operations by effectively managing the flexibilities associated with the Company’s assets (gas supply contracts, transportation rights, storage capacities, unutilized power capacity). This can be achieved through strategies of asset-backed trading by entering into derivative contracts to leverage on commodity price volatility, the risks of which might be absorbed in part or entirely by the natural hedge granted by the asset availability. Asset-backed activities may lead to gains, as well as losses the amount of which could be significant. For further information on the market risk and how the Company manages it see “Item 11 – Quantitative and Qualitative Disclosures about Market Risk”. Based on the above outlined trends and industrial actions, management expects that we will retain profitable, cash-positive operations in the Company’s gas marketing business over the plan period. Our profitability outlook factors in the expected benefits of ongoing renegotiations of the Company long-term supply contracts which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3. These projections could be subject particularly to the risks of further contraction in demand or the total addressable market and the risks related to the outcome of contract renegotiations. For more information see the specific risk paragraph in “Item 3 – Risk factors”. 121 Refining & Marketing The outlook of the European refining sector is unfavorable due to structural headwinds in the industry pressured by overcapacity, stagnant fuel demand, energy efficiency and rising competition from cheaper products streams from the Middle East and other areas. Management expects refining margins in 2017 and going forward to remain around the weak levels registered in 2016 at about 4$ per barrel, where the Company’s refining business is at breakeven. At the end of the plan period it is projected an improvement in refining margins due to the enactment of a new regulation regarding the quality of fuel used in the bunker segment. Against this backdrop, the Company priority is to retain profitable and cash-positive operations even in a depressed downstream oil environment, by further reducing the breakeven margin of Eni refineries. The refining business has undergone a restructuring process resulting in a reduction of the installed capacity by more than 30% versus the 2012 baseline. This process has comprised the conversion of the Venice refinery into a green refinery for the production of bio-fuels based on a proprietary technology, the shutdown of Gela refinery, which is undergoing a transformation into a green refinery like the Venice site, asset disposals, the shutdown of unprofitable lines and other efficiency initiatives. We believe that additional optimization is needed considering the structural headwinds and volatility of the refining scenario. Our goal is to lower the breakeven margin to 3$ per barrel by 2018. The planned initiatives include the completion of the Gela project and the second phase of Venice upgrading, optimization of plant setup and continued efficiency gains in logistics, energy management and capital discipline. In Marketing activities, where we expect competitive pressure to continue due to weak demand trends, we are planning to achieve a gradual improvement in results of operations mainly by focusing on innovation of products and services anticipating customer needs, as well as efficiency in the marketing and distribution activities. Retail operations abroad will be focused on the core markets of Germany, Austria, Switzerland and France, where we intend to exploit synergies with Italian operations, brand awareness, a fair market share and development of non-oil activities to retain steadily profitable operations. We have completed the refocusing program of our portfolio of activities exiting Eastern Europe. Overall, we expect that under constant 2017 scenario assumptions, in the next four-year plan the business will generate enough cash to fund its capital expenditure plans and to generate a surplus. Chemical The outlook in the chemical business is unfavorable due to structural headwinds in the industry pressured by overcapacity, weak macroeconomic growth and rising competition from cheaper products streams from the Middle East, Far East and the US. In addition, our petrochemical commodities are exposed to the volatility of the crude oil-based feedstock costs. Like the R&M business, our chemical activity has undergone a deep restructuring process. Over the last few years, we have lowered the cost base and exposure to commodity risk by reducing capacity, divesting or exiting unprofitable lines, plant optimization and other efficiency measures as well as a shift in our product portfolio towards specialties, green chemicals and products with high technology content, which are less exposed to the scenario volatility. Looking forward we believe that further steps are needed to preserve profitable and cash-positive operations, including self-financing the business capital requirements. The industrial plan contemplates the completion of the restructuring process at unprofitable sites, increased plant flexibility and optimization, development of new products and specialties as well as the start-up of certain joint ventures in East Asia with local partners to produce and market elastomers. Overall, we expect that even under our conservative scenario assumptions the business will generate enough cash to cover its capital expenditures requirements along the plan period. 122 Capital expenditure plans Over the next four years, the Company plans to invest €31.6 billion, excluding capex associated with the disposal plan, to support continued organic growth in oil&gas production; approximately 86% of planned capital expenditures is expected to be directed to the Exploration & Production segment. Eni’s capital expenditure program is reflective of a lower oil price environment and of uncertainties about future trends in the oil markets. Our capital expenditure plan will be more selective than in the past and will focus on the more profitable projects in portfolio and on project re-phasing and modularization. These optimizations and curtailments, as well as wider portfolio effects are expected to drive an 8% reduction in capital expenditure compared to the previous plan at constant exchange rates and net of capital expenditures associated with our disposal activity, without sacrificing our production growth targets. E&P capital expenditure for the four-year plan is expected to decrease by 13% compared to the previous plan. In 2017 we expect overall capex in the range of €7.6 billion, down by 18% vs 2016 at a constant exchange rates and post portfolio transactions. Development of oil&gas reserves will attract some €25 billion. Project start-ups and plateau enhancement at existing fields will be geographically diversified and executed mainly in Egypt, with the development of the very important Zohr gas discovery, Mozambique, Italy, Iraq, Kazakhstan, Nigeria, Norway, Libya, Angola and Ghana. Egypt will attract approximately 20% of the Group capital expenditure over the plan period. Exploration capex will amount to €2.1 billion. Our projects will include appraisal of recent discoveries and near-field activities designed to provide fast production support and contribution to the cash flow, as well as new initiatives targeting conventional prospects with high working interest in order to support Eni’s dual exploration model in case of material discoveries. We are planning to invest approximately €2.2 billion in R&M which will mainly be directed to the completion of the Gela reconfiguration project, the repair of the EST unit at the Sannazzaro site and various initiatives of plant upgrading, as well as network upgrading. The Chemical business will attract approximately €1 billion for plant upgrading and selected growth initiatives. In G&P we intend to spend approximately €0.5 billion. Finally, we will invest approximately €0.5 billion to develop photovoltaic and other renewable-related power plants in our industrial properties in Italy or in countries where we are conducting E&P operations. Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 70 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2021 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital (“WACC”) to the Group. In 2016, management assessed that the cost of capital to the Group was marginally lower than in 2015 mainly due to a reduced premium for the sovereign risk incorporated into the yields on Italian ten-year bonds, partly offset by an increased volatility of the Eni share and an appreciation of the country risk. This latter factors in the perceived level of risk associated with each country of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework, as well as the consensus outlook. In 2016, our average premium for the country risk was higher than in 2015 due to a deteriorated political and financial outlook of certain countries where we are conducting upstream operations. A country risk premium is added to the Group WACC and a premium for the business risk in determining the hurdle rates, which are utilized by management in its final investment decisions. Liquidity and leverage Considering the uncertainties about future trends in market fundamentals and price volatility, management’s priorities remain to maximize cash generation and to preserve a solid balance sheet. We believe the initiatives implemented by management during the downturn intended to lower the cost base, to optimize investments and to streamline operations together with recent exploration success have improved the Company’s competitive position. Currently we are estimating that on average the Company will be able to fund its requirements for capital expenditures with cash flow from operations in a Brent price environment lower than 45 $/BBL on average in the next four-year plan. We have also evaluated our 123 financial resiliency considering our commitment to pay a floor dividend of €0.8 per share equating to approximately €2.9 billion per year. We estimate that in the 2017-2020 plan the Company will be able to fund through cash flow from operations both the planned capital expenditures and the floor dividend at 60 $/BBL in 2017 and at a Brent price lower than 60 $/BBL going forward. These targets are reflective of the Company’s initiatives in lowering its cost base and in optimizing its capital plan without impairing its ability to pursue its growth objectives. During the plan period, management expects to execute an asset disposal program in the range of €5-7 billion, which will comprise the dilution of interests in our exploration assets, non-strategic hydrocarbons producing assets and other marginal assets in the mid and downstream businesses. These expected cash inflows will improve the Group’s financial flexibility. These planned disposals exclude the already defined divestment of a 40% interest in the Zohr gas discovery, off Egypt, while they include the disposition of an interest in our exploration asset in Mozambique. During the downturn, in spite of the sharp contraction in the operating cash flow due to lower oil prices, the Company has managed to maintain its key ratio of net borrowings to equity – leverage – within the ceiling of 0.3 through a combination of cost cuts, asset disposals, capital expenditure curtailments and working capital optimization. At the end of 2016, our leverage stood at 0.28. Management believes that the target ceiling leverage is consistent with the Company’s business profile, which features an increasing exposure to the Exploration & Production segment. In 2017, we expect that the Company leverage will including the likely improve from 2016. This will be driven by the planned portfolio transactions, completion of the Zohr divestment, and an expected reduction of 18% in the Group capital expenditure at constant exchange rates versus 2016, post portfolio transactions. This forecast is also based on the Company’s projected levels of Brent prices at which cash flow from operations is expected to fund the planned capital expenditure for the year. Our cash flow projections are exposed to the volatility of the oil price environment. Currently, based on our portfolio of oil&gas properties, we estimate that, holding all other factors constant, our net profit and cash flow from operations vary by approximately €0.2 billion for each dollar change in Brent prices on a yearly basis compared to our price forecast. We note that the Brent price in the period January 1 to March 17, 2017 was approximately 55 $/BBL on average (it was 34 $/BBL on average in the period January 1 to March 31, 2016). We retain some levels of financial flexibility that we may use in case oil prices should take another leg down in the cycle in the remainder of the year. Particularly, approximately 37% of the planned investment in the four-year plan has been allocated to projects yet to be sanctioned. In addition, we retain cash reserves and committed and uncommitted borrowing facilities. For planning purposes, management assumed a EUR/USD exchange rate in the range of 1.08-1.20 U.S. dollars per euro in the 2017-2020 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty, as well as a potential positive driver of the Group results of operations, cash flow and balance sheet in case the U.S. dollar appreciates against the euro. We note that in the period January 1 to March 17, 2017 the EUR/USD exchange rate was approximately 1.06 and appreciated year-on-year. This trend will favorably affect the reported amounts of operating profit and operating cash flow in our Exploration & Production segment. However, the net impact of the U.S. dollar appreciation on the Group liquidity and net borrowings is uncertain as our capital expenditures are mainly denominated in U.S. dollars. See “Item 3 – Risk factors”. Dividend policy Considering the weak oil price environment, in 2015 the Company decided to rebase the annual dividend at €0.80 per share, which is our floor dividend. This floor dividend has been confirmed for fiscal year 2016. In 2017, we confirm our plan to pay a cash dividend of €0.80 per share. Going forward, we remain committed to a progressive distribution policy in line with our plans of underlying earnings and cash flow growth and the scenario evolution. This forecast is dependent on the results that ultimately will be achieved in implementing our strategy and on management’s estimations of the minimum level of Brent prices at 124 which the Company’s cash flows from operating activities are able to fund planned capital expenditures and dividend payments. This projected level of cash neutrality is dependent upon achievement of our plans of profitable production growth and upgrading of profitability in mid and downstream businesses. 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, political instability in Libya and other countries, crude oil and natural gas prices; demand for oil&gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by including adverse weather and natural disasters; and other changes to workers; environmental risks, business conditions. Please refer to “Item 3 – Risk factors”. Off-balance sheet arrangements Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in “Item 18 – note 38 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments under take-or-pay or ship-or-pay contracts in the gas business, are described under “Contractual obligations” below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses. Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources. Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in “Item 18 – note 38 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. 125 Contractual obligations The amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments. Total debt ...................................................... Long-term finance debt ..................................... Short-term finance debt ..................................... Fair value of derivative instruments ...................... Interest on finance debt ...................................... Guarantees to banks .......................................... Non-cancelable operating lease obligations(1) ............ Decommissioning liabilities(2) .............................. Environmental liabilities ..................................... Purchase obligations(3) ....................................... Natural gas to be purchased in connection with take-or-pay contracts(4) ..................................... Natural gas to be transported in connection with ship-or-pay contracts(4) ..................................... Other take-or-pay and ship-or-pay obligations ......... Other purchase obligations(5) .............................. Other obligations(6) ........................................... of which: - Memorandum of intent relating to Val d’Agri ......... Total 2017 2018 2019 2020 2021 2022 and thereafter 29,318 23,653 3,396 2,269 4,007 84 2,418 16,281 2,689 120,225 8,492 2,988 3,396 2,108 696 84 593 253 281 10,891 2,126 2,090 4,120 4,044 2,914 2,914 1,331 1,285 10,335 10,332 36 557 353 580 249 9,265 76 486 257 417 255 9,511 386 231 400 202 8,839 46 277 3 1,605 199 184 71 7,961 785 14,447 1,631 73,758 110,697 8,429 7,912 8,277 7,916 7,312 70,851 6,620 724 2,184 129 1,569 114 779 9 1,053 105 195 3 129 9 3 943 101 190 2 2 724 96 103 2 2 478 80 91 2 1,853 228 826 111 2 111 TOTAL ......................................................... 175,151 21,299 13,133 15,048 12,974 10,025 102,672 (1) (2) (3) (4) Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings. 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. Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Gas & Power – Natural Gas Purchases” and “Item 3 – Risk Factors – Risks in the G&P business. (5) Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States of euro 1,226 milion. (6) In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans (See Note 31 to the Consolidated Financial Statements). The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment as of December 31, 2016. 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. Committed projects ...................................................... 23,756 6,733 6,679 4,218 2,441 3,685 Total 2017 2018 2019 2020 (€ million) 2021 and subsequent years Liquidity risk Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the its assets on the marketplace as to be unable to meet short-term finance Group is unable to sell 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 126 requirements. The Group has also established a cash reserve, which consists of cash on hand and very liquid financial assets (short-term deposits and held-for-trading securities). This cash reserve according to management plans can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity over a 24-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”. As of December 31, 2016, Eni maintained short-term unused borrowing facilities of €12,308 million, of which €41 million committed. Long-term committed borrowing facilities amounted to €6,236 million, of which €700 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.3 billion were drawn as of December 31, 2016. Working capital Management believes that, taking into account unutilized credit facilities, Eni’s credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements. Credit risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amount due. For a description of how the Company manages the credit risk see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”. For information about credit losses in 2016 and the allowance for doubtful accounts see “Item 18 – note 10 of the Notes on Consolidated Financial Statements”. Market risk In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”. Research and development For a description of Eni’s research and development operations in 2016, see “Item 4 – Research and development”. 127 Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES Directors and Senior Management The following table lists the Company’s Board of Directors as at March 2017: Name Emma Marcegaglia Claudio Descalzi Andrea Gemma Pietro A. Guindani Karina A. Litvack Alessandro Lorenzi Diva Moriani Fabrizio Pagani Alessandro Profumo1 Position Chairman CEO Director Director Director Director Director Director Director Year elected or appointed Age 2014 2014 2014 2014 2014 2011 2014 2014 20152 51 62 43 59 54 68 48 50 60 In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members. The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on May 8, 20143 which also established the number of Directors at nine for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2016. 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 Gemma, Diva Moriani, Fabrizio Pagani and Luigi Zingales4 were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina Litvack and Alessandro Lorenzi were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Emma Marcegaglia as the Chairman of the Board of Directors and, on May 9, 2014, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company. The provisions designed to ensure gender balance were applied for the first time in the aforementioned elections. Three Directors out of nine, including the Chairman, were drawn from the less represented gender, thereby already reaching the ratio of one-third of the Directors, instead of the ratio of one-fifth as provided by the law for the first relevant election of the Board. The ratio of one-third of the Directors belonging to the less represented gender shall also apply to the next two subsequent terms of the Board of Directors. The following provides details on the personal and professional profiles of the Directors. Emma Marcegaglia was born in Mantua in 1965 and has been Chairman of Eni since May 2014. She has been Chairman of the Fondazione Eni Enrico Mattei since November 2014. She is also Chairman and CEO of Marcegaglia Holding SpA and Deputy Chairman and CEO of the subsidiary companies operating in the processing of steel. She is also Chairman and CEO of Marcegaglia Investments Srl, the holding company of the diversified activities of the group. She is President of Businesseurope and of the Luiss Guido Carli University, a member of the Board of Directors of Bracco SpA and Gabetti Property Solutions SpA. From 1994 to 1996 she was National Deputy President of Young Entrepreneurs of Confindustria, from 1997 to 2000 she was President of the European Confederation of the Young Entrepreneurs (YES), from 1996 to 2000 President of Young Italian Entrepreneurs of Confindustria and from 2000 to 2002 she was Vice President of Confindustria for Europe. From May 2004 to May 2008 she (1) (2) (3) (4) On July 29, 2015, the Board of Directors of Eni co-opted Alessandro Profumo as Director replacing Luigi Zingales, who resigned from the Board on July 2, 2015. The Director Profumo was confirmed by the Shareholders’ Meeting on May 12, 2016. Alessandro Profumo was Director of Eni from May 2011 to May 2014. On July 29, 2015, the Board of Directors of Eni co-opted Alessandro Profumo as Director replacing Luigi Zingales, who resigned from the Board on July 2, 2015. The Director Profumo was confirmed by the Shareholders’ Meeting on May 12, 2016. Luigi Zingales resigned from the Board on July 2, 2015. 128 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. She was a member of the Management Board of Banco Popolare and Director of Finecobank SpA and Italcementi SpA. She also held the position of Chairman of the Aretè Onlus Foundation. She graduated with a degree in business administration from the Bocconi University in Milan and attended a Master’s in Business Administration at New York University. Claudio Descalzi was born in Milan and has been Eni’s CEO since May 2014. He is a member of the General Board and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala. He is a member of the National Petroleum Council for 2016/2017. 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 Eni’s Exploration & Production Division. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer of Eni’s Exploration & Production Division. 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” 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”. He graduated with a degree in physics in 1979 from the University of Milan. Andrea Gemma was born in Rome in 1973 and has been Director of Eni since May 2014. He is Professor of Private Law at The Third University of Rome, Law Department, Member of the Strategic Board of the American University of Rome and Appeal Court Lawyer and Partner in the Law and Tax Firm Gemma & Partners. He is a Member of the Studies Centre of the Chamber of Arbitration of Rome. He is Deputy Chairman of Serenissima SGR SpA and Chairman of the Watch Structure in Sorgente SpA. He is a member of the Board of Directors of Banca UBAE SpA and of Global Capital PLC. He is President of Board of Statutory Auditors of PS Reti S.p.A. and Sirti S.p.A. He is a member of the Board of Directors of Cinecittà Centro Commerciale S.r.l. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA, Sequoia Partecipazioni SpA, Corit SpA and of Sigrec SpA (Unicredit Group). Pietro A. Guindani was born in Milan in 1958 and has been Director of Eni since May 2014. He is currently Chairman of the Board of Directors of Vodafone Italia SpA, Board member of FINECOBank SpA, Salini-Impregilo SpA and Cefriel S.cons.r.l. and of the Italian Institute of Technology, Board Member of Civita Foundation, Assonime and Confindustria, Member of the Executive Board of Assotelecomunicazioni, member of the Executive Board of Confindustria Digitale and Vice President for Universities, Innovation and Human Capital of Assolombarda. From 1982 to 1986 he was Relationship Banker at Citibank N.A. He then became International Finance Director in Montedison SpA (Enimont SpA) until 1992. He was Group Finance, Budget and Reporting Manager at European Vinyls Corporation SA/NV (1992-1993). In 1993 he became Head of Foreign Finance in Olivetti SpA. From 1995 to 2004 he was Chief Financial Officer of Vodafone Italy and of Vodafone South Europe, Middle East & Africa Region. From 2004 to 2008 he was Chief Executive Officer of Vodafone Italy. He was also Director of Pirelli & C. SpA (2011-2014), Carraro SpA (2009-2012) and Sorin SpA (2009-2012). He graduated with a degree in Business from the Università Luigi Bocconi in Milan. Karina A. Litvack was born in Montreal in 1962 and has been a Director of Eni since May 2014. She is currently a member of the Global Advisory Council of Cornerstone Capital Inc., a member of the Advisory Board of Bridges Ventures LLC, a member of the CEO Sustainability Advisory Panel of SAP AG, a member of Business for Social Responsibility and of Yachad and a member of the Advisory Council for Transparency International UK. 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 129 Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012). She graduated with a degree in Political Economy from the University of Toronto and in Finance and International Business from Columbia University Graduate School of Business. Alessandro Lorenzi was born in Turin in 1948 and has been Director of Eni since May 2011. He is a founding partner of Tokos Srl, a consulting firm for securities investment, Chairman of Società Metropolitana Acque Torino SpA and Director of Ersel SIM SpA and of Mutti SpA. He began his career at SAIAG SpA in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined GFT Group where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Operating Officer and was subsequently Director of Ersel SIM SpA until June 2000. In 2000 he became Executive Officer of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of Coin Group and in 2006 he became Chief Corporate Officer at Lavazza SpA, serving as a Board member from 2008 to June 2011. Diva Moriani was born in Arezzo in 1968 and has been a Director of Eni since May 2014. She is currently Executive Vice Chairman of Intek Group SpA, CEO of KME AG Vorstand, a German holding company of KME Group, Chairman of KME S.r.l., Member of the Supervisory Board of KME Germany GmbH and Director of Assicurazioni Generali SpA, Moncler SpA, Ergycapital SpA, Dynamo Academy, Dynamo Foundation and Associazione Dynamo. From 2007 to 2012 she was CEO of I2 Capital Partners, a private equity fund sponsored by Intek SpA, with an investment strategy focused on “Special Situations”. She graduated with a degree in Economics from the University of Florence. Fabrizio Pagani was born in Pisa in 1967 and has been a Director of Eni since May 2014. He is currently the Head of the Technical Secretariat of the Ministry of Economy and Finance. He was Deputy Director of the International Training Programme for Conflict Management at the S. Anna School of Advanced Studies in Pisa from 1995 to 1998, Professor of International Law in the Faculty of Political Science at the University of Pisa from 1993 to 2001, Deputy Chief of the Legislative Office at the Department of European Affairs from 1998 to 1999 and Counsellor for International Affairs in the Ministry of Industry and Foreign Trade from 1999 to 2001. He was Senior Advisor at the OECD from 2002 to 2006, Head of the Office of the State Undersecretary, within the Prime Minister’s Office from 2006 to 2008, a board member of SACE SpA from 2007 to 2008, Political Counsellor of the OECD General Secretary from 2009 to 2011, Director of the G8/G20 Office at the OECD from 2011 to 2013 and Senior Economic Counsellor to the Prime Minister and G20 Sherpa from 2013 to 2014. He was a NATO Fellow and was a visiting scholar at Columbia University, New York. He graduated with a degree in international studies from the Sant’Anna School of Advanced Studies, Pisa, and has a Master’s Degree from the European University Institute, Florence. Alessandro Profumo was born in Genoa in 1957 and has been Director of Eni since July 2015. He is currently Chairman of Equita SIM, of Appeal Strategy & Finance S.r.l. and member of the Supervisory Board of Sberbank. He is also a Board member of TOG “Together To Go”. In February 2012 he was appointed member of the International Advisory Board of Itau-UniBanco. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey, where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development and organization projects at Bain, Cuneo e Associati (now Bain & Company). In 1991 he left the field of company consultancy to join RAS, Riunione Adriatica di Sicurtà, where as General Manager he was responsible for the banking and parabanking sectors. He was also in charge of the yield increase of RAS’s bank and of the other companies in the group operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager and was in charge of Programming and Control, becoming General Manager in 1995. In 1997 he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On an international level he was Chairman of the European Banking Federation and Chairman of the IMC in Washington. In May 2004 he was decorated as Cavaliere del Merito del Lavoro. 130 From 2006 to 2014 he was Director of Bocconi University in Milan and from 2011 to 2014 he was Director of Eni and he was Chairman of Banca Monte dei Paschi di Siena from 2012 to 2015. He was Chairman of CASL (Comitato per gli Affari Sindacali e del Lavoro dell’ABI) from 2014 to 2015 and in February 2012 he was appointed a member of the “High-level Expert Group” on structural reform of the EU banking sector; he left the Group when he was appointed Chairman of Banca Monte dei Paschi di Siena. He graduated with a degree in business administration from the Università Luigi Bocconi of Milan. Senior Management The table below sets forth the composition of Eni’s Senior Management as at December 31, 2016. 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 Claudio Descalzi General Manager of Eni Luca Bertelli Chief Exploration Officer Roberto Casula Chief Development, Operations & Technology Officer Alberto Chiarini Chief Retail Market Gas & Power Officer Claudio Granata Chief Services and Stakeholder Relations Officer Massimo Mantovani Chief Midstream Gas & Power Officer Massimo Mondazzi Chief Financial Officer Giuseppe Ricci Chief Refining & Marketing Officer Antonio Vella Chief Upstream Officer Marco Bollini Legal Affairs Department Senior Executive Vice President Marco Petracchini Internal Audit Department Senior Executive Vice President Roberto Ulissi Corporate Affairs and Governance Department Senior Executive Vice President Board Secretary and Corporate Governance Counsel Marco Bardazzi External Communication Department Executive Vice President Luca Cosentino Energy Solutions Department Executive Vice President Pasquale Salzano Government Affairs Department Executive Vice President Luca Franceschini Integrated Compliance Department Executive Vice President Jadran Trevisan Integrated Risk Management Executive Vice President Year first appointed to current position Total number of years of service at Eni Age 2014 2014 2014 2016 2014 2016 (2) 2014 (3) 2016 (4) 2014 2016 (5) 2011 (6) 2006 (7) 2015 2015 2015 (8) 2016 (9) 2016 (10) 35 32 28 27 (1) 33 23 24 31 33 19 17 10 1 13 5 25 16 61 58 54 53 56 53 53 58 59 50 52 54 49 55 43 50 55 (1) (2) (3) (4) (5) (6) (7) (8) (9) It includes the period he served at Saipem SpA Prior to October 17, 2016, he was Chief Legal and Regulatory Affairs. Prior to September 12, 2016, he was Chief Financial and Risk Management Officer. Prior to September 12, 2016 he was Executive Vice President Health, Safety, Environment & Quality Department, but he did not report to Chief Executive Officer. Prior to October 17, 2016, he was Executive Vice President International and Finance Legal Department, but he did not report to Chief Executive Officer. Since 2014 the Senior Executive Vice President of the Internal Audit Department reports hierarchically to the Board of Directors and, on its behalf, to the Chairman, without prejudice to its functional dependence on the Control and Risk Committee and on the Chief Executive Officer (in his capacity as Director in charge of the Internal Control and Risk Management System). Since 2014, the Board Secretary has also served as Corporate Governance Counsel. The Board Secretary reports hierarchically and functionally to the Board of Directors and, on its behalf, to the Chairman. Prior to February 19, 2015, he was Senior Vice President Government Affairs. Prior to September 12, 2016, he was Executive Vice President Legal Compliance and Regulatory Department, but he did not report to Chief Executive Officer. (10) Prior to September 12, 2016 he reported to the Chief Financial and Risk Management Officer. 131 The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief Midstream Gas & Power Officer, the Chief Refining & Marketing Officer, the Chief Retail Market Gas & Power Officer, the Chief Financial Officer, the Chief Services & Stakeholder Relations Officer, the Senior Executive Vice President Legal Affairs Department, the Senior Executive Vice President Internal Audit Department, the Senior Executive Vice President Corporate Affairs and Governance Department, as well as the Executive Vice President Energy Solutions Department, the Executive Vice President External Communication Department, the Executive Vice President Government Affairs Department, the Executive Vice President Integrated Compliance Department, the Executive Vice President Integrated Risk Management, the Chief Executive Officer of Versalis SpA and the Chief Executive Officer of Syndial SpA are members of the Management Committee, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of Committee Secretary are performed by the Senior Executive Vice President Corporate Affairs and Governance Department. The Chief Financial Officer has been appointed as Officer in charge of preparing Company’s financial reports pursuant to Italian law by the Board of Directors, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors. The Senior Executive Vice President of the Internal Audit Department is appointed by the Board of Directors, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer (in his capacity as Director in charge of the internal control and risk management system), following consultation with the Board of Statutory Auditors and the Nomination Committee and with the favorable opinion of the Control and Risk Committee. The Board Secretary and Corporate Governance Counsel is appointed by the Board of Directors upon a proposal of the Chairman. Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause. Senior Managers Luca Bertelli was born in Sesto Fiorentino in 1958. He graduated cum laude with a degree in geology in 1983 from the University of Florence. In 1984 joined Eni’s geophysics division where he worked first as a researcher in the development of 3D seismic prospecting technology and subsequently as a manager of 3D seismic prospecting programs, and specializing in seismic-stratigraphy. In 1994, he was appointed Manager of seismic-stratigraphy applications and in 1999 expanded the technical-managerial scope of his activities becoming Eni’s Manager of geological and geophysical services. At the end of 2001, his career took a new international turn with roles of increasing managerial complexity over a period of eight years, starting in Norway where he was Technical Director and Deputy Managing Director of Norsk Agip. In 2003, he was appointed Managing Director of Eni Indonesia and in 2006, moved to Egypt as General Manager and Managing Director, a role he covered also at Eni Angola in 2007. In 2009, he returned to Eni’s headquarters as Senior Vice President Global Exploration. At the beginning of 2010, he was appointed Executive Vice President of Exploration and Unconventional. Since July 1, 2014, he has been Eni’s Chief Exploration Officer. Roberto Casula was born in Cagliari in 1962. He graduated with a degree in mining engineering from the University of Cagliari and joined Eni in 1988 as a reservoir engineer. He spent the first years of his professional life working at oilfields in Italy before moving to West Africa where he was appointed Chief Development Engineer. He returned to headquarters in 1997 as coordinator business development activities for Africa and the Middle East, contributing to a number of new initiatives and portfolio activities. In 2000, he became project technical services manager and in 2001, moved to the Middle East as Project Director on a giant gas production project. From 2004 to 2005, he held a number of managerial positions in the Exploration & Production Division, becoming Chief Executive Officer of Eni Mediterranea Idrocarburi SpA, engaged in oil&gas exploration and production in Sicily. At the end of 2005, he was appointed Managing Director of Eni’s activities in Libya, where he remained for two years and concluded the renegotiation of oil contracts and launched an important program of social projects. In October 2007, 132 he became head of operational and business activities in sub-Saharan Africa as Senior Vice President, based in Nigeria. In December 2011, he was appointed Executive Vice President Africa and Middle East Region, also coordinating the Mozambique programme for the development of the Mamba and Coral discoveries. From 2014 to May 2016, he was a member of the Board of Directors of the Eni Foundation. Since July 1, 2014, he has been Eni’s Chief Development, Operations & Technology Officer. Alberto Chiarini was born in Milan in 1963. After taking a degree in political science and a course of specialization at the Scuola Enrico Mattei, he joined Eni in 1989. He began his career in an international context, in the business/finance area, in positions of growing responsibility in a number of countries (including the United Kingdom, Congo, Libya and Holland) rising to the position of Managing Director of Eni UK. He returned to Italy in 2006 as head of Planning and Control at the Exploration and Production division and was subsequently appointed as Eni’s Executive Vice President Global Procurement and Strategic Sourcing. In 2011 he was appointed Chief Executive of Syndial, the Eni subsidiary that provides integrated services in the field of environmental remediation. On December 6, 2013 he was appointed Chief Financial and Compliance Officer of Saipem SpA with responsibility for Finance, Legal Affairs & Compliance and ICT, overseeing in particular the recapitalisation and refinancing of the company. He was appointed as Chief Retail Market Gas & Power Officer on September 12, 2016. Claudio Granata was born in Rome in 1960. Graduating with a degree in economics, he joined the Eni group in 1983. From 1983 to 1994 he worked as a labour market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999, he continued his experience with Eni Corporate as an expert in industrial relations. In 2000, he was given responsibility for Staff and Organization within Eni Servizi Amministrativi, a company that was set up to centralize Eni’s administrative activities. In 2001, he took over the management of Eni’s territorial divisions, for which he structured the management of the staff by geographical area and, in 2003, he took on the role of Business HR for Eni Corporate, ensuring support for Departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), characterized by the mergers by incorporation of Snam and AgipPetroli and the redefinition of the organizational structures for the staff. In the same year he was also appointed as Director of personnel and organization 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 the human resources and organization activities. He also collaborated with the top management in the reorganization of macro processes for the Division and promoted Change Management initiatives. From 2006, he has been a Board Member of Eni International Resources Ltd, and from 2012 to 2013, he has been appointed as Chairman of the Board of Eni International Resources Ltd. From 2012 to March 2015, he has been a board member of Eni UK Ltd. Since 2013, he has been Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, with responsibility 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. Since November 2014, he has been Chairman of the Board of Eni Corporate University. Since July 1, 2014, he has been Eni’s Chief Services & Stakeholder Relations Officer. Massimo Mantovani was born in Milano in 1963. He graduated with a degree in law from the University of Milan and holds a Master’s Degree from the University of London. He is the author of numerous publications and teaches post-graduate courses. After qualifying to practice law in Italy and UK he worked for a few years in private legal practice in Milan and London. In 1993 he joined Eni’s Legal Department, specializing in international negotiations and contracts, specifically international gas/LNG supplies and projects and joint ventures for the commercialization and transport of gas. In 2001 he was appointed legal Director of Eni’s Gas & Power Division. His main task was participating to the management for Eni of the start-up phase of the liberalization of the gas market in Italy and the unbundling of the national and international network for the transport of gas. In October 2005 he was appointed Senior Executive Vice President of Legal Affairs in Eni S.p.A. He has been Chief Legal and Regulatory Affairs of Eni from 2014 to 2016, the department managed all legal and energy regulatory issues of Eni and its unlisted subsidiaries. From 2005 to 2016 he was member of the Eni S.p.A. Watch Structure. He was a member of the Board of Directors of Snam Rete Gas S.p.A. from 2005 to 2012 and of the Board of the University of Bologna from 2011 to 2012. He has been Chairman of Syndial S.p.A. from 2016 to 2017. He is currently Chairman of Eni Trading & Shipping S.p.A. He is also Eni Representative on the Eurogas Governing Board and on its Executive Committee since November 2016. Between 2011 and 133 2014 he was a member of the anticorruption working group for the B20, coordinator for activities relating to the development of an international regulatory framework for the B20 held in Russia in 2013 and leading expert for the 2014 B20 in Australia. Massimo Mantovani has been Eni’s Chief Midstream Gas & Power Officer since 17 October 2016. Massimo Mondazzi was born in Monza in 1963. He graduated with a degree 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 head of the Division. From 2006 to 2009 he was Director of Planning and Control for the Eni Group, before returning to E&P as Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration and Production division, to the launch of new development projects and to Eni’s entry into new countries. 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. From 2014 until September 2016, alongside his role as Eni’s Chief Financial Officer, he was also responsible for Eni’s Integrated Risk Management department. Giuseppe Ricci was born in Casale Monferrato in 1958. He has a degree in chemical engineering. He joined Eni in 1985 initially working in the study and development of new refining processes at the Sannazzaro refinery, before becoming involved in the creation and consolidation of the joint venture with Kuwait Petroleum at the Milazzo refinery. In 2000 he returned to head office as where he was responsible for Refining Processes Development and oversaw the performance optimisation at the refining facilities of Agip Petroli. He left central technologies to take over, in 2004, as director of the Gela Refinery, a particularly challenging assignment both from a managerial perspective and in terms of the refining cycle and the complexity of the plant; in 2006 he was appointed managing director of the refinery. In June 2010 he was made Senior Vice President of the Industrial Sector for Refining & Marketing, with responsibility for the refineries, storage deposits, oil pipelines and plant and facilities in Italy, as well as the management of subsidiary and associated companies in Italy and abroad. As Industrial Director he also held a series of additional responsibilities, such as the chairmanship of Gela and Milazzo. In 2012 he took on the delicate role of Eni’s Executive Vice President Health, Safety Environment and Quality with responsibility for providing the guidelines, coordination and control of safety, industrial health, product safety, the environment and quality. Since 2016 he has been a board member of Eniservizi. He was appointed as Chief Refining & Marketing Officer on September 12, 2016. Antonio Vella was born in 1957. He graduated with a degree in engineering from the Turin Polytechnic in 1982 and joined the Eni Group in 1983. He began his career as an oil engineer at Agip in Libya, where he was involved in upstream onshore and offshore operations. From 1988 to 1991, he was project manager for EniChem’s petrochemical plants and refineries in Italy. In 1991, he was appointed project manager for the development of Libyan oil fields and in 1993, he moved to Egypt, initially as Operations Manager and subsequently as General Manager and Managing Director of Petrobel, where he was responsible for all of Eni’s upstream operations in Egypt. In 1999, he was appointed District General Manager of Nigerian Agip Oil Co (NAOC), and in 2000, became Vice Chairman and Managing Director of the Eni companies in Nigeria NAOC, NAE (Nigerian Agip Exploration) and AENR (Agip Energy). In 2002, he became regional Vice President for Australasia, Russia, Azerbaijan and then, in 2005, a Member of the Board of Directors and Managing Director of Eni Algeria. From 2006 to 2009, he was regional Senior Vice President for North Africa and the Middle East (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) for Eni’s Exploration & Production Division. In 2009, he was appointed Executive Vice President Operations for the Exploration & Production Division. In December 2012, he was appointed Executive Vice President for Central Asia, the Far East and the Pacific Area. Since July 2014, he has been a Board Member of Eni Foundation. Since July 1, 2014, he has been Upstream Officer. 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 S.p.A., 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 134 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, with a particular focus on the Upstream business and management of partnerships and M&A transactions. Since 2016, he has been a Board Member of Eni Foundation. He was appointed Senior Executive Vice President Legal Affairs on October 17, 2016. 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 Department. Roberto Ulissi was born in Rome in 1962. He’s a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998, he was appointed General Manager at the Ministry of the Economy and Finance, head of the Banking and Financial System and Legal Affairs Department. He has been 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 of Banor SIM. He has also been a member of numerous Italian and European committees representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law (Commission “Vietti”) and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board Member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel. Marco Bardazzi was born in Prato in 1967. A journalist by trade, he worked in the media business for 28 years, before joining Eni in 2015. He has achieved an extensive experience in foreign policy and digital communications, particularly related to European and American realities (he lived and worked in the United States for nine years). Between 2009 and 2015, he has been Managing Editor and Digital Editor at “La Stampa”, a leading European newspaper based in Turin, Italy. He has been a key member of the “La Stampa” team that has worked on its transformation from a traditional newspaper founded in 1867 to an integrated digital news organization, thus creating an innovative “concentric circle” multiplatform newsroom. He has also been a co-founder of the “Europa” 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, covering every aspect of American life for the Italian media. Among other things, he has covered the 2000 Bush-Gore electoral race for the White House; the first international Al Qaeda trial in Manhattan; the September 11, 2001 attack on America; the war in Afghanistan; the war in Iraq; the 2004 and 2008 presidential campaigns; he has visited and reported on the Guantanamo detention camp at U.S. Navy Guantanamo Bay base, Cuba; he has covered the 2008 financial crisis, and he has extensively reported on the American digital, energy and manufacturing businesses. He teaches a class on “Journalism innovation” in the Master on Journalism program at ALMED-Università Cattolica del Sacro Cuore, Milan. 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. Since February, 16, 2015, he has been External Communication Department Executive Vice President. Luca Cosentino was born in Venice on August 1, 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 135 Persian Gulf. In this period, he also taught at the IFP School and published several technical papers, including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to 2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From 2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed Senior Vice President Non Operated Business Performance and Stranded Resources Valorization. Since November 1, 2015, he has been Executive Vice President Energy Solutions Department. Pasquale Salzano was born in Pomigliano d’Arco (Naples) in 1973. In 1996, he graduated with Honors with a degree in Law from the University “Federico II” in Naples and in 2000 obtained a PhD in international law from the University of Siena. From 1996 to 1999, he collaborated with Prof. Benedetto Conforti at the Chair of International Law at the University of Naples and in 2000, qualified as a Lawyer at the Naples Court of Appeals. He began his career as a diplomat in December 1999 and from January 2000 to July 2001, worked on legal and institutional issues regarding the European Union at the General Directorate for European Integration of the Italian Ministry of Foreign Affairs. In 2001, in the aftermath of the Balkan conflict, Pasquale Salzano was appointed Chief of Staff of the international OSCE Mission in Belgrade and the following year was posted by the Italian Government to Pristina to establish and manage the Italian Liaison Office at the Special Representative of the Secretary-General of the United Nations in Kosovo, which subsequently became the Italian Embassy. From 2005, he was in New York at the Permanent Mission of Italy to the United Nations and, after about two years, was posted to Rome to the Office of the Diplomatic Adviser to the Prime Minister where, in view of the Italian Presidency of the G8, was appointed by the Prime Minister as Head of the Sherpa Office for the G8/G20. In 2009, he was selected by the OECD Secretary-General as Director of the Heiligendamm/L’Aquila Process in Paris. From January 2011, he was seconded by the Ministry of Foreign Affairs to Eni, where he was appointed Vice President, International Institutional Relations in the Department of Institutional Relations and Communications and Vice President of Eni-USA’s Representative office. He is a Young Global Leader of the World Economic Forum, is a Member of the Board of the European Council on Foreign Relations (ECFR) Italy, the Scientific Committee of the Rome-Mediterranean Foundation and the National Assembly of UNICEF Italy. He is a member of the Institute for International Affairs (IAI) and the Institute for International Political Studies (ISPI). From July 1, 2014 to 2015 he was Eni’s Senior Vice President Government Affairs. Since February 19, 2015, he has been Eni’s Executive Vice President Government Affairs Department. Luca Franceschini was born in Milan in 1966. He graduated with a degree 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 in Eni in 1991 in the legal department of Agip S.p.A., 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 a member of the boards of directors of both Italgas and Stogit. In 2015 he was appointed as Eni’s Executive Vice President for Legal and Regulatory Compliance. He was appointed as Executive Vice President of Integrated Compliance on September 12, 2016. 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 136 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. Compensation Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of Directors, which considers relevant proposals made by the Compensation Committee after consultation with the Board of Statutory Auditors. Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter of Legislative Decree No. 58 of February 24, 1998 and Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications) and in line with the Corporate Governance Code recommendations for Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy Guidelines adopted for Directors and other Managers with strategic responsibilities5. The main elements of the 2017 remuneration policy and of the compensation paid in 2016 to Directors, Statutory Auditors, CEO and General Manager and other Managers with strategic responsibilities, are described below. 2017 Remuneration Policy Guidelines This chapter contains the Remuneration Guidelines for the new 2017-2020 term, approved by the Board of Directors on February 28, 2017 for the Directors who will be appointed at the Shareholders’ Meeting on April 13, 2017. The new Board of Directors will retain the prerogative to determine, specific remuneration for the exercise of delegated powers and for participating on Board Committees, based on a proposal by the Compensation Committee. The Shareholders’ Meeting will retain the prerogative to approve the Share-based Variable Incentive Plans. Furthermore, the Remuneration Guidelines below for Directors in office until April 13, 2017 are also briefly outlined. These were already extensively discussed in the Remuneration Report 2016 and reflect the decisions made by the Board of Directors on May 28, 2014 for the 2014-2017 term. Policies For Directors During The 2017-2020 Term Of Office The main novelty of the Remuneration Policy in the new term of office is the comprehensive review of the variable incentive scheme for the Chief Executive Officer and General Manager and for all other Senior Managers in order to simplify the incentive scheme’s overall architecture (which will be broken down into two incentive plans instead of three) and further align performance objectives with shareholder expectations. More specifically, the new incentive scheme provides for the introduction of: • • a Short-Term Monetary Plan with the deferral of a portion of the accrued bonus, which will start from the assignment of the 2017 objectives with the first payment in 2018, to replace the previous Annual Monetary Incentive and Deferred Monetary Incentive plans. a Long-Term Performance Share Plan 2017-2019, with first attribution in 2017, to replace the previous Long-Term Monetary Incentive Plan (subject to approval by the Shareholders’ Meeting on April 13, 2017). (5) Those persons who have the power and responsibility, directly or indirectly, for planning, directing and controlling Eni fall under the definition of “Managers with strategic responsibilities”, pursuant to Consob regulations. Eni Managers with strategic responsibilities, other than Directors and Statutory Auditors, are those who sit on the Management Committee and, in any case, those who report directly to the Chief Executive Officer. 137 For the Chairman and the Non-Executive Directors, adjustments are proposed for the remuneration envisaged for delegated powers and for participating on Board Committees compared with median levels in the reference markets. Market references and peer group For the Chief Executive Officer and General Manager, the positioning of the Company’s remuneration is assessed by comparing similar roles only in the international Oil & Gas sector, with regard to upstream activities in particular, and in line with the company’s strategy to increase its focus on the business. More specifically, the comparator group has been expanded to include the main listed companies in the Oil & Gas sector, which are Eni competitors at the international level and possess comparable business characteristics (Anandarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total). This panel also constitutes the Peer Group used for the relative comparison of Eni performance in the new Long-Term Performance Share Plan. For the Chairman and the Non-Executive Directors, the positioning of remuneration is assessed by comparing similar roles in the Top Italy Panel, composed of the main companies listed on the FTSE MIB (Assicurazioni Generali, Atlantia, Enel, Intesa Sanpaolo, Leonardo-Finmeccanica, Luxottica, Mediaset, Mediobanca, Poste Italiane, Snam, Terna, TIM, Unicredit). For Managers with strategic responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector. General principle of clawback Clawback mechanisms will be adopted, through a specific regulation proposed by the Compensation Committee and approved by the Board of Directors, allowing the variable remuneration components already paid and/or granted to be reclaimed, or those subject to deferral to be withheld, where their achievement was based on data that was subsequently proven to be manifestly misstated, or allowing the recoupment of all the incentives for the year (or years) in which subsequent checks confirm the fraudulent alteration of the results data used to obtain the right to incentives, and/or the commission of serious and deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to the employment and trust relationship, without prejudice to any other action permitted by law and regulations to protect the interests of the Company. The regulation provides that the activation of recoupment claims (or revocation of incentives awarded but not yet paid) must take place, once the checks have been completed, within three years of payment (or award) in the case of error, and within five years in the case of fraud. Chairman of the Board of Directors Remuneration for the delegated powers Remuneration will be defined in line with the decisions taken by the Shareholders’ Meeting on 13th April 2017 and with the median levels in the reference market, taking the delegated powers into account. Payments due in the event of termination of office or employment No specific severance payments are provided for the Chairman, nor do any agreements exist for indemnities in the case of early termination of office. Non-executive directors Remuneration for participation on Board Committees The Policy Guidelines for Non-Executive and/or Independent Directors provide for the adjustment of the additional annual remuneration for participating on Board Committees in line with the median levels in the reference market, taking due account of commitment in terms of meetings and their duration. More specifically, for the 2017-2020 term, the following remuneration is proposed: 138 • • • for the Control and Risk Committee, annual remuneration consists of €70,000 for the Chairman and €50,000 for the other members; for the Compensation Committee and the Sustainability and Scenarios Committee, the annual remuneration consists of €50,000 for the Chairman and €35,000 for the other members; for the Nomination Committee, the annual remuneration consists of €40,000 for the Chairman and €30,000 for the other members. Payments due in the event of termination of office or employment No specific severance payments are provided for the Non-Executive Directors, nor do any agreements exist for indemnities in the case of early termination of office. Chief Executive Officer and General Manager The Policy Guidelines for the Chief Executive Officer and General Manager take into account the specific delegated powers granted in accordance with the By-laws, the instructions contained in the chapter “Purpose and general principles of the Remuneration Policy” as well as the remuneration levels and best practices in the reference Oil & Gas panel. Fixed remuneration Fixed remuneration (FR) will be set by the new Board of Directors based on a proposal of the Compensation Committee in relation to the delegated powers and positions held, taking into account the median levels in the reference market. Fixed remuneration includes the remuneration for Directors established by the Shareholders’ Meeting on April 13, 2017, as well as any compensation that may be due for participating on the Board of Directors of subsidiaries or associated companies. Variable incentive plans Short-Term Monetary Plan with deferral The new Short-Term Monetary Plan with deferral of a portion of the accrued bonus brings together the previous Annual Monetary Incentive and Deferred Monetary Incentive plans. Compared with the previous Plans, the performance scales have been extended to include achievement of results that are above or far above the target levels. In this Plan, a portion of the incentive is paid annually and a portion is deferred for a three-year period, as described below. The Short-Term Monetary Plan with deferral is linked to the achievement of the 2017 objectives approved by the Board of Directors on February 28, 2017. These objectives keep the structure focused on the essential goals consistent with the guidelines outlined in the Strategic Plan and balanced against the interests of the various stakeholders, in terms of economic and financial results (25%), operating results and sustainability of the economic performance (25%), environmental sustainability and human capital (25%), efficiency and financial strength (25%). The value of each objective, at target performance level, is aligned with the budgeted value. Each objective is measured in accordance with a performance scale of 70 to 150 points (target=100), in relation to the weight assigned to each target (below 70 points, the performance of each target is considered to be zero). For the purposes of the incentive award, the minimum overall performance is 85 points. This Plan provides for remuneration calculated with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) multiplier, equal respectively to 85%, 100% and 150% to be applied to the target incentive, as determined by results achieved by Eni over the previous year. Total incentive (TI) is calculated using the following formula: TI = FR x % ITarget x Multiplier 139 Where “ITarget” is the incentive percentage at target performance level, which is set at 150% of total fixed remuneration for the Chief Executive Officer. The Plan conditions state that the total incentive is divided into 2 portions. 1) a portion paid annually (IYear) equal to 65% of the total incentive. Iannual = TI x 65% The levels of the fraction of the incentive payable during the year, depending on the performance levels achieved, are shown in the table below. Annual performance Annual incentive (% of Fixed Rem) <85 85 threshold 100 target 150 max 0% 83% 98% 146% 2) a deferred portion equal to 35% of the total incentive, subject to further performance conditions during a three-year vesting period. The deferred portion payable at the end of the vesting period is determined by multiplying the initial deferred portion by the payment multiplier. The latter is given by the average of the three annual multipliers, each determined during the three-year period in relation to the performance achieved, based on Eni’s annual objectives. The multiplier of the deferred portion depends on the performance achieved, with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) incentive level, equal respectively to 85%, 130% and 230% of total fixed remuneration. The Deferred Incentive (DI) payable at the end of the three-year deferment period is calculated using the following formula: DI = TI x 35% x Multiplier The levels of the payable deferred portion, depending on the performance levels achieved throughout the three-year period, are shown in the table below. 3-year Average performance <85 85 threshold 100 target 150 max Deferred incentive (% of Fixed Rem) 0% 38% 68% 181% Long-Term Performance Share Plan The Chief Executive Officer participates in the Long-Term Performance Share Plan 2017-2019, which also applies to Senior Managers, deemed critical for the business, subject to approval by the Shareholders’ Meeting on April 13, 2017. The Plan replaces the previous Long-Term Monetary Incentive Plan as a tool to incentivize and promote the loyalty of the most critical management positions for the company, ensuring achievement, in line with international best practices, of the following additional objectives: • • • strengthening the culture of business risk management from the perspective of shareholders by adopting shares as an incentive; setting a more challenging minimum incentive threshold, positioned at median level; further aligning performance conditions with the long-term expectations of shareholders, using: (i) an assessment of the performance of the Company’s Total Shareholder Return over a three-year period compared with that of the Reference Stock Market Index, compared with the same performance of the main international competitors (Peer Group); 140 (ii) further incentivize the capacity to develop industrial assets, measured using the increase in the Net Present Value of hydrocarbon reserves in the medium-long term (in accordance with the assessment method defined by the SEC), measured in relative terms compared with the designated peer group. The Plan provides for three annual awards starting from 2017, each with a three-year vesting period. The Plan is subject to performance conditions during the three-year vesting period, in accordance with the following parameters and related weightings: 1. The difference between the TSR of Eni Shares and the TSR of the FTSE MIB index of Borsa Italiana, corrected by the Eni Correlation Coefficient, compared with the equivalent adjusted TSR measure for each company in the Peer Group, as shown in the following (50% weight): TSRA - (TSRI x ρ A,I) Where: TSRA: TSR of Eni or one of the companies in the Peer Group TSRI: TSR of the Reference Stock Market Index of the company for which TSRA was calculated ρ A,I: Correlation Coefficient 2. Net Present Value of proven reserves (NPV) vs the Peer Group, measured in terms of the annual percentage change, calculating the average annual performance in the three-year period (50% weight). The reference Peer Group is described in the “Market references and Peer Group” section. (Anadarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total). For the Chief Executive Officer and General Manager, the Plan conditions provide for the annual award of shares for a value equivalent to 150% (Itarget) of total fixed remuneration, using the following formula. No.of Attributed Shares = FR x % Itarget PriceAttr Where the price of the award (PriceAttr) is calculated as the average of daily official prices (source Bloomberg) recorded in the 4 months before the date of the Board of Directors meeting that annually approves the plan rules and the award to the Chief Executive Officer and General Manager. The granting of shares at the end of the three-year vesting period is determined using a final multiplier to be applied to awarded shares (calculated as the weighted average of the multipliers of each parameter) determined over the vesting period in relation to the position reached in the peer group. Each multiplier may be between 0 and 180%, with a threshold set at the median level, in accordance with the scale shown below. Performance Scale - Multiplier Ranking 1st 2nd 3rd 4th 5th 6th 7th 8th 9th 10th 11° Multiplier 180% 160% 140% 120% 100% 80% 0% 0% 0% 0% 0% Median positioning 141 Grantable shares are calculated using the following formula: No.of Granted Shares = No.of Attributed Shares x Multiplier The value levels of the Shares granted at the end of the vesting period, net of changes in the share price over the same period, are given below. Weighted average 3-year performance Value of Shares (% of Fixed Rem) <26.6 26.6 threshold (*) 100 target 180 max 0% 40% 150% 270% (*) Achieved for example if the minimum level (6th place) is reached for the indicator of NPV of proven reserves, in at least two years of the three year vesting period. For executives in services, 50% of the shares granted at the end of the vesting period are locked up for a period of 1 year after the grant date. As the Plan is submitted to the Shareholders’ Meeting for approval, it is also described in detail in the information document made available to the public on the Company website. For both the deferred portion of the short-term incentive and the long-term share incentive, the clauses provided for all Managers in the respective Rules will apply in cases of termination of employment before the end of their term of employment. If their contract is not renewed, the natural expiry of the related vesting period is retained, in accordance with the performance conditions defined by each Plan. Benefits For the Chief Executive Officer and General Manager, the Policy Guidelines provide for insurance coverage for the risk of death or permanent disability and, as per provisions contained in the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the supplementary pension plan (“FOPDIRE”) as well as in the supplementary health plan (FISDE ), together with a company car for business and personal use. Pay Mix The remuneration package for the Chief Executive Officer and General Manager includes a fixed component, a short-term variable component and a long-term variable component, composed of the short-term incentive deferral and the long-term share incentive valued using the international methodologies adopted for remuneration benchmarks. The pay mix, calculated by considering fixed remuneration as the base, is significantly focused on the variable components, with a dominant weighting attributed to the long-term component. Payments due in the event of termination of office or employment For the Chief Executive Officer and General Manager, in line with reference practice and with the provisions of the European Commission Recommendation No. 385 of April 30, 2009, as well as to protect the Company from potential competitive risks, the Policy provides for following payments: • An indemnity supplementing the severance award payable upon termination of the employment relationship, due to non-renewal or early termination of the 2017-2020 term of office, including in the event of resignation due to a substantive reduction of delegated powers. Compensation for the CEO position will be defined in line with European Recommendations. For any employment relationship, the provisions set out for Managers with Strategic Responsibilities shall apply. Also with reference to criteria 6.C.1.g of the Italian Corporate Governance Code, this compensation is not due in the event of dismissal for “just cause” under Art. 2119 of the Italian Civil Code, or in the event of resignation as Chief Executive Officer prior to the expiry of the term in office, unless triggered by either the above-noted reduction of delegated powers, or in the event of death as governed by Art. 2122 of the Italian Civil Code; 142 • Any non-competition agreement to protect the Company’s interests, with specific compensation as a proportion of annual remuneration, as well as in relation to the rules of application, extent and duration of the commitments. POLICIES FOR DIRECTORS DURING THE 2014-2017 TERM OF OFFICE The Policy Guidelines for the term of office that expires at the Shareholders’ Meeting on 13th April 2017 are summarized below. Chairman of the Board of Directors Remuneration for delegated powers A fixed remuneration for the delegated powers of €148,000 is provided for the Chairman of the Board of Directors, in addition to remuneration for the position determined by the Shareholders’ Meeting on May 8, 2014, amounting to €90,000, in compliance with the maximum of €238,000 defined by the same Shareholders’ Meeting. These Guidelines do not provide for variable remuneration. In 2017, these remuneration components will be paid pro-rata with respect to the period in office that ends with the Shareholders’Meeting called to approve the Financial Statements as at December 31, 2016. Payments due in the event of termination of office or employment No specific severance payments are envisaged for the Chairman, nor do any agreements exist for indemnities in the case of early termination of office. Benefits The Chairman is granted insurance coverage for the risk of death or permanent disability. Non-executive Directors Remuneration for participation on Board Committees Non-executive and/or Independent Directors receive an additional annual remuneration6 for participating on Board Committees, as follows: • • for the Control and Risk Committee, the remuneration amounts to €60,000 for the Chairman and €40,000 for the other members; the Sustainability and Scenarios Committee and the for the Compensation Committee, Nomination Committee the remunerations amount to €30,000 for the Chairman and €20,000 for the other members. In 2017, this remuneration will be paid pro-rata with respect to the period in office that ends with the Shareholders’ Meeting of April 13, 2017. Payments due in the event of termination of office or employment No specific severance payments are provided for the Non-Executive Directors nor do any agreements exist that provide for indemnities in the case of early termination of office. Chief Executive Officer and General Manager For the Chief Executive Officer and General Manager, the Policy Guidelines reflect the resolutions passed by the Board of Directors on May 28, 2014, taking into account the specific delegated powers granted in accordance with the Articles of Association, the instructions contained in the chapter “Principles and general purposes of Eni Remuneration Policy”, as well as the 25% reduction of the (6) This remuneration supplements the one established by the Shareholders’ Meeting of May 8, 2014, for the remuneration of Non-executive Directors, amounting to €80,000 annual gross. 143 maximum payable overall remuneration of the previous mandate, in accordance with the Shareholders’ resolution of May 8, 2014. The remuneration envisaged by the Board in relation to the delegated powers includes both the compensation for Directors determined by the Shareholders’ Meeting on May 8, 2014, as well as any compensation that may be due for participating on the Board of Directors of Eni’s subsidiaries or associated companies. Fixed remuneration For the Chief Executive Officer and General Manager total fixed remuneration is set at a gross annual amount equal to €1,350,000, of which €550,000 for the position of Chief Executive Officer and €800,000 for the position of General Manager. The remuneration envisaged by the Board in relation to the powers delegated includes both the remuneration for Directors determined by the Shareholders’ Meeting on May 8, 2011, as well as any compensation that may be due for participating on the boards of directors of Eni’s subsidiaries or associated companies. In 2017, these remuneration components will be paid pro-rata with respect to the period in office that ends with the Shareholders’ Meeting of April 13, 2017. In his capacity as Eni Senior Manager, the General Manager is also entitled to receive an allowance for travel, in Italy and abroad, in line with the applicable provisions provided by the relevant national collective labor agreement for senior managers and complementary Company level agreements. Annual variable incentives The annual variable incentive linked to achieving the targets set for 2016 will be paid in 2017. Deferred Monetary Incentive Plan In 2017, the Chief Executive Officer and General Manager participates in the last award of the Deferred Monetary Incentive (DMI) Plan 2015-2017, also envisaged for all the Company’s senior managers, associated with Company performance measured in terms of Earnings Before Taxes (EBT). Long-Term Monetary Incentive Plan The Long-Term Monetary Incentive Plan 2014-2016 ended in 2016 with the last award. The new Long-Term Performance Share Plan 2017-2019 will be implemented from 2017. This Plan has already been described in the section “Policies for the 2017-2020 term of office” and in the information document made available to the public on the Company website. Benefits For the Chief Executive Officer and General Manager the Policy Guidelines provide for insurance and healthcare coverage defined by the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, as well as a company car for business and personal use. Payments due in the event of termination of office or employment For the Chief Executive Officer and General Manager, in line with sector practices and with the provisions of the European Commission Recommendation No. 385 of April 30, 2009, as well as to protect the Company from potential competitive risks, the Policy provides for following payments: • an indemnity supplementing the severance award, with mutual exemption from notice, is payable upon termination of the employment relationship, due to non-renewal or early termination of the 2014-2017 term of office, including in the event of resignations caused by a substantial reduction of delegated powers. This indemnity is equal fixed remuneration (€1,350,000), for a total gross amount equal to €2,700,000. It should also be noticed that there is an ongoing analysis of the effective enforceability of the agreed framework, partly with reference to legislative changes following the conclusion of the contract with the Chief Executive Officer the Italian and General Manager. Also with reference to the recommendation 6.C.1g) of to two years of total 144 • Corporate Governance Code, note that, in relation to the applicable contractual provisions, this compensation is not due in case of dismissal for “just cause” under Article 2119 of the Italian Civil Code or in cases of resignations as Chief Executive Officer before the expiry of the term in office , unless triggered by a reduction of delegated powers, or in the event of death governed by Article 2122 of the Italian Civil Code; non-competition agreement to protect the Company’s interests that can be activated at the sole discretion of the Board of Directors through the exercise of an option right, the validity of which applies only as of the one set of a second term (if appointed), in exchange for a total option fee of €500,000 gross to be paid in three annual installments. If the option is exercised by the Board and the agreement is implemented, a non-compete award will be paid subject to a commitment by the Chief Executive Officer and General Manager not to undertake, for the twelve months following the expiry of the term, any activities of Exploration & Production activities potentially in competition with Eni in key markets in Europe, America, Asia and Africa. This amount will be set by the Board of Directors as the sum of two components: (i) a fixed component of €1,500,000; and (ii) a linearly determined variable component based on the average annual performance of the previous three years (equal to 0 for performance below or equal to the target and to €750,000 for maximum performance), and will be paid at the expiry of the term of the agreement. The variable component is calculated by taking into consideration the annual performance related to the annual Variable Incentive Plan. Any violation of the non-competition agreement will result in the non-payment of the consideration (or its restitution, where the violation is identified by Eni after the payment), and the obligation to pay damages set by mutual agreement in an amount equal to twice the amount of the non-competition agreement, without prejudice to Eni’s right to seek fulfillment in specific form. 2017 POLICIES FOR MANAGERS WITH STRATEGIC RESPONSIBILITIES For Managers with Strategic Responsibilities, the Guidelines provide for remuneration plans that are strictly in line with those of the Chief Executive Officer and General Manager, to better guide and align managerial action with the objectives set out in the Company’s Strategic Plan, and with the provisions and protections laid down by the national collective bargaining agreement for senior managers. In the new 2017-2020 term of office, starting from April 13, 2017, the new Long-Term Share Incentive Plan and Short-Term Variable Incentive Plan with Deferral – intended for the Chief Executive Officer who will be appointed by the Shareholders’ Meeting of April 13, 2017 - will also apply to Managers with Strategic Responsibilities. The Plans applying to the previous term will be implemented until April 13, 2017. Market references For Managers with Strategic Responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector. Fixed remuneration Fixed remuneration is based on the role and responsibilities assigned, taking into consideration a graduated and a generally median to below-median positioning versus national and international executive markets for comparable roles. It may be updated periodically during the annual salary review for all managers. Given current market comparators and trends, the 2017 Guidelines provide for a selective approach to salary reviews, while maintaining appropriate levels to ensure competitiveness and motivation. More specifically, the proposed actions will include measures to adjust fixed/one-off remuneration for those in positions that have seen a significant increase in responsibility or scope, and to reflect needs for retention and excellent performance. 145 In addition, as Eni officers, Managers with Strategic Responsibilities are entitled to receive the allowances due for travel in Italy and abroad, in line with applicable provisions of the relevant national collective bargaining agreement for senior managers and supplementary Company agreements. Variable incentive plans Annual variable incentives Starting with the assignment of the 2017 objectives and with the first payment in 2018, the annual variable Incentive Plan will be replaced by the new Short-Term Monetary Plan with deferral, already described for the Chief Executive Officer and General Manager. The targets set for Managers with Strategic Responsibilities are consistent with those assigned to the Chief Executive Officer and General Manager, on the basis of the same perspective of stakeholder interests, as well as with the relevant individual targets, consistent with the responsibilities of the role played and the provisions of the Company’s Strategic Plan. For Managers with Strategic Responsibilities the target incentive levels for the new Short-Term Monetary Plan differ depending on the role’s level of responsibility and complexity and are equal to the sum of those set for the previous Annual Variable Incentive Plan and Deferred Monetary Incentive Plan (up to 100% of fixed remuneration). The last award for the previous Annual Variable Incentive Plan will be paid in 2017, determined with reference to the performance goals set for Eni, the business area and individual performance in 2016. Deferred Monetary Incentive Plan Managers with Strategic Responsibilities participate in the last attribution of the Deferred Monetary Incentive Plan (DMI) 2015-2017, approved by the Board of Directors on March 12, 2015. Long-term variable incentive plan Managers with Strategic Responsibilities participate in the Long-Term Performance Share Plan (LTI) 2017-2019, approved by the Board of Directors on February 28, 2017 and submitted for approval by the Shareholders’ Meeting on April 13, 2017. The Plan is directed at managers who are critical for the business and envisages three annual awards, starting in 2017, with the same performance conditions and characteristics as those described above for the Chief Executive Officer and General Manager. For Managers with Strategic Responsibilities, the value of the shares to be awarded each year differs depending upon the level of their role and is limited, as in the previous long-term monetary incentive plan, to a maximum of 75% of fixed remuneration. Benefits For Managers with Strategic Responsibilities, in line with the policy implemented in 2016 as well as the provisions of the national collective bargaining agreement and supplementary Company-level agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE) and health plan (FISDE), as well as insurance coverage for the risk of death or disability, together with a company car for business and personal use, and the possible assignment of housing based on operational and mobility requirements. Pay Mix The average target pay mix of the remuneration package for Managers with Strategic Responsibilities, with the application of both new incentive plans (short-term monetary plan with deferral and long-term performance share plan), calculated using the same valuation methods used for the Chief Executive officer and General Manager, highlights the balance between the fixed and variable components and, as regards the latter, the greater weighting of medium-long term variable incentives, in line with market best practice. 146 Payments due in the event of consensual termination of employment Managers with Strategic Responsibilities, as well as Eni senior managers, are entitled to the severance benefits for employment termination established by law and applicable national collective bargaining agreement, together with any termination indemnities agreed on an individual basis, in accordance with the criteria established by Eni for cases of early termination, within the limits of the protection envisaged by the applicable national collective bargaining agreement, and consistent with application criterion 6.C.1 lett.g) of the Italian Corporate Governance Code. These criteria take into account the position held, the retirement age and actual age of the manager at the time employment is terminated and the annual remuneration received. For cases of termination that present high competitive risks relating to the criticality of the position held by the Manager, agreements containing non-competition clauses may also be entered into with payments defined in relation to the remuneration received and the scope, duration and effectiveness of the agreement. COMPENSATION AND OTHER INFORMATION Implementation of the 2016 remuneration policies The following is a description of the remuneration decisions taken in 2016 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, and other Managers with strategic responsibilities, in relation to their time in office. The implementation of the 2016 Remuneration Policy, as verified by the Compensation Committee at the regular assessment required by the Corporate Governance Code, was found to be consistent with the 2016 Remuneration Policy, approved by the Board of Directors on March 17, 2016. This takes into account the resolutions passed by the Board of Directors on May 9 and May 28, 2014 on the remuneration of Non-executive Directors appointed Board Committees and on the definition of the remuneration of Directors with delegated powers, in accordance with the resolutions passed at the Shareholders’ Meeting in accordance with Law No. 98/2013. Chairman of the Board of Directors - Emma Marcegaglia Fixed remuneration The Chairman was paid the fixed remuneration approved for the office by the Shareholders’ Meeting of May 8, 2014 of €90,000 gross and the remuneration approved by the Board of Directors Meeting of May 28, 2014, in relation to the exercise of delegated powers, amounting to €148,000 gross. Benefits The Chairman was granted insurance coverage against the risk of death and permanent disability, in accordance with the resolutions of the Board of Directors Meeting of May 28, 2014. Non-executive Directors The Directors were paid fixed remuneration approved by the Shareholders’ Meeting of May 8, 2014 of €80,000 gross. The additional remunerations payable for participation on the Board Committees, as resolved by the Board of Directors Meeting of March 12, 2015, were also paid. Chief Executive Officer and General Manager - Claudio Descalzi Claudio Descalzi has held the office of Chief Executive Officer and General Manager since May 9, 2014, and before then he held the office of Chief Operating Officer (COO) of the E&P Division. Therefore, during 2016, Claudio Descalzi received the fixed remuneration and the annual variable incentive related to his current role of Chief Executive Officer and General Manager and the long term variable incentives accrued during his previous role, as detailed below. 147 Fixed remuneration The Chief Executive Officer and General Manager was paid the fixed remunerations approved by the Board of Directors Meeting of May 28, 2014, which also include the remunerations approved by the Shareholders’ Meeting for all the Directors, equal to a total gross annual amount of €1,350,000. Annual variable incentives In line with the Remuneration Policy 2016, the Chief Executive Officer and General Manager was paid a gross annual variable incentive of €1,755,000 associated with the performance achieved during 2015 (130 points). Deferred Monetary Incentive Plan For the Chief Executive Officer and General Manager, the Board of Directors as its meeting of March 17, 2016, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2016, approved the assignment of the deferred monetary incentive of €864,000 gross, calculated based on the 2015 EBT results approved by the Board of Directors. Furthermore, in 2016 the Deferred Monetary Incentive assigned in 2013 to Claudio Descalzi, as COO of the Exploration & Production Division, vested, resulting in a gross amount paid equaled €659,000. Long-Term Monetary Incentive Plan For the Chief Executive Officer and General Manager, the Board of Directors at its meeting of 15th September 2016, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2016, approved the grant of the 2016 long-term monetary incentive award of 1,350,000 euros gross. Furthermore, with regard to the Long-Term Monetary Incentive award granted in 2013 to Claudio Descalzi, as COO of the E&P Division, the performance achieved in the reference three-year period did not satisfy the conditions for payment of the incentive. Benefits The Chief Executive Officer and General Manager, in line with the resolution of the Board of Directors Meeting on May 28, 2014, was granted insurance coverage for death or permanent disability, and in compliance with the provisions of the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the supplementary pension plan (FOPDIRE) as well as supplementary health plan (FISDE), together with a company car for business and personal use. In 2016 Claudio Descalzi, for his role as Chief Executive Officer and General Manager, received a total of €3,120,000 and, for his previous role as COO of the E&P Division (held until May 8, 2014), €659,000 for the long term variable incentives accrued. Consequently, the total amount received was €3,779,000. Managers with strategic responsibilities Fixed remuneration For the current Managers with Strategic Responsibilities, within the context of the annual salary review process envisaged for all managers, in 2016 selective adjustments were made to fixed remuneration, in cases of promotion to more senior levels, or in line with necessary market-driven adjustments . The total gross value of the fixed remuneration paid in 2016 to Managers with Strategic Responsibilities is shown in the section “Compensation paid in 2016”, under the item “Fixed compensation”. Annual variable incentive In March 2016, annual variable incentives were paid to Managers with Strategic Responsibilities in accordance with the Remuneration Policy and based on performance achieved in 2015. 148 In particular, the incentive is linked to performance against a range of metrics related to business and sustainability objectives (safety, environmental protection, stakeholder relations), as well as relevant individual, consistent with the provisions of the 2015 Eni Performance Plan. Deferred Monetary Incentive Plan Managers with Strategic Responsibilities were granted 2016 deferred monetary incentive awards, in accordance with the Remuneration Policy and on the basis of the 2015 EBT results approved by the Board of Directors on March 17, 2016, as proposed by the Compensation Committee. In 2016, the Deferred Monetary Incentive award granted in 2013 also vested. Long-Term Monetary Incentive Plan Managers with Strategic Responsibilities were granted their 2016 long-term monetary incentive award, determined in accordance with the Remuneration Policy. With regards to the Long-Term Monetary Incentive awards granted in 2013, the performance achieved in the three-year reference period did not satisfy the conditions for their payment. Severance indemnity for end-of-office or termination of employment During 2016, Managers with Strategic Responsibilities who accepted enhanced voluntary termination offers were paid, in addition to amounts due under legal and contractual obligations, additional amounts defined in line with company policy on early retirement incentives. Benefits For Managers with Strategic Responsibilities, in line with provisions in the national collective bargaining agreement and the supplementary corporate agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (“FOPDIRE”) as well as in the supplementary health plan (FISDE), insurance coverage for the risk of death or disability, together with a company car for business and personal use. COMPENSATION PAID IN 2016 The table below lists the individual remunerations to the Directors, Statutory Auditors, Chief Executive Officer and General Managers and, in aggregate form, to other Managers with strategic responsibilities. The remunerations received from subsidiaries and/or affiliates, except those waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year. In particular: • based on the criteria of competence, the column “Fixed remuneration” reports the fixed remuneration and fixed salary from employment due for the year, gross of the social security contribution and tax expenses to be paid by the employee; it excludes attendance fees, as these are not provided for. Details of the compensation are provided in the notes, and any indemnities or payments with reference to the employment relationship are indicated separately; based on the criteria of competence, the “Remuneration for participation in the Committees” column reports the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately; the column “Variable non-equity remuneration” under the item “Bonuses and other incentives” shows the incentives paid during the year due to rights vested following the assessment and approval of the related performance results by the relevant corporate bodies; based on the criteria of competence and taxability, the “Benefits in kind” column reports the value of the fringe benefits awarded; based on the criteria of competence, the “Other remuneration” column reports any other remuneration deriving from other services provided; the “Total” column details the sum of the amounts of all the previous items; • • • • • 149 • • the “Fair value of equity remuneration” column reports the relevant fair value for the year related to the existing stock option Plans, estimated in accordance with international accounting standards, which assign the related cost in the vesting period; and the “Severance indemnity for end of office or termination of employment” column reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of the financial year in question, or in relation to the end of the mandate and/or employment. Remuneration paid to Directors, Statutory Auditors, Chief Executive officer and General Managers and other Managers with strategic responsibilities (€ thousand) First name and Surname Note Position Period for which the position was held Expiration of office (*) Fixed remuneration Remuneration for participation in the Committees 01.01-12.31 05.2017 238 (a) Variable non-equity remuneration Bonuses and other incentives Profit sharing Benefits in kind Other remuneration Total Fair value of equity compensation Severance indemnity for end of office or termination of employment Board of Directors Emma Marcegaglia Claudio Descalzi Andrea Gemma Pietro Angelo Guindani Karina Litvack Alessandro Lorenzi Diva Moriani Fabrizio Pagani Alessandro Profumo (1) Chairman (2) Chief Executive Officer and General Manager 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 (3) Director (4) Director (5) Director (6) Director (7) Director (8) Director (9) Director Board of Statutory Auditors Matteo Caratozzolo Paola Camagni Alberto Falini Marco Lacchini Marco Seracini (10) Chairman (11) Statutory auditor (12) Statutory auditor (13) Statutory auditor (14) Statutory auditor 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 01.01-12.31 05.2017 1,755 (b) 15 90 (b) 50 (b) 63 (b) 80 (b) 51 (b) 50 (b) 40 (b) 1,350 (a) 80 (a) 80 (a) 80 (a) 80 (a) 80 (a) 80 (a) 80 (a) 80 (a) 70 (a) 70 (a) 70 (a) 70 (a) 238 3,120 170 130 143 160 131 130 120 177 150 150 82 150 97 (b) 80 (b) 80 (b) 12 (b) 80 (b) Other Managers with strategic responsibilities (**) (15) Remuneration in the company that prepares the Financial Statements Remuneration from subsidiaries and associates Total 8,595 458 9,053 (a) 9,118 186 9,118 (b) 186 (c) 126 18,025 458 126 (d) 18,483 11,561 424 10,873 201 475 23,534 4,603 4,603 (e) 4,603 (3) (1) (2) The term of office expires with the Shareholders’ Meeting approving the Financial Statements for the year ending December 31, 2016. Notes (*) (**) Managers who were permanent members of the Company’s Management Committee during the course of the year together with the Chief Executive Officer and Division Chief Operating Officers, or who reported directly to the Chief Executive Officer (twenty-three managers). Emma Marcegaglia - Chairman of the board of directors (a) The amount includes the fixed remuneration of €90 thousand set by the Shareholders’ Meeting on May 8, 2014 and the fixed remuneration for the delegated powers of €148 thousand approved by the Board on May 28, 2014. Claudio Descalzi - Chief Executive Officer and General Manager (a) The amount includes the fixed remuneration of €550 thousand for the position of Chief Executive Officer, which incorporates the remuneration set by the Shareholders’ Meeting on May 8, 2014 for the position of Director, and the fixed remuneration of €800 thousand for the position of Chief Executive Officer; indemnities due for transfers, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and of the Company’s complementary agreements are added to this amount for a total of €19 thousand. (b) The amount correspond to the variable annual incentive paid in 2016. To this amount is added the incentives of €659 thousand paid in 2016 for the position of COO of the E&P Division, held until May 8, 2014, related to the deferred monetary incentive assigned in 2013, calculated in relation to the performance targets achieved during the 2013-2015 vesting period. Andrea Gemma – Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €40 thousand for participating in the Control and Risk Committee and €20 thousand for the Sustainability and Scenarios Committee and €30 thousand for the Nomination Committee. Pietro Angelo Guindani - Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €30 thousand for participating in the Compensation Committee and €20 thousand for the Sustainability and Scenarios Committee. Karina Litvack – Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €23 thousand for participating in the Control and Risk Committee, €20 thousand for participating in the Compensation Committee and €20 thousand for the Sustainability and Scenarios Committee. Alessandro Lorenzi - Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €60 thousand for participating in the Control and Risk Committee and €20 thousand for the Compensation Committee. (5) (4) (6) 150 (7) (8) (9) Diva Moriani – Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €12 thousand for participating in the Control and Risk Committee, €19 thousand for the Compensation Committee and €20 thousand for the Nomination Committee. Fabrizio Pagani – Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €30 thousand for participating in the Sustainability and Scenarios Committee and €20 thousand for the Nomination Committee. Alessandro Profumo – Director (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount includes the €20 thousand for partecipating in the Sustainability and Scenarios Committee and €20 thousand for the Nomination Committee. (10) Matteo Caratozzolo - Chairman of the Board of Statutory Auditors (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of TTPC (€32.1 thousand) and of Eni Adfin (€13.9 thousand). (11) Paola Camagni - Statutory Auditor (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni East Africa (€18 thousand) and Auditor of Syndial (€12 thousand). (12) Alberto Falini - Statutory Auditor (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni Timor Leste (€12.9 thousand) and Auditor of TTPC (€21.2 thousand). (13) Marco Lacchini - Statutory Auditor (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of SOM (€20.3 thousand) and Auditor of Eni East Africa (€12 thousand). (14) Marco Seracini - Statutory Auditor (a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014. (b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Ing. Luigi Conti Vecchi (€18.2 thousand) and Auditor of Eni Adfin (€9.2 thousand). (15) Other Managers with strategic responsibilities (a) The amount of €8,595 thousand for Gross Annual Salary is supplemented by the indemnities owed for the transfers performed, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and with the Company’s additional agreements as well as other indemnities related to the employment contract for a total amount of €851 thousand. (b) The amount includes the payment of €3,170 thousand relating to the deferred and long-term monetary incentives assigned in 2013 and the pro-rata amounts of the Long-Term Incentive Plans (DMI and LTMI) paid upon consensual employment contract resolution, for the vesting period expired as defined in the respective Plan Regulations. (c) The amount includes the taxable value of insurance and welfare coverage, complementary pensions, the car for business and personal use. (d) Amounts due for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231 and the Manager responsible for the preparation of the Company’s financial statements. (e) The amount includes the severance indemnity and early retirement incentives paid in relation to the termination of the employment, to which €1,044 thousand is added for the non-competition clauses payable by 2017 at the expiry of the related validity period, subject to the obligations being fulfilled. OTHER INFORMATION Accrued compensation Total compensation accrued in the year 2016 pertaining to all the Board members amounted to €7.1 million; it amounted to €0.738 million in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company. For the year ended December 31, 2016, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2016 period, filled said roles, even if only for a fraction of the year) amounted to €44 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2016. The breakdown is as follow: 151 Fees and salaries ..................................................................................................... Post-employment benefits ........................................................................................ Other long-term benefits ......................................................................................... Indemnity upon termination of the office .................................................................. 2016 (€ million) 26 2 12 4 44 The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay, as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay. As of December 31, 2016, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the 2016 period, filled said roles, even if only for a fraction of the year), was €1,706 thousand. Name Claudio Descalzi Senior Managers (a) Chief Executive Officer ...................................................... ........................................................................................ (€ thousand) 352 1,353 1,706 (a) No. 18 Managers Board practices Corporate Governance The Corporate Governance structure of Eni follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. Eni complies with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) approved by Italian Corporate Governance Committee (hereinafter “Corporate Governance Code” or “Code”). On July 9, 2015, the Italian Corporate Governance Committee approved a few amendments to the Corporate Governance Code. At its Meeting held on February 25, 2016, the Board adopted the new recommendations of the Code, acknowledging that Eni’s Corporate Governance model was already broadly compliant with the new recommendations. 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. Board of Directors’ duties and responsibilities The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated May 9, 2014, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, in addition to those that cannot be delegated by law, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board. In the same resolution, the Board of Directors resolved to attribute 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 152 Audit Department reports to the Board, and on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system. The Chairman is also involved in the appointment of the primary Eni officers in charge of internal controls and risk management, as well as in approving internal rules governing the Internal Audit process. In addition, the Chairman carries out her statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer. Finally, the Board of Directors entrusted the Board Secretary with the role of Corporate Governance Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He lends assistance and independent legal advice to the Board and the Directors and periodically presents to the Board of Directors a report on the functioning of Eni’s Corporate Governance system. On May 9, 2014, the Board reserved to itself the strategic, operational and organizational powers briefly described below: • • • • • • • • • • • • the Group as a whole. It evaluates the adequacy of defines the system and rules of Corporate Governance for the Company and the Group; establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets; expresses the general criteria for determining the maximum number of offices that a Company Director may hold in other companies; delegates and revokes the powers of the CEO and the Chairman, establishing the limits and procedures for exercising those powers and determining the compensation associated with these duties; establishes the basic structure of the organizational, administrative and accounting arrangements of the Company (including the internal control and risk management system), of its strategically important subsidiaries and of these arrangements; establishes the guidelines for the internal control and risk management system, so that the main risks facing the Company and its subsidiaries are correctly identified and adequately measured, managed and monitored, determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives. It sets the financial risk limits of the Company. It also examines the main business risks, which are identified taking into account the characteristics of the activities carried out by the Company and its subsidiaries and which are reported by the Chief Executive Officer at least quarterly. Moreover, it evaluates, every six months, the adequacy of the internal control and risk management system with respect to the characteristics of the Company and its risk profile, as well as the system’s effectiveness; approves at least annually the Audit Plan drawn up by the Senior Executive Vice President of the Internal Audit Department. It also evaluates the findings contained in the recommendation letter, if any, of the Audit Firm and in its statement on the key issues that arose during the statutory audit; including defines the strategic guidelines and objectives of sustainability policies. It examines and approves the budgets and strategic, industrial and financial plans of the Group, periodically monitoring their implementation, as well as agreements of a strategic nature for the Company. It examines and approves the plan for the Company’s non-profit activities and approves operations not included in the plan whose cost exceeds €500,000; examines and approves the annual financial report (which includes Eni’s draft Financial Statements and the Consolidated Financial Statements) and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report; receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers; receives a report from the Board’s internal committees on at least a semi-annual basis; assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts; the Company and the Group, 153 • • • • • • • evaluates and approves transactions of the Company and its subsidiaries with related parties provided for in the procedure approved by the Board7, as well as transactions in which the CEO has an interest; evaluates and approves any transaction executed by the Company and its subsidiaries that has a significant strategic, economic, financial or asset impact on the Company; appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the Senior Executive Vice President of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of a manager responsible for shareholder relations; examines and approves the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting. It also defines the criteria for remunerating the senior executives of the Company and of the Group and takes steps to implement compensation plans based on shares or other financial instruments approved by the Shareholders’ Meeting; resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries; formulates the proposals to present to the Shareholders’ Meeting; and examines and resolves on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity. In accordance with Article 23.2 of the By-laws, the Board also resolves on mergers and proportional spin-offs of companies in which Eni’s shareholding is at least 90%; the establishment and closing of branches; and the amendment of the By-laws to comply with the provisions of law. In accordance with the By-laws, the Chairman and the Chief Executive Officer retain representative powers for the Company. Directors’ independence On the basis of statements made by the Directors and other information available to the Company, during its meeting of May 9, 2014 and, after an investigation by the Nomination Committee, at its meeting of February 17, 2015, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales8 satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales 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. On July 29, 2015, the Eni Board of Directors appointed Alessandro Profumo to replace Luigi Zingales, who resigned on July 2, 2015. The Board of Directors, following an investigation performed by the Nomination Committee, on the basis of declarations made by Profumo and information available to the Company, ascertained that Profumo was independent according to law and the Corporate Governance Code. With reference to the marital relationship of Profumo with an employee of the Company, the Board resolved that this relationship does not compromise the independence requirements requested by the Corporate Governance Code, on account of Profumo’s ethical and professional integrity and his international reputation and taking into account the fact that his spouse is employed at a foundation, which is independent of Eni SpA9. On February 25, 2016, and most recently on February 28, 2017, on the basis of statements made by the Directors and other information available to the Company, after an investigation by the Nomination Committee, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Profumo satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani (7) (8) (9) 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. Luigi Zingales resigned from the Board of Directors on July 2, 2015. On May 26, 2016, the Board of Directors, after an investigation by the Nomination Committee, on the basis of declarations made by Profumo and information available to the Company, verified that Profumo - confirmed by the Shareholders’ Meeting on May 12, 2016 - was independent in accordance with law and the Corporate Governance Code, confirming the previous assessments. 154 and Profumo have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code. The Board confirmed the independence requirements of Director Profumo on the basis of the aforementioned reasons. At the last assessment, the Board of Directors also evaluated that the commercial relationships between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative, are not significant for the purpose of assessing the independence of the Director himself, having regard to the nature and the amounts of these relationships. The Board of Statutory Auditors ascertained that the Board of Directors correctly applied the assessment criteria and procedures for evaluating the independence of its members. The independence criteria may not be equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company. Board Committees The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the Compensation 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 meetings and may participate in other Committees’ meetings. Furthermore, Committees may invite other persons to attend the meetings in relation to individual items on the agenda. The CEO and the Chairman may attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they may attend Control and Risk Committee meetings, unless matters relating to them are discussed. Finally, they may attend Compensation Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their remuneration. The Board Secretary and Corporate Governance Counsel coordinates the secretaries of the Board Committees, receiving at this end information on the items in the Committees’ agendas, the notices of the meetings, as well as their signed minutes. Minutes of all Committee meetings are usually drafted by their respective secretaries. The current members of the Control and Risk Committee, Compensation Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on May 9, 2014, except for Director Profumo, appointed by the Board of Directors as a member of Nomination Committee and 155 Sustainability and Scenarios Committee on September 17, 2015, and Director Diva Moriani, who was appointed as a member of the Control and Risk Committee on September 15, 2016, replacing Director Karina Litvack10; Director Diva Moriani left the Compensation Committee on December 22, 2016. Compensation Committee Members: Pietro A. Guindani (Chairman), Karina Litvack, Alessandro Lorenzi11. The Compensation Committee is made up of non-executive, independent Directors. All the members possess adequate professional requirements and expertise for carrying out the duties assigned to the Committee. In particular, at his appointment, the Director Guindani was identified by the Board as the member with “adequate knowledge and experience in finance or remuneration policies” as recommended by the Corporate Governance Code. (ii) annual and long-term incentive plans, 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 to the Board of Directors for its approval the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting called to approve the financial statements, as provided for by applicable law; b) presents proposals for the remuneration of the Chairman of the Board and the Chief Executive Officer, covering the various forms of compensation and benefits awarded; c) presents proposals for the remuneration of members of the Board’s internal committees; d) examines the CEO’s indications (i) general criteria for the compensation of Managers with strategic and presents proposals for: responsibilities; including equity-based plans; and (iii) establishing performance targets and assessing results for performance plans in connection with the determination of the variable portion of the compensation for Directors with delegated powers and with the implementation of incentive plans; e) monitors the execution of Board resolutions regarding remuneration matters; f) periodically evaluates the adequacy, overall consistency and actual implementation of the adopted policy, as described in letter a) above, formulating proposals on the topic for the Board of Directors; g) performs the tasks required under the Company’s procedures for handling related party transactions; h) through the Chairman of the Committee, informs the Board of Directors on the main issues examined by the Committee thereof during the first available meeting of the Board; furthermore, the Committee reports to the Board, at least once every six months and no later than the deadline for the approval of the annual Financial Statements and the semi-annual financial report, on its activities at the Board Meeting indicated by the Chairman of the Board of Directors; and i) reports through its Chairman or another Committee member designated by the Chairman on its operational procedures to the Shareholders’ Meeting called to approve the Financial Statements. During 2016, the Compensation Committee met a total of nine times, with an average attendance of 94,4% of its members and an average duration of 3 hours and 13 minutes. All the Committee meetings were attended by at least one member of the Board of Statutory Auditors. Earlier in the year, the Committee focused its activities in particular on the following topics: (i) periodic assessment of the Remuneration Policy implemented in 2015, also for the purpose of defining the proposed Policy Guidelines for 2016; (ii) review of 2015 corporate performance linked to the implementation of annual and long-term incentive plans, in accordance with a “variation analysis methodology” approved by the Committee in order to neutralize the positive or negative impact of exogenous factors, to allow an unbiased assessment of the performance levels achieved; (iii) definition of the 2016 performance targets related to the variable incentive plans, with the introduction of a new metric in the Annual Incentive Plan, enhancing exploration resources as a fundamental asset in order to preserve the sustainability of the Company’s future results; (iv) definition of the proposals for the implementation of the Deferred Monetary Incentive Plan for the Chief Executive Officer and General Manager as well other senior executives; (v) review of the 2016 Eni Remuneration report; (vi) ) review of the outcome of the first in order to maximize shareholder cycle of engagement conducted with main institutional consensus on the 2016 Remuneration Policy, as well as of voting projections produced with the support of an international consultant. investors, (10) On July 28, 2016, Eni’s Board of Directors approved the replacement of Director Karina Litvack with another Director - identified by the Board itself in Director Diva Moriani on September 15, 2016 - in the Control and Risk Committee (CRC) in light of the ongoing investigations related to alleged conspiracy against the Company, reported also by the press. The board has taken this decision only to safeguard the Company from the risks of possible conflicts of interest until the closing of the investigation, remaining the presumption that Director Litvack has not been involved in the facts under investigations. (11) Director Diva Moriani left the Compensation Committee on December 22, 2016 156 In the second part of the year the Committee primarily analyzed the results of the 2016 Shareholder’s Meeting season, regarding the Eni Remuneration Report, the main Italian and European listed companies as well as companies in the peer group of reference. Among other main activities, the Committee also: (i) finalised the proposal concerning the fulfilment (2016 award) of the Long Term Incentive Plan for the Chief Executive Officer and General Manager and other critical management personnel; (ii) initiated the examination of the 2017 Remuneration Policy Guidelines, developing in particular, over the course of a number of meetings, a proposal for the revision of the variable incentive system applicable to the Chief Executive Officer and General Manager as well as Managers with Strategic Responsibilities, with the goal of further strengthening the alignment between the action of management and shareholder interests; (iii) approved the annual engagement plan prepared by the competent company functions and was informed of in implementation of the engagement plan for 2017. the first cycle of meetings held with the main proxy advisors, the findings of The composition and appointment, as well as the duties and operating procedures, of the Committee are governed by the rules approved by the Board of Directors on July 30, 2014, and most recently amended on September 15, 2016, available to the public on the Company’s website. Control and Risk Committee Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Diva Moriani12. The Control and Risk Committee is entrusted with supporting, on the basis of an appropriate control process, the Board of Directors in evaluating and making decisions concerning the internal control and risk management system and in approving the periodical financial reports. It is entirely made up of non-executive and independent Directors13 who possess the necessary expertise consistent with the duties they are required to perform14. In particular, at their appointment, the Directors Lorenzi and Moriani were identified by the Board as members with “adequate experience in the area of accounting and finance or risk management”, as recommended by the Corporate Governance Code. The Committee advises the Board of Directors and specifically issues its prior opinion: a) and drafts recommendations concerning the guidelines for the internal control and risk management system so that the main risks faced by the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored and also supports the Board in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives; b) on the assessment, performed by the Board of Directors, on the main company risks, identified taking into account the characteristics of the activities carried out by the company or its subsidiaries; c) on the evaluation, performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, at least once every six months it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the internal control and risk management system at the meeting of the Board of Directors indicated by the Chairman of the Board of Directors; d) on the approval, at least once a year, of the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; e) on the description, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, and how the different subjects involved therein are coordinated, providing its evaluation of the overall adequacy of the system itself; and f) on the evaluation of the findings reported by the Audit Firm in any recommendations letter it may issue and in the latter’s report on the main issues arising during the audit. The Committee furthermore: a) issues opinions to the Board of Directors on specific aspects concerning the identification of the main risks faced by the Company; b) examines and issues an opinion (12) On September 15, 2016, Eni’s Board of Directors appointed Diva Moriani as member of the Control and Risk Committee in place of Director (13) Karina Litvack, following the replacement approved by the Board of Directors on July 28, 2016. In accordance with the rules of the Control and Risk Committee, the Committee is made up of three to four non-executive Directors, all of whom are independent. Alternatively, the Committee may be made up of non-executive Directors, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. In any case, the number of members shall be fewer than the number representing a majority on the Board. (14) The Governance system put in place by Eni establishes that at least two members of the Committee – and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment. 157 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 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, its duty; c) about any particular material or significant situation detected in the performance of 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. 158 Furthermore, the Committee oversees the activities of the Legal Affairs Department in case of judicial inquiries, carried out in Italy and/or abroad, in relation to which the CEO and/or the Chairman of the Company and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, have received a notice of investigation for crimes against the Public Administration and/or corporate crimes and/or environmental crimes, related to their mandate and their scope of responsibility. The composition and appointment, as well as duties and operational procedures of the Committee, are governed by rules approved by the Board of Directors on July 30, 2014 and amended on April 7, 2016, available to the public at the Company’s website. Nomination Committee Members: Andrea Gemma (Chairman), Diva Moriani, Fabrizio Pagani and Alessandro Profumo. The Nomination Committee is made up of non-executive Directors, a majority of whom are independent. The Committee provides the Board of Directors with recommendations and advice. In particular, the Committee: a) assists the Board of Directors in formulating any criteria for the appointment of persons indicated in the following letter and of 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, whose appointment fall under the Boards’ responsibility and oversees the associated succession plans. Where possible and appropriate, in relation to the shareholding structure, the Committee proposes to the Board of Directors the succession plan for the Chief Executive Officer; c) acting upon proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession plan for the Company’s key management personnel; d) proposes candidates to serve as Directors on 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 on the minimum number of independent Directors and of 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 recommendation 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 sentence, 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 to be submitted 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; and 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 financial statements and of the semi-annual financial report, on the activity carried out, as well as on the adequacy of the appointment system, at the Board Meeting indicated by the Chairman of the Board of Directors. The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors on July 30, 2014, and amended on April 7, 2016, available to the public at the Company’s website. 159 Sustainability and Scenarios Committee Members: Fabrizio Pagani (Chairman), Andrea Gemma, Pietro A. Guindani, Karina Litvack and Alessandro Profumo. The Sustainability and Scenarios Committee is made up of non-executive Directors, a majority of whom are independent. The Sustainability and Scenarios Committee provides recommendations and advice to the Board of Directors on scenarios and sustainability, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: the health, well-being and safety of people and communities; the protection of rights; local development; access to energy, energy sustainability and climate change; the environment and efficient use of resources; integrity and transparency; and innovation. Board of Statutory Auditors The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of three financial years. The Board’s term will therefore expire with the May 8, 2014 for a term of Shareholders’ Meeting called to approve the Financial Statements for the year ending December 31, 2016. Name Matteo Caratozzolo Paola Camagni Alberto Falini Marco Lacchini Marco Seracini Stefania Bettoni Mauro Lonardo Position Chairman Auditor Auditor Auditor Auditor Alternate Alternate Year first appointed to Board of Statutory Auditors 2014 2014 2014 2014 2014 2014 2014 Paola Camagni, Alberto Falini, Marco Seracini and Stefania Bettoni (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; Matteo Caratozzolo (Chairman), Marco Lacchini and Mauro Lonardo (Alternate) were candidates listed in the slate presented by non-controlling shareholders (institutional investors). The Auditors are appointed by means of a slate voting system: the lists are presented by shareholders representing at least 0.5% of the share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders. In accordance with the provisions designed to ensure gender balance, which were applied for the first time in the elections of the Board of Directors and the Board of Statutory Auditors at the Shareholders’ Meeting held on May 8, 2014, one Statutory Auditor and one Alternate Statutory Auditor were drawn from the less represented gender. For the next two elections, one third of the statutory auditors will be drawn from the less represented gender. The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. Regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of Financial Statements and internal control processes. 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 160 the Board’s Authority, the adequacy of within the scope of the internal control system and the administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements. In addition, pursuant to Article 19 of Legislative Decree No. 39/2010 (in force as of December 31, 2016) in its role as the “internal control and financial auditing committee” the Board of Statutory Auditors oversees the following: (a) the financial reporting process; (b) the efficacy of internal control, internal audit (where applicable) and risk management systems; (c) the auditing of the annual financial statements and Consolidated Financial Statements; and (d) the independence of the external auditor or the Audit Firm, in particular with regard to the provision of non-audit services to the entity subject to financial auditing. The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee” are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “U.S. Sarbanes-Oxley Act” (discussed in greater detail below). As already set forth in the Consolidated Law on Financial Intermediation and currently regulated by Article 13 of Legislative Decree No. 39/2010, the Board of Statutory Auditors submits a reasoned opinion to the Shareholders’ Meeting on the selection of the external auditors and the determination of the associated fees. As from 2017 the above tasks provided for by the Legislative Decree. no. 39/2010, have been updated by Legislative Decree no. 135/ 2016, to comply with European Directive no 56/2014. In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements. On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, and lastly on May 28, 2014, the Board of Statutory Auditors approved the internal rules concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website15. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC rules are as follows: • • • • • • • 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; making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting; approving the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters; approving the procedures for the pre-approval of specifically identified admissible non-audit services and examining the disclosures on the execution of the authorized services; evaluating requests to use the external auditor firm engaged to perform audit services for admissible non-audit services and providing its opinion to the Board of Directors; examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within (15) These internal rules will be subject to revision and possible updating to take into account the aforementioned regulatory changes. 161 generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management; examining reports from the CEO and the CFO concerning any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and examining reports from the CEO and the CFO concerning 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. legal entities, 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”), including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the Watch Structure. Moreover, as a result of changes in the Italian legislation governing the matter and of the Company’s organizational structures, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of October 27, 2016, ratified the updating of Model 231 to incorporate a number of legislative changes in the environmental crimes provided for by Law no. 68/ 2015 (“eco-crimes”). The synergies between the Code of Ethics – an integral part and essential general principle of Model 231 – and Model 231 are highlighted by the assignment, to the Eni Watch Structure, of the function of Guarantor of the Code of Ethics. 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. Audit Firm The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit Firm appointed by the Shareholders’ Meeting on the basis of a reasoned recommendation of the Board of Statutory Auditors. In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm issue 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. 162 For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit Firm. Moreover, Eni’s Audit Firm, for the purpose of issuing an opinion on the Consolidated Financial Statements, assumes responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which, taken together, account for an immaterial share of consolidated assets and revenues. Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of April 29, 2010 appointed Ernst & Young SpA for the financial years 2010-2018. 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 is 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. The Magistrate of the Court attends the meetings of the Board of Employees As of December 31, 2016, Eni had a total of 33,536 employees, with a decrease of 660 employees, or down by 1.9% from December 31, 2015, which mainly reflects a decrease of 690 employees working outside Italy. Employees at year end Exploration & Production ............................................................... Gas & Power .................................................................................. Refining & Marketing and Chemicals ............................................... Corporate and Other activities ......................................................... 12,777 4,561 11,884 5,624 (number) 12,821 4,484 10,995 5,896 34,846 34,196 12,494 4,261 10,858 5,922 33,536 2014 (1) 2015 (1) 2016 (1) Excluding the operating segment E&C divested in January 2016. 163 The table below sets forth Eni’s employees as of December 31, 2014, 2015 and 2016 in Italy and outside Italy: Exploration & Production 2014 (1) 2015 (1) 2016 Italy ................................ Outside Italy ..................... 4,534 8,243 (number) 4,572 8,249 4,608 7,886 Gas & Power Italy ................................ Outside Italy ..................... Refining & Marketing and Chemicals Italy ................................ Outside Italy ..................... 12,777 12,821 12,494 2,067 2,494 4,561 9,286 2,598 2,023 2,461 4,484 8,635 2,360 2,032 2,229 4,261 8,577 2,281 11,884 10,995 10,858 Corporate and other activities Italy ................................ Outside Italy ..................... 5,320 304 5,624 Total Italy ................................ Outside Italy ..................... 21,207 13,639 5,650 246 5,896 20,880 13,316 of which senior managers ........................................ 1,074 1,061 34,846 34,196 5,693 229 5,922 20,910 12,626 33,536 1,036 (1) Excluding the operating segment E&C divested in January 2016. We seek to maintain constructive relationship with labor unions. Share ownership As of February 28, 2017, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 303,091 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. Name Position Board of Directors Emma Marcegaglia Claudio Descalzi Board of Statutory Auditors ...................................................................................................... Senior Managers ........................................................................................................ Chairman ........................................................................ CEO ................................................................................ Number of shares owned 87,447 (1) 39,455 5,000 (2) 171,189 (3) (1) (2) (3) Of which No. 1,034 shares held under Asset Management, No. 7,143 shares held under Asset Management jointly with a third person, and No. 45,000 shares held as naked owner jointly with a third person. Shares held under Asset Management. Of which No. 14,390 shares owned by spouses not legally separated and by underage children. 164 Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS Major Shareholders The Ministry of Economy and Finance controls Eni as a result of the shares directly owned and those indirectly owned through Cassa Depositi e Prestiti SpA (CDP), in which the Ministry of Economy and Finance holds a 82.77% stake. As of February 28, 2017, the total amount of Eni’s voting securities owned by these shareholders was: Title of class Number of shares owned Percent of class Ministry of Economy and Finance ................................... Cassa Depositi e Prestiti SpA ........................................... 157,552,137 936,179,478 4.34 25.76 The following table shows the percentage of Eni’s share capital owned, either directly or indirectly, by persons that as of February 28, 2017 have notified that their holding either exceeds the threshold of 3% since March 18, 2016 pursuant to Article 120 of the Legislative Decree No. 58/1998 (as amended by article 1 of Legislative Decree No. 25 of February 15, 2016) and to the Consob Regulation No. 11971/1999 (as amended by Consob Resolution No. 19614 of May 26, 2016) or the previous threshold of 2% (in effect until March 17, 2016)1. Title of class Percent of class People’s Bank of China ................................................................................... 2.102 Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified Italian legislation governing the special powers of the Italian State to comply with European rules. See “Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)”. As of February 28, 2017, there were 36,611,569 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 2.0% of Eni’s share capital. See “Item 9 – The offer and the listing”. Related party transactions In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with non-consolidated subsidiaries and 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 companies. Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in “Item 18 – note 47 of the Notes on Consolidated Financial Statements”. (1) The Legislative Decree No. 25/2016, in force since March 18, 2016, modified the Article 120 of the Legislative Decree No. 58/1998, increasing this holding threshold from 2% to 3%. See “Item 10 – Additional information – Shareholder ownership thresholds”. 165 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, Eni believes that the foregoing will likely not have a material adverse effect on Eni’s Consolidated Financial Statements. For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”. Dividends Eni’s future dividend policy, as well as 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 future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the “Risk factors” set out in Item 3 and the oil price scenario adopted by management described in “Item 5 – Management’s expectations of operations”. The parent company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. In 2017, we confirm our commitment to pay a full cash dividend of €0.80 per share and, later on, to a progressive distribution policy in line with the achievement of our plans of underlying earnings and cash flow growth and the scenario evolution. For further information on the Company’s dividend policy see “Item 5 – Management’s Expectations of Operation.” In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. For further details see “Item 3 – Risk factors” and the other planning assumptions and initiatives described in “Item 5 – Management’s expectations of operations”. At the General Shareholders’ Meeting scheduled on April 13, 2017, management intends to propose the distribution of a dividend of €0.80 per share for fiscal year 2016, of which €0.40 paid as interim dividend in September 2016. Total cash outlay for the 2016 balance dividend is expected at approximately €1.4 billion (whereas €1.4 billion were distributed in September 2016) if the General Shareholders’ Meeting approves the annual dividend. Significant changes See “Item 5 – Recent developments” for a discussion of significant events occurred after 2016 year end up to the latest practicable date. 166 Item 9. THE OFFER AND THE LISTING Offer and listing details The principal trading market for the ordinary shares of Eni SpA (Eni), without indication of par value (the “Shares”), is the Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (Borsa Italiana). Eni’s American Depositary Receipts (ADRs), each representing two Shares, are listed on the New York Stock Exchange. The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. See “Item 3 – Key information – Exchange rates” regarding applicable exchange rates during the periods indicated below. Year ended December 31, 2012 ........................................................................................... 2013 ........................................................................................... 2014 ........................................................................................... 2015 ........................................................................................... 2016 ........................................................................................... 2015 First quarter ............................................................................... Second quarter............................................................................. Third quarter .............................................................................. Fourth quarter ............................................................................ 2016 First quarter ............................................................................... Second quarter............................................................................. Third quarter .............................................................................. Fourth quarter ............................................................................ Month of September 2016 ........................................................................... October 2016 .............................................................................. November 2016 ........................................................................... December 2016 ........................................................................... January 2017 ............................................................................... February 2017 ............................................................................. March 2017 (through March 17, 2017) ............................................ MTA New York Stock Exchange High Low High Low (Euro per share) (U.S.$ per ADR) 18.700 19.480 20.410 17.430 15.470 15.250 15.290 13.290 13.140 10.930 49.440 52.120 55.300 39.290 33.330 36.850 40.390 32.810 29.280 25.000 16.680 17.430 16.210 15.730 13.370 15.720 13.140 13.240 37.690 39.290 35.610 36.020 31.960 34.940 30.300 29.280 13.800 14.580 14.900 15.470 10.930 12.320 12.310 12.260 31.050 33.330 33.250 32.240 25.000 28.170 27.650 26.260 14.030 13.770 13.140 15.470 15.720 14.580 15.270 12.310 12.890 12.260 13.540 14.210 14.120 14.470 31.600 30.170 28.740 32.240 33.260 31.260 32.250 27.650 28.940 26.260 28.650 30.880 30.070 30.780 Since January 18, 2012, the Bank of New York Mellon (the “Depositary”) functions as depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) among Eni, the Depositary and the beneficial owners (“Beneficial Owners”) and registered holders from time to time of the ADRs issued hereunder. As of February 28, 2017, there were 36,611,569 ADRs outstanding, representing 71,233,138 ordinary shares or approximately 2% of all Eni’s shares outstanding, held by 105 holders of record (including the Depository Trust Company) in the United States, 104 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 167 MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The constituents of the FTSE MIB are selected based on market capitalization of free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free float and foreign ownership limits. Since June 1, 2009, the FTSE MIB is the principal indicator used to track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are the first largest component of the FTSE MIB, with a weighting of approximately 14%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective December 19, 2016. Beginning from October 6, 2014, a two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Market (SeDeX). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated market where it is possible to trade securitized derivatives (for instance, covered warrants and certificates). Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an “official price”, calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades and block trades, and a “reference price”, calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective February 13, 2017: (i) ± 5.0% (or such other amount established by Borsa Italiana in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall be the previous day’s reference price, in the opening auction, or the auction price, 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 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. According to Consob regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which are MTA (shares, convertible bonds, pre-emptive rights, warrants and Funds), ETFplus (Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes and open-ended funds market), IDEM (index, stock and other derivatives market), SeDeX (covered warrants and certificates), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets. According to EU Markets in Financial Instruments Directive (No. 2004/39/EC) (MiFID) and Consob regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (MTFs) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm or a bank which deals on own account by executing client orders outside a Regulated Market or a MTF. Outside Regulated Markets, block trading is also permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana. 168 Following the transposition in Italy of Directive No. 2014/65/EU (“MiFID II”), which is due to be implemented by 3 January 2018, Organized Trading Facilities (“OTFs”) will be included among the “trading venues” that are subject to regulation. An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract. The implementation of the MiFID II and entry into force of the Regulation (EU) No. 600/2014 (“MiFIR”) will entail some additional changes to the regulatory framework currently applicable to Regulated Markets, MTFs and Systematic Internalisers. According to Legislative Decree No. 58 of February 24, 1998, as amended from time to time (“Decree No. 58”, the Consolidated Law on Financial Intermediation), the provision of investment services and activities to the public on a professional basis is reserved to banks and investment firms (“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. 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 (“EMIR”) and the Regulation (EU) No. 909/2014 (“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). Item 10. ADDITIONAL INFORMATION Memorandum and Articles of Association Company register “Eni SpA” is the company resulting from the privatization of Ente Nazionale Idrocarburi, a public agency, established by Law No. 136 of February 10, 1953 and it is registered in the Rome Companies Register, with identification number (and tax number) 00484960588, and VAT number 00905811006. The Company’s registered office is in Rome, Italy, and the Company has two branch offices in San Donato Milanese (Milan). The full text of Eni’s By-laws is attached as an exhibit to this Annual Report (last amended on November 20, 2014). 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. 169 Directors’ issues Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting. If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members. The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions. According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors. In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote. For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see “Item 6 – Board of Directors’ duties and responsibilities”. Interests in Company’s transactions As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob (“Commissione Nazionale per le Società e la Borsa” is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the “Consob Regulation”), the Board of Directors – on November 18, 2010 – unanimously approved the Management System Guidelines “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”1 (“MSG”), which has been in effect from January 1, 20112 to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. This MSG and the subsequent amendments received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The MSG sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and (1) (2) The Board of Directors modified this Management System Guideline on January 19, 2012. This MSG replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The new provisions regarding information to be provided to the public, under both the Consob Regulation and the MSG, have been applied since December 1, 2010. 170 shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required. Moreover, to ensure compliance with the procedures envisaged by the above mentioned MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in which they explain their potential interests related to Eni and its subsidiaries, and in any case they inform the CEO (or the Chairman, in the case the CEO holds an interest) about individual transactions that Eni intends to carry out in which they have an interest; the CEO (or Chairman) will then inform the other Directors and the Board of Statutory Auditors. Compensation Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors assigned particular duties in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the Compensation Committee, after consultation with the Board of Statutory Auditors (for more details about the compensation policy in 2016, see “Item 6 – Compensation”). 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 to €4,005,358,876.00, 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, 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. share capital amounts the Company’s the By-laws, 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. 171 Voting rights The general provisions on share “voting rights” are described at the paragraph “Shareholders’ Meeting” below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see “Item 6”), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 25, 2017, 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. 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 including and Eni’s By-laws, contains all the information for attending and voting at the meeting, 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 172 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. 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 33 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved. (3) This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below. 173 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, modified Italian legislation governing the special powers of the Italian State to comply with European rules4. The new special powers no longer apply to specific State-controlled companies, identified by name, but to companies that hold strategic assets vital to the interests of the Italian State as defined by the ministerial regulations which implement the relevant law. The current legislation governing the special powers briefly include: a) veto power (or the power of imposing conditions or requirements) over 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. The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of in the EU of stock of company that holds strategic assets be allowed on condition of reciprocity, compliance with international agreements signed by Italy or the EU. These powers are exercised exclusively on the basis of objective and non-discriminatory criteria. Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force. In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily (4) 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. 174 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 instruments be issued to them with the right to vote in ordinary and extraordinary new financial 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 Finance5 and the Consob Regulation6, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%7 (until March 17, 2016, the threshold was 2%), 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6% and 90% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds. Such disclosures shall be made – using the forms contained in Annex 4A to the above Regulation – without delay and, in any case, within four days of the transaction, starting from the day on which the subject gains knowledge of the transaction that can lead to the obligation, regardless of the date of execution, or from the date on which the subject obliged to make the disclosure gains knowledge of the event that leads to changes in the share capital as contemplated in the Consob Regulation. For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria8. 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 investments9. 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% (until March 17, 2016, the threshold was 2%) of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code. (5) (6) (7) (8) (9) Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122. Article 117 of Consob Decision No. 11971/1999 and subsequent amendments. The Legislative Decree No. 25/2016, in force since March 18, 2016, modified the Article 120 of the Legislative Decree No. 58/1998, increasing this holding threshold from 2% to 3%. Moreover, Consob may, by means of measures justified by the need to protect investors, as well as corporate control market and capital market efficiency and transparency, envisage – for a limited period of time – lower thresholds by its decree for companies with an elevated current market value and, particularly, extensive shareholding structure. Article 118 of Consob Decision No. 11971/1999 and subsequent amendments. Article 119 of Consob Decision No. 11971/1999 and subsequent amendments. 175 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. Finally, in accordance with Law No. 287 of October 10, 1990, any merger or acquisition of sole or joint control over a company or any change of control over a company that would create or strengthen a dominant position in the domestic market in a manner that eliminates or significantly reduces competition is prohibited and mergers and acquisition of specified dimension must be subject to the prior authorization of the Italian Antitrust Authority10. However, if the merging parties or the acquiring party and the company to be acquired operate in more than one EU Member State and/or outside Europe and exceed certain thresholds (e.g. turnover, asset value or market share thresholds), the antitrust approval for the merger and/or acquisition can fall under the jurisdiction of the European Commission or the EU Members States and/or other Competition Authorities outside Europe. 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 the authorizing the share capital shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind. increase. The shareholders’ pre-emptive right is also waived if Material contracts None. (10) Autorità garante per la concorrenza e il mercato (AGCM - www.agcm.it). 176 Exchange controls There are no exchange controls in Italy. Residents and non-residents in Italy may carry out any investments, divestments and other transactions that entail a transfer of assets to or from Italy, subject only to the reporting, record-keeping and disclosure requirements described below. In particular, residents of Italy may hold foreign currency and foreign securities of any kind, within and outside Italy, while non-residents may invest in Italian securities without restriction and may export from Italy cash, instruments of credit or payment and securities, whether in foreign currency or euro, representing interest, dividends, other asset distributions and the proceeds of dispositions. Updated reporting and record-keeping requirements are contained in the Italian legislation which implements an EU directive regarding the free movement of capital. Such legislation requires that transfers into or out of Italy of cash or securities in excess of €12,500 be reported in writing to the relevant authority (Ministry of Economy and Finance) by residents or non-residents that effect such transfers directly, or by banks, securities dealers or Poste Italiane SpA (Italian Mail) that effect such transactions on their behalf. In addition, banks, securities dealers or Poste Italiane SpA effecting such transactions on behalf of residents or non-residents of Italy are required to maintain records of such transactions for five years. These records may be inspected at any time by Italian Tax and Judicial Authorities. Non-compliance with these reporting and record-keeping requirements may result in administrative fines or, in the case of false reporting and in certain cases of incomplete reporting, criminal penalties. 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 received by Italian resident individuals in relation to interest exceeding 2% of the voting rights or 5% of the share capital (“substantial interest”) are included in the taxable income subject to personal income tax to the extent of 49.72% of their amount. Article 1, paragraph 64 of Law No. 208 of December 28, 2015 (“Italian Budget Law for the 2016”) provides that the percentages of the dividends relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61 of the aforementioned Italian Budget Law for the 2016.Personal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends received by Italian resident individuals in relation to non-substantial interest not related to the conduct of a business are subject to a substitute tax of 26% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return. If the non-substantial interest is related to the conduct of a business, dividends are included in the taxable business income for 49.72% of their amount. Article 1, paragraph 64 of the Italian Budget Law for the 2016 provides that the percentages of the dividends and capital gains relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61 of the aforementioned Italian Budget Law for the 2016. The change of tax rate does not apply to the entities referred to into Article 5 of Presidential Decree 22 December 1986 No. 917. Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to undistributed profit of 2007 and previous years. Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, and società di investimento a capitale variabile (SICAV) are not subject to substitute 177 tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares. Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units. Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute tax (12.5% as regards income from government bonds). Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment. Dividends are subject to a 1.375% 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 Norway. Because corporate tax rate has been decreased to 24%, from the 1st of January 2017, the above mentioned dividends on 2017 income are subject to a 1,2% withholding tax. the Beneficial Owner of The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence 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, 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. 178 As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (ADSs), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith. Capital gains tax This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy. Profits gained by Italian resident individuals upon the sale of a substantial interest are included in the taxable base subject to personal income tax for 49.72% of their amount. Article 1, paragraph 64 of the Italian Budget Law for the 2016 provides that the percentages of the capital gains relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61, of the aforementioned Italian Budget Law for the 2016. Gains realized upon the sale of non-substantial interest is subject to a substitute tax at a 26% rate. For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return: • • the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 26% substitute tax to be applied by the portfolio. Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax. On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to the capital gains tax. However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non taxability pursuant to the convention have been satisfied. Financial Transactions Tax Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable is 0.10% for ADR negotiated in regulated markets (like the NYSE). 179 Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law. Inheritance and gift tax Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows: (a) 4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary); (b) 6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding €100,000 (per beneficiary); (c) 6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity, as well as to persons related by collateral affinity up to the third degree; and (d) 8 per cent: in all other cases. If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place. United States taxation The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not purport to address all material tax consequences of the ownership of Shares or ADSs. 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 Eni SpA’s Shares, 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 a partnership holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs. As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust. The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the income tax convention between the United States and Italy with their advisors and to discuss with their advisors any 180 possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax. Dividends 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 or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities. For non-corporate U.S. Holders, dividends paid that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by the Group with respect to the Shares or ADSs will generally be qualified as dividend income. 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 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 is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See “Italian taxation – Income tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the shares will be income from sources outside the United States and will, depending on your circumstances,be either “passive” or “general” income for purposes of computing the foreign tax credit allowable to you. 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, determined at the spot rate on the date of disposition). Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes. PFIC rules Eni believes that Shares and ADSs should not be treated as stock of a PFIC for U.S. federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, if classified as a U.S. Holder, 181 one 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 http://www.eni.com/en_IT/documentation/ Company website the at: available documentation.page?type=bil-rap. online on 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. SEC at the U.S. SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, USA. You may also call the U.S. SEC at +1 800-SEC-0330 or log on to www.sec.gov. It is also possible to read and copy documents referred to in this Annual Report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17th floor, New York, USA. Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market risk is the possibility that the exposure to fluctuations 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. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity. The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and petrochemical operations depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products as in the case of gas prices. 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 182 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 and Eni Finance International manage subsidiaries’ financing requirements in and outside Italy, 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). Eni’s activities are in compliance with regulatory requirements for execution of financial derivatives on European and non-European Regulated Markets, on Multilateral Trading Facilities, on Organized Trading Facilities or bilaterally with OTC counterparties. In addition to the reinforcement of the centralized execution model, as required by the new financial regulation, in 2013 the EMIR concepts of “risk reducing” and “non-risk reducing” derivatives were introduced. Activities 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 value, direct or caused by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk, of different assets under Eni control or that Eni will have under its controls in the normal course of business; or (ii) qualifies as a hedging contract pursuant to IFRS. 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 entailcounterparty 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. 183 • • Asset-backed hedging: is a portfolio-based activity performed to protect assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated to assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible is an asset the higher is its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. In order to protect the value of asset flexibility a business unit may transfer to a central entity part or the whole of 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 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 the target of a portfolio physical delivery) and related financial derivatives. Normally, management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, prices scenarios and logistic flexibility/constraints, determine the optimal configuration in term of volume, price and flexibility for physical and commercial assets in the portfolio. Financial derivatives are then used in the portfolio management activity in order to manage the overall risk level associated to such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the portfolio in line with company’s targets. Market risk associated to portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence financial Derivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several times. 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. 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 38 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks. Please also refer to “Item 18 – notes 15, 23, 28, 33 and 34 of the Notes on Consolidated Financial Statements” for details of the different derivatives owned by the Company in these markets. 184 Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES Item 12A. Debt securities Not applicable. Item 12B. Warrants and rights Not applicable. Item 12C. Other securities Not applicable. Item 12D. American Depositary Shares In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. Since January 18, 2012, Eni’s ADRs are issued, cancelled and exchanged at the office of Bank of New York Mellon, as depositary (the “Depositary”) under the Deposit Agreement between Eni, the Depositary and the holders of ADRs. Computershare is the transfer agent for the Eni SpA ADR program. Société Générale Securities Services SpA and UniCredit SpA are the custodians (the “Custodian”) on behalf of the holders of Eni’s ADRs, and their principal offices are located in Milan, Italy. Fees and charges paid by ADR holders The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. 185 The table below sets forth all fees and charges that a holder of Eni’s ADRs may have to pay, either directly or indirectly, to Bank of New York Mellon, as Depositary. Type of service Amount of fees or charges(1) Depositary actions (a) Depositing or substituting the $5.00 (or less) for each 100 ADSs Each person to whom ADRs are issued underlying shares (or portion of 100 ADSs) against deposits of shares, including deposits and issuances in respect of: • • Share distributions, stock split, rights, merger. Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities. (b) Selling or exercising rights $5.00 (or less) for each 100 ADSs Distribution or sale of securities, the fee (or portion of 100 ADSs) being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities. (c) Withdrawing an underlying security $5.00 (or less) for each 100 ADSs (or portion of 100 ADSs) Acceptance of ADRs surrendered for withdrawal of deposited securities. (d) Transferring, splitting or grouping Registration or transfer fees receipts Transfers, combining or grouping of depositary receipts. (e) Expenses of the depositary Varied charges Expenses incurred on behalf of holders in connection with: • The Depositary’s or its custodian’s compliance with applicable law, rule or regulation. Stock transfer or other taxes and other governmental charges. Cable, telex, facsimile transmission/ delivery. Expenses of the Depositary in connection with the conversion of foreign currency into U.S. dollars (which are paid out of such foreign currency). Any other charge payable by Depositary or its agents. • • • • (f) Distribution of cash $0.02 (or less) per ADS Any cash distribution to ADS registered (g) Depositary services $0.02 (or less) per ADS per calendar year holders. Depositary services. (1) All fees and charges are paid by ADR holders to Bank of New York Mellon as Depositary and Transfer agent. Fees and payments made by the Depositary to the issuer The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the NYSE. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing U.S. SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities. For the year 2016, as agreed in the Deposit Agreement with the previous depositary bank, JPMorgan Chase Bank of New York, and subsequent amendments, the Depositary will reimburse to Eni up to US$2,200,000 in connection with above mentioned expenditures. 186 Expenses waived or paid directly to third parties by the Depositary The Depositary reimbursed to the company, or paid amounts on the company’s behalf to third parties, or waived its fees and expenses, of US$189,419.31 for the year ended December 31, 2016. Category of expense reimbursed, waived or paid directly to third parties BNY Mellon products and services ..................................................... BNY Mellon related to servicing registered shareholders ........................ BNY Mellon paid to third-party vendors(1) .......................................... Total ................................................................................................ (1) Includes payments for AGM and related ADR Program services. Amount reimbursed, waived or paid directly to third parties for the year ended December 31, 2016 (US$) 120,000.00 650.90 68,768.41 189,419.31 187 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. 188 The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (CoSO) in 2013. Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2016. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2016, has been audited by Reconta Ernst & Young SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F. Changes in Internal Control over Financial Reporting There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Item 16. [RESERVED] Item 16A. Board of Statutory Auditors financial expert Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: Matteo Caratozzolo, who is the Chairman of the Board, Paola Camagni, Alberto Falini, Marco Lacchini and Marco Seracini. All members are independent. Item 16B. Code of Ethics Eni adopted a Code of Ethics that applies to all Eni’s employees including Eni’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Corporate Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F. Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model. Item 16C. Principal accountant fees and services Reconta Ernst & Young SpA has served as Eni principal independent public auditor for fiscal years 2016 and 2015 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F. 189 The following table shows total fees paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures for services provided by Eni to its public auditors Reconta Ernst & Young SpA and its respective member firms, for the years ended December 31, 2016 and 2015, respectively: Year ended December 31, 2015 2016 (€ thousand) Audit fees ......................................................................... Audit-related fees .............................................................. Tax fees ........................................................................... All other fees .................................................................... 33,752 1,138 3 21,433 1,874 Total ................................................................................ 34,893 23,307 Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting. Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due diligence, audit and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards. Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value-added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities. All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations. Pre-approval policies and procedures of the Internal Control Committee The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities within the Eni Group which are either controlled or jointly controlled (directly or indirectly) by Eni SpA. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors. During 2016, 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. 190 Item 16D. Exemptions from the Listing Standards for Audit Committees Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, performs the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act to be carried out by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 – Board of Statutory Auditors” above). Item 16E. Purchases of equity securities by the issuer and affiliated purchasers The issuer and its affiliated purchasers have not executed any purchase of equity securities of the issuer since the end of 2014 and up to and as of the date of the 20-F filing for the year ended December 31, 2016. Item 16F. Change in Registrant’s Certifying Accountant Not applicable. Item 16G. Significant Section 303A.11 of the New York Stock Exchange Listed Company Manual in Corporate Governance differences practices as per 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 their 191 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 independence requirements. The Corporate Governance Code provides for additional 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 2016, Eni’s independent Directors had numerous opportunities to meet, formally and informally, to hold discussions and exchange opinions. 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 Code1. On (1) The Committee is currently made up of four Directors, three of whom are independent. 192 May 9, 2014, the Board of Directors of Eni established the Nomination Committee, chaired by Andrea Gemma (independent Director) and composed of Diva Moriani (independent Director), Fabrizio Pagani (non-executive Director) and Luigi Zingales (independent Director). On September 17, 2015, the Board appointed Director Alessandro Profumo (independent Director) as a member of the Committee, replacing Luigi Zingales who resigned from the Board on July 2, 2015. Further details on this Committee are reported in the Item 6. Compensation Committee NYSE standards. U.S. listed companies must have a Compensation Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The Compensation Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The Compensation Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers. Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a Compensation Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have an adequate understanding of and experience in financial matters or compensation policies. First established by the Board of Directors in 1996, the Compensation Committee is currently chaired by Director Pietro A. Guindani. The other members include directors Karina A. Litvack and Alessandro Lorenzi2. Further details on this Committee are reported in the Item 6. Code of Business Conduct and Ethics NYSE standards. The NYSE listing standards require each U.S. listed company to adopt a Code of Business Conduct and Ethics for its Directors, Officers and employees, and to promptly disclose any waivers of the code for Directors or Executive Officers. Eni standards. 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 October 27, 2016, ratified the updating of Model 231 to incorporate a number of legislative changes provided for by law No. 68/2015 (“eco-crime”). The CEO is supported in this activity by the “Technical Committee 231”, consisting of members from the Company’s Legal Affairs, Integrated Compliance Department, Human Resources and Organization and Internal Audit units. Eni’s Code of Ethics, which is an integral part of Model 231, sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All Eni personnel, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under U.S. SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties. The synergies between the Code of Ethics and Model 231 are underscored by the designation of the Eni Watch Structure, established under Model 231, as the Guarantor of the Code of Ethics. The Guarantor of the Code of Ethics acts to ensure the protection and promotion of the above principles. Every six months, it presents a report on the implementation of the Code to the Control and Risk Committee, to the Board of Statutory Auditors and to the Chairman and (2) Director Diva Moriani left the Compensation Committee on December 22, 2016. 193 the CEO, who in turn reports on this to the Board of Directors. At present, the Watch Structure of Eni SpA is composed of three external members, including the Chairman, and four internal members. The internal members are Company executives in charge of Legal Affairs, labor law matters and disputes, Internal Audit and Integrated Compliance. External members are independent professionals, experts in law and/or economic matters. Item 16H. Mine safety disclosure Not applicable since Eni does not engage in mining operations. 194 PART III Item 17. FINANCIAL STATEMENTS Not applicable. Item 18. FINANCIAL STATEMENTS Index to Financial Statements: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheet as of December 31, 2016 and December 31, 2015 and January 1, 2015 Consolidated profit and loss account for the years ended December 31, 2016, 2015 and 2014 Consolidated Statements of comprehensive income for the years ended December 31, 2016, 2015 and 2014 Consolidated Statements of changes in shareholders’ equity for the years ended December 31, 2016, 2015 and 2014 Consolidated Statement of cash flows for the years ended December 31, 2016, 2015 and 2014 Notes on Consolidated Financial Statements Page F-1 F-3 F-4 F-5 F-6 F-8 F-10 Item 19. EXHIBITS 1. By-laws of Eni SpA 8. List of subsidiaries 11. Code of Ethics Certifications: 12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act 12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act 13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act) 13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act) 15.a(i) Report of DeGolyer and MacNaughton 15.a(ii) Report of Ryder Scott Co 15.a(iii) Gaffney, Cline & Associates 195 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Eni S.p.A. We have audited the accompanying consolidated balance sheets of Eni S.p.A. as of December 31, 2016 and 2015, and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eni S.p.A. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. As discussed in Note 5 to the consolidated financial statements, the Company has elected to change its method of accounting for the oil & gas exploration and production activities to the “Successful Efforts Method”. The Company applied this change in accounting principle retrospectively to all prior periods presented. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni S.p.A.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 22, 2017 expressed an unqualified opinion thereon. /s/ Ernst & Young S.p.A. Rome, Italy March 22, 2017 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Eni S.p.A, We have audited Eni S.p.A.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of (the COSO criteria). Eni S.p.A.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. the Treadway Commission (2013 framework) We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) 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. In our opinion, Eni S.p.A. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Eni S.p.A. as of December 31, 2016 and 2015, and the related consolidated profit and loss account and consolidated statements of comprehensive income, the three years in the period ended changes in shareholders’ equity, and cash flows for each of December 31, 2016 and our report dated March 22, 2017 expressed an unqualified opinion thereon. /s/ Ernst & Young S.p.A. Rome, Italy March 22, 2017 F-2 CONSOLIDATED BALANCE SHEET (euro million) January 1, 2015(a) Total amount of which with related parties December 31, 2015(a) December 31, 2016 Note Total amount of which with related parties Total amount of which with related parties 1,973 43 259 12 181 1,954 58 20 6,614 5,024 257 28,601 7,555 762 1,209 4,385 54,407 75,991 1,581 4,420 3,172 2,015 1,042 4,509 2,773 95,503 456 150,366 2,716 3,859 23,703 534 1,873 4,489 37,174 19,316 15,882 1,313 8,590 2,285 47,386 165 84,725 2,455 4,005 (284) 60,763 (581) (2,020) 1,303 63,186 65,641 150,366 ASSETS Current assets Cash and cash equivalents ......................... Financial assets held for trading .................. Financial assets available for sale ................. Trade and other receivables ........................ Inventories ............................................ Current tax assets .................................... Other current tax assets............................. Other current assets ................................. Non-current assets Property, plant and equipment.................... Inventory – compulsory stock..................... Intangible assets...................................... Equity-accounted investments .................... Other investments.................................... Other financial assets ............................... Deferred tax assets................................... Other non-current assets ........................... (8) (9) (10) (11) (12) (13) (14) (15) (34) (16) (17) (18) (20) (20) (21) (22) (23) (34) 5,209 5,028 282 21,640 4,579 360 630 3,642 41,370 68,005 909 3,034 2,853 660 1,026 3,853 1,758 82,098 Discontinued operations and assets held for sale ...................................................... TOTAL ASSETS .................................... LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term debt ...................................... Current portion of long-term debt ............... Trade and other payables........................... Income tax payable .................................. Other tax payable .................................... Other current liabilities ............................. Non-current liabilities Long-term debt....................................... Provisions for contingencies ....................... Provisions for employee benefits.................. Deferred tax liabilities .............................. Other non-current liabilities ....................... Discontinued operations and liabilities directly associated with assets held for sale ................ TOTAL LIABILITIES ............................. SHAREHOLDERS’ EQUITY ................... Non-controlling interest ............................. Eni shareholders’ equity ............................. Share capital .......................................... Reserve related to cash flow hedging............. derivatives net of tax effect ........................ Other reserves......................................... Treasury shares ....................................... Interim dividend ..................................... Net profit (loss) ...................................... Total Eni shareholders’ equity...................... TOTAL SHAREHOLDERS’ EQUITY ........ TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY ................... (35) 15,533 139,001 (24) (29) (25) (26) (27) (28) (34) (29) (30) (31) (32) (33) (34) (35) (36) 5,720 2,676 14,942 431 1,454 4,712 29,935 19,397 15,375 1,123 7,425 1,852 45,172 6,485 81,592 1,916 4,005 (474) 62,761 (581) (1,440) (8,778) 55,493 57,409 1,985 50 396 10 308 208 1,544 96 23 207 1,100 57 1,349 13 191 2,289 88 23 5,674 6,166 238 17,593 4,637 383 689 2,591 37,971 70,793 1,184 3,269 4,040 276 1,860 3,790 1,348 86,560 14 124,545 3,396 3,279 16,703 426 1,293 2,599 27,696 20,564 13,896 868 6,667 1,768 43,763 71,459 49 4,005 189 52,329 (581) (1,441) (1,464) 53,037 53,086 139,001 124,545 (a) Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles. F-3 CONSOLIDATED PROFIT AND LOSS ACCOUNT (euro million except as otherwise stated) REVENUES ................................................. Net sales from operations ................................. Other income and revenues ............................... OPERATING EXPENSES............................... Purchases, services and other ............................ Payroll and related costs .................................. OTHER OPERATING (EXPENSE) INCOME .... Depreciation and amortization .......................... Net Impairments/reversal ................................. Write-off of tangible and intangible assets ............ OPERATING PROFIT (LOSS)......................... FINANCE INCOME (EXPENSE) ..................... Finance income ............................................. Finance expense ............................................ Net Finance income from financial assets held for trading ........................................................ Derivatives financial instruments ........................ INCOME (EXPENSE) FROM INVESTMENTS... Share of profit (loss) from equity-accounted investments .................................................. Other gain (loss) from investments ...................... PROFIT BEFORE INCOME TAXES ................ Income taxes ................................................. Net profit (loss) for the year - Continuing operations .................................... Net profit (loss) for the year - Discontinued operations .................................. Net profit (loss) for the year ............................... Attributable to Eni – continuing operations ................................... – discontinued operations ................................. Attributable to non-controlling interest .................. - continuing operations .................................... - discontinued operations ................................. Earnings per share attributable to Eni (€ per share) .. Basic .......................................................... Diluted ........................................................ Earnings per share attributable to Eni - Continuing operations (€ per share) .................... Basic .......................................................... Diluted ........................................................ Note (39) (40) (40) (40) (40) (40) (41) (42) (43) (35) (35) (36) (35) (44) (44) 2014(a) 2015(a) 2016 Total amount of which with related parties Total amount of which with related parties Total amount of which with related parties 98,218 1,079 99,297 77,404 2,929 145 7,676 1,270 1,198 8,965 5,701 (7,057) 24 165 (1,167) 110 366 476 8,274 (6,466) 1,808 (949) 859 1,720 (417) 1,303 88 (532) (444) 0.36 0.36 0.48 0.48 1,497 69 7,143 60 208 1,238 74 8,212 24 247 1,342 69 6,882 55 96 72,286 1,252 73,538 56,848 3,119 (485) 8,940 6,534 688 (3,076) 55,762 931 56,693 44,124 2,994 16 7,559 (475) 350 2,157 46 (41) 8,635 (10,104) 83 (50) 5,850 (6,232) 157 (145) 867 27 3 160 (1,306) (471) 576 105 (4,277) (3,122) (7,399) (1,974) (9,373) (7,952) (826) (8,778) 553 (1,148) (595) (2.44) (2.44) (2.21) (2.21) 142 (21) (482) (885) (326) (54) (380) 892 (1,936) (1,044) (413) (1,457) (1,051) (413) (1,464) 7 7 (0.41) (0.41) (0.29) (0.29) (a) Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles. F-4 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (euro million) Net profit ........................................................ Other items of comprehensive income Items that are not reclassified to profit in later periods Remeasurements of defined benefit plans ........... Share of other comprehensive income on equity accounted entities in relation to remeasurements of defined benefit plans .................................... Tax effect related to other comprehensive income not to be reclassified to profit or loss in subsequent periods .......................................... Items that may be reclassified to profit in later periods Currency translation differences ........................ Change in the fair value of available-for-sale investments ..................................................... Change in the fair value of other available-for-sale financial instruments ............... Change in the fair value of cash flow hedging derivatives ...................................................... Share of other comprehensive income on equity-accounted entities .................................. Tax effect related to other comprehensive income to be reclassified to profit or loss in subsequent periods ........................................................... Total other items of comprehensive income ........... Total comprehensive income ............................... Attributable to Eni - continuing operations .................................... - discontinued operations .................................. Attributable to non-controlling interest - continuing operations .................................... - discontinued operations .................................. Note 2014(a) 859 2015(a) (9,373) 2016 (1,457) (36) (36) (36) (36) (36) (36) (36) (36) (36) (35) (35) (82) 36 16 3 22 (57) (21) 15 (35) (19) 5,427 4,837 1,198 (77) 7 (4) (167) (256) 4 (9) 30 5,224 5,167 6,026 6,817 (390) 6,427 91 (492) (401) 66 4,634 4,649 (4,724) (3,416) (779) (4,195) 554 (1,083) (529) (4) 883 32 (220) 1,889 1,870 413 819 (413) 406 7 7 (a) Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles. F-5 Balance at December 31, 2013 . . . . . . . . . . . . . . Changes in accounting principles (SEM) . . . . . . Balance at January 1, 2014 . . . . . . . . . . . . . . . . . Net profit (loss) for the year . . . . . . . . . . . . . . . . Other items of comprehensive income Items that are not reclassified to profit in later periods Remeasurements of defined benefit plans net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Share of “Other comprehensive income” on equity-accounted entities in relation to remeasurements of defined benefit plans net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Items that may be reclassified to profit in later periods Currency translation differences . . . . . . . . . . . . Change and reversal of the fair value of investments net of tax effect Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change and reversal the fair value of cash flow hedge derivatives net of tax effect . . . . . . . . . . . Share of “Other comprehensive income” on equity-accounted entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total comprehensive income of the year. . . . . . . . Transactions with shareholders Dividend distribution of Eni SpA (€0.55 per share in settlement of 2013 interim dividend of €0.55 per share) . . . . . . . . . . . . . . . . . . . . . . . . . Interim dividend distribution of Eni SpA (€0.56 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . per share) Dividend distribution of other companies . . . . . Allocation of 2013 net profit . . . . . . . . . . . . . . . Acquisition of treasury shares . . . . . . . . . . . . . . Payments and reimbursements by/to minority shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . Other changes in shareholders’ equity Elimination of intercompany profit between companies with different Group interest . . . . . . Stock options expired . . . . . . . . . . . . . . . . . . . . Other changes . . . . . . . . . . . . . . . . . . . . . . . . . . CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (euro million) Eni shareholders’ equity Reserve related to the fair value of cash flow hedging derivatives net of the tax effect Reserve related to the fair value of available- for-sale financial instruments net of the tax effect Share capital Legal reserve of Eni SpA Reserve for treasury shares Note Reserve for defined benefit plans net of the tax effect Cumulative currency translation differences Other reserves Treasury shares Retained earnings Interim dividend 4,005 959 6,201 (154) 4,005 959 6,201 (154) 81 81 (72) (72) 296 296 (698) (201) (698) (201) 44,626 (1,993) 3,001 47,627 (1,993) Other comprehensive income (loss) related to discontinued operations Net profit (loss) for the year 5,160 5,160 1,303 Non- controlling interest Total shareholders’ equity 2,839 3 2,842 (444) 61,049 3,004 64,053 859 Total 58,210 3,001 61,211 1,303 (51) (9) (60) 2 (49) 1 (8) 3 (57) (51) 2 (49) (1) 5,137 232 5,368 59 5,427 (76) 6 (70) (70) (130) (130) (130) (1) (50) 5 5 5 5,137 5,137 232 232 1,303 (76) 6 (76) 6 (130) (7) (137) 5 5,173 6,427 (1) 51 (401) 4 5,224 6,026 1,993 (3,979) (2,020) 1,181 (1,181) (380) (1,986) (2,020) (380) (380) 1,181 (27) (5,160) (4,386) (62) (7) 97 28 4,439 (581) 49,068 (2,020) 1,303 (8,778) (62) (7) 3 (66) 63,186 (8,778) (1,986) (2,020) (49) (380) 1 (4,434) (7) 3 (4) 65,641 (9,373) (49) 1 (48) 62 62 2,455 (595) 14 14 1 1 15 15 (8) (8) 4,722 54 4,775 62 4,837 (9) (9) (9) (32) 4,690 4,690 (3) (3) (194) 3 (191) (9) (9) 54 54 (8,778) 28 28 20 4,569 (4,195) 65 (529) 4,634 (4,724) 2,020 (4,037) (1,440) (2,017) (1,440) (2,734) 2,734 (2,734) 580 (1,303) (3,457) (2,017) (1,440) (21) 1 (3,477) (21) 1 (20) (28) (7) (28) 28 (7) (10) (17) 4,005 959 6,201 (284) 11 (122) (94) (94) 207 14 8 22 (1) (1) 21 (3) (3) (3) (194) 4 (190) (190) (36) Balance at December 31, 2014 . . . . . . . . . . . . . . Net profit (loss) for the year . . . . . . . . . . . . . . . . Other items of comprehensive income Items that are not reclassified to profit in later periods Remeasurements of defined benefit plans net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reclassification of “Other comprehensive loss” related to discontinued operations . . . . . . . . . . . (35) (36) (36) (36) Items that may be reclassified to profit in later periods Currency translation differences . . . . . . . . . . . . Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change and reversal the fair value of cash flow hedge derivatives net of tax effect . . . . . . . . . . . Share of “Other comprehensive income” on equity-accounted entities . . . . . . . . . . . . . . . . . . Reclassification of “Other comprehensive income” related to discontinued operations . . . . (35) (36) (36) (36) (36) Total comprehensive income of the year. . . . . . . . Transactions with shareholders Dividend distribution of Eni SpA (€0.56 per share in settlement of 2014 interim dividend of €0.56 per share) . . . . . . . . . . . . . . . . . . . . . . . . . Interim dividend distribution of Eni SpA (€0.40 per share) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividend distribution of other companies . . . . . Allocation of 2014 net loss. . . . . . . . . . . . . . . . . Payments and reimbursements by/to minority shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . (36) (36) (36) Other changes in shareholders’ equity Elimination of intercompany profit between companies with different Group interest . . . . . . Exclusion from the scope of consolidation of non-significant companies and changes in non-controlling interests . . . . . . . . . . . . . . . . . . Reclassification of the reserve for treasury shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other changes . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at December 31, 2015 . . . . . . . . . . . . . . (36) 4,005 959 (5,620) (5,620) 581 (474) 8 (101) (18) (18) 180 9,129 (581) 5,620 12 5,597 51,985 (1,440) (8,778) 20 (6) (41) 55,493 (8) 10 1,916 (14) (31) 57,409 F-6 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued) (euro million) Eni shareholders’ equity Reserve related to the fair value of cash flow hedging derivatives net of the tax effect Reserve related to the fair value of available- for-sale financial instruments net of the tax effect Share capital Legal reserve of Eni SpA Reserve for treasury shares Note Reserve for defined benefit plans net of the tax effect Cumulative currency translation differences Other reserves Treasury shares Retained earnings Interim dividend (36) 4,005 959 581 (474) 8 (101) 180 9,129 (581) 51,985 (1,440) Balance at December 31, 2015 . . . . . . . . . . . . . . Net profit (loss) for the year . . . . . . . . . . . . . . . . Other items of comprehensive income Items that are not reclassified to profit in later periods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Remeasurements of defined benefit plans net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Items that may be reclassified to profit in later periods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Currency translation differences . . . . . . . . . . . . Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change and reversal the fair value of cash flow hedge derivatives net of tax effect . . . . . . . . . . . Share of “Other comprehensive income” on equity-accounted entities . . . . . . . . . . . . . . . . . . Total comprehensive income of the year . . . . . . . Transactions with shareholders Dividend distribution of Eni SpA (€0.40 per share in settlement of 2015 interim dividend of €0.40 per share) . . . . . . . . . . . . . . . . . . . . . . . . . Interim dividend distribution of Eni SpA (€0.40 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . per share) Dividend distribution of other companies . . . . . Allocation of 2015 net loss. . . . . . . . . . . . . . . . . Other changes in shareholders’ equity Exclusion from the scope of consolidation of Saipem group following the sale of the control Reclassification to profit and loss account of amounts previously recognized in other comprehensive income related to Saipem . . . . . Other changes . . . . . . . . . . . . . . . . . . . . . . . . . . . (36) (36) (36) (36) (36) (36) (36) (35) Other comprehensive income (loss) related to discontinued operations Non- controlling interest Total shareholders’ equity Total 20 55,493 (1,464) 1,916 7 57,409 (1,457) Net profit (loss) for the year (8,778) (1,464) (19) (19) (19) (19) (19) (19) 8 1,190 1,198 1,198 (4) (4) (4) 663 663 663 8 (11) 32 32 32 1,190 1,190 (4) 663 32 1,889 406 (1,440) (1,441) (2,881) (4) 663 32 1,889 413 (1,440) (1,441) (4) (2,885) 7 (4) (4) (1,464) (1,028) 1,440 (1,852) (1,441) (10,630) (11,658) 10,630 8,778 (1) (8) 48 40 10,319 (581) 40,367 (1,441) (1,464) (1) (1) 211 (1,872) (1,872) (20) (20) (28) 47 19 53,037 2 (1,870) 49 (28) 49 (1,851) 53,086 Balance at December 31, 2016 . . . . . . . . . . . . . . (36) 4,005 959 581 189 4 (112) F-7 CONSOLIDATED STATEMENT OF CASH FLOWS (euro million) Net profit (loss) of the year – Continuing operations .............. Adjustments to reconcile net profit to net cash provided by operating activities Depreciation and amortization ............................................. Net Impairments/reversal .................................................... Write-off of tangible and intangible assets ............................. Share of (profit) loss of equity-accounted investments ............ Gain on disposal of assets, net ............................................. Dividend income ................................................................ Interest income .................................................................. Interest expense .................................................................. Income taxes ...................................................................... Other changes .................................................................... Changes in working capital: - inventories ........................................................................ - trade receivables ................................................................ - trade payables ................................................................... - provisions for contingencies ................................................. - other assets and liabilities ................................................... Cash flow from changes in working capital ............................ Net change in the provisions for employee benefits ................. Dividends received .............................................................. Interest received ................................................................. Interest paid ...................................................................... Income taxes paid, net of tax receivables received ................... Net cash provided by operating activities – Continuing operations........................................................................... Net cash provided by operating activities – Discontinued operations........................................................................... Net cash provided by operating activities.................................. - of which with related parties ................................................ Investing activities: - tangible assets ................................................................... - intangible assets................................................................. - consolidated subsidiaries and businesses net of cash and cash equivalent acquired............................................................... - investments ....................................................................... - securities .......................................................................... - financing receivables ........................................................... - change in payables in relation to investing activities and capitalized depreciation......................................................... Cash flow from investing activities ........................................ Disposals: - tangible assets ................................................................... - intangible assets................................................................. - consolidated subsidiaries and businesses net of cash and cash equivalent disposed of ........................................................... - investments ....................................................................... - securities .......................................................................... - financing receivables ........................................................... - change in receivables in relation to disposals ........................... Cash flow from disposals ..................................................... Net cash used in investing activities ......................................... - of which with related parties ................................................ Note 2014(a) 1,808 2015(a) (7,399) 2016 (1,044) (40) (40) (40) (42) (42) (43) 7,676 1,270 1,198 (110) (224) (385) (162) 681 6,466 852 1,620 2,051 (1,669) (234) 431 2,199 12 603 107 (851) (6,671) 8,940 6,534 688 471 (577) (402) (164) 659 3,122 586 1,638 4,944 (2,342) 43 498 4,781 (3) 545 81 (692) (4,295) 7,559 (475) 350 326 (48) (143) (209) 645 1,936 (9) (273) 1,286 1,495 (1,043) 647 2,112 22 212 160 (780) (2,941) 14,469 12,875 7,673 (35) 273 14,742 (47) (3,203) (1,226) 11,649 (3,966) (16) (11,646) (226) (18) (11,177) (125) 7,673 (3,749) (9,067) (113) (37) (20) (36) (372) (77) (1,289) (228) (201) (1,103) (1,164) (1,336) (1,208) 669 (12,977) (1,058) (13,892) (8) (12,896) 104 1 427 32 (37) 3,579 57 506 155 4,402 (8,575) (47) (1,458) 73 1,726 18 533 160 2,969 (10,923) (1,583) 19 (362) 508 20 8,063 205 8,453 (4,443) 3,752 (a) Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles. F-8 CONSOLIDATED STATEMENT OF CASH FLOWS (continued) (euro million) Increase in long-term financial debt ................... Repayments of long-term financial debt ............. Increase (decrease) in short-term financial debt ... Net capital contributions by non-controlling interest ........................................................... Dividends paid to Eni’s shareholders .................. Dividends paid to non-controlling interest .......... Acquisition of treasury shares ........................... Net cash used in financing activities ..................... - of which with related parties ............................. Effect of change in consolidation (inclusion/ exclusion of significant/insignificant subsidiaries) Effect of cash and cash equivalents pertaining to discontinued operations ................................... Effect of exchange rate changes on cash and cash equivalents and other changes ........................... Net cash flow of the year.................................... Cash and cash equivalents - beginning of the year (excluding discontinued operations)....................................................... Cash and cash equivalents - end of the year (excluding discontinued operations)....................................................... Note (29) (29) (24) (47) (37) (8) (8) 2014 (a) 1,916 (2,751) 207 (628) 1 (4,006) (49) (380) (5,062) (99) 2 76 1,183 2015 (a) 3,376 (4,466) 3,216 2,126 1 (3,457) (21) (1,351) 13 (13) (889) 122 (1,405) 2016 4,202 (2,323) (2,645) (766) (2,881) (4) (3,651) (192) (5) 889 2 465 5,431 6,614 5,209 6,614 5,209 5,674 (a) Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles. F-9 Notes on Consolidated Financial Statements 1 Basis of preparation The Consolidated Financial Statements of the Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS)1 as issued by the International Accounting Standards Board (IASB). Oil and natural gas exploration and production activity is accounted for in accordance with internationally accepted accounting standards taking into account the requirements in IFRSs that apply. In particular, starting from January 1, 2016, Eni has adopted, on a voluntary basis, the so-called Successful Efforts Method (hereinafter also SEM) to recognize and measure costs related to exploration activities, in order to improve the comparability of Eni’s results with those of the competitors, as well as to ensure financial reporting that is proper, reliable and consistent with the decision-making processes related to the evaluation of the exploration and production activities’ results. The recognition and measurement criteria for the oil&gas exploration and production activities are indicated in the accounting policy for “Oil and natural gas exploration, appraisal, development and production expenditure”; the effects arising from the adoption of SEM are indicated in note 5 “Changes in accounting policies”. The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value as described in the note 3 “Significant accounting policies”. The 2016 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on March 17, 2017, were audited by the external auditor Ernst & Young SpA. The external auditor of Eni SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other external auditors, Ernst & Young SpA takes the responsibility of their work. Amounts in the financial statements and in the notes are expressed in millions of euros (euro million). 2 Principles of consolidation Subsidiaries The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its Italian and foreign subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee, i.e. the activities that significantly affect the investee’s returns. For entities acting as sole-operator in the management of oil&gas contracts on behalf of companies participating in a joint project, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized 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 significant2 effects on the Consolidated Financial Statements. (1) (2) IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations issued by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC). According to the requirements of the Conceptual Framework for IFRS, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”. F-10 Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases. 100% of assets, liabilities, income and expenses of consolidated subsidiaries are combined with those of the parent in the Consolidated Financial Statements; the net book value of these subsidiaries is eliminated against the corresponding portion of the shareholders’ equity. Equity and net profit attributable to non-controlling interests are included in specific line items of equity and profit and loss account. When the proportion of the equity held by non-controlling interests changes, any difference between the consideration paid/received and the amount by which the non-controlling interests are adjusted is attributed to the Group 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/loss calculated as the difference between the consideration received and the corresponding transferred portion of equity; (ii) any gain or loss recognized as a result of the re-measurement of any investment retained in the former subsidiary to its fair value; and (iii) any amount related to the former subsidiary previously recognized in other comprehensive income which can be reclassified subsequently to the profit and loss account3. Any investment retained in the former subsidiary is recognized at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria. Interests in joint arrangements A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”. A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement. Judgment is required in assessing whether a joint arrangement creates enforceable rights and obligations; this assessment is made considering the design and purpose of the joint arrangement, the terms of the contractual arrangements, as well as any other facts and circumstances that are relevant for this assessment. In the Consolidated Financial Statements the Eni’s share of the assets/liabilities and revenues/ expenses of joint operations is recognized upon rights and obligations to the arrangements. After the initial recognition, the assets/liabilities and revenues/expenses of the joint operations are measured in accordance with the measurement criteria applicable to each case. Immaterial joint operations are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of any impairment losses. Interests 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”. Consolidated companies’ financial statements are audited by external auditors who audit also the information required for the preparation of the Consolidated Financial Statements. (3) Conversely, any amount related to the former subsidiary previously recognized in other comprehensive income, which cannot be reclassified subsequently to the profit and loss account, are reclassified within retained earnings. F-11 The equity method of accounting Investments in immaterial subsidiaries, joint ventures and associates are accounted for using the equity method4. Under the equity method, investments are initially recognized at cost, allocating, similarly to business combinations procedures, the purchase price of the investment to the investee’s assets/liabilities; if this allocation is provisionally recognized 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; and (ii) the investor’s share of the investee’s other comprehensive income. Changes in the net assets of an equity-accounted investee, not arising from the investee’s profit or loss or other comprehensive income, are recognized in the investor’s profit and loss account, as they basically represent a gain or loss from a disposal of an interest in the investee’s equity. Distributions received from an equity-accounted investee reduce the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). When there is objective evidence of impairment (see also the accounting policy for “Current financial assets”), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the accounting policy for “Property, plant and equipment”. Immaterial subsidiaries, joint ventures and associates are accounted for at cost, net of any impairment losses, if this does not result in a misrepresentation of the Group financial position and performance. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account within “Other gain (loss) from investments”. The reversal cannot exceed the previously recognized 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/loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognized as a result of the re-measurement of any investment retained in the former joint venture/associate to its fair value5; and (iii) any amount related to the former joint venture/associate previously recognized in other comprehensive income which can be reclassified subsequently to profit and loss account6. Any investment retained in the former joint venture/associate is recognized at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria. The investor’s share of losses of an equity-accounted investee, that exceeds the carrying amount of the investment, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to fund its losses. Business combinations Business combinations are recognized by applying the acquisition method. The consideration the transferred in a business combination is measured at the acquisition date and is the sum of acquisition-date fair values of the assets transferred, the liabilities incurred, as well as any equity instruments issued by the acquirer. Acquisition-related costs are accounted for as expenses when they are incurred. At the acquisition date, the acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values7, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed is recognized as goodwill; a gain from a bargain purchase is recognized in the profit and loss account. (4) (5) (6) (7) In the case of step acquisition of significant influence (or joint control), the investment is recognized, 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. If the retained investment continues to be accounted for using the equity method, no remeasurement to fair value is recognized in the profit and loss account. Conversely, any amount related to the former joint venture/associate previously recognized in other comprehensive income, which cannot be reclassified subsequently to the profit and loss account, are reclassified in another item of equity. Fair value measurement principles are described below in the accounting policy for “Fair value measurements”. F-12 Any non-controlling interest is measured as the proportionate share in the recognized amounts of the acquiree’s identifiable net assets at the acquisition date (partial goodwill method); as an alternative, it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, including also the goodwill attributable to non-controlling interests (full goodwill method). In the last case, non-controlling interests are measured at their fair value, which therefore includes the goodwill attributable to them8. The choice of measurement basis of 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 fair value of previously held equity interests in the acquiree and the consideration transferred for the acquisition of control; the previously held equity interests are re-measured at their acquisition-date fair value and the resulting gain or loss, if any, is recognized in the profit and loss account. Furthermore, on obtaining control, any amount of the acquiree previously recognized in other comprehensive income is charged to the profit and loss account, or in another item of equity when the amount cannot be reclassified to the profit and loss account. If control is obtained over a business formerly classified as joint operation, the previously held interest in its assets and liabilities is not re-measured to its fair value. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date. The acquisition of interests in a joint operation in which the activity constitutes a business is recognized applying the relevant principles for business combinations. Intragroup transactions All balances and transactions between consolidated companies, including unrealized profits arising from such transactions, have been eliminated. Unrealized profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity. In both cases, unrealized losses are not eliminated when they provide evidence of an impairment loss of the asset transferred. Foreign currency translation The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency, are translated into euro using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows (source: WMR/IPSE). The cumulative amount of the resulting translation differences is presented in the separate component of the Group shareholders’ equity “Cumulative currency translation differences”9. Cumulative exchange differences are reclassified to the profit and loss account when the entity disposes the entire interest in a foreign operation or when the partial disposal involves the loss of control, joint control or significant influence of a 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 that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account. (8) The choice between partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account. (9) When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognized as part of “Non-controlling interest”. F-13 The financial statements of foreign operations which are translated into euro are denominated in the foreign operations’ functional currencies which generally is the U.S. dollar. The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below: (currency amount for 1 €) Annual average exchange rate 2014 Exchange rate at December 31, 2014 Annual average exchange rate 2015 Exchange rate at December 31, 2015 Annual average exchange rate 2016 Exchange rate at December 31, 2016 U.S. Dollar ............................... Pound Sterling .......................... Norwegian Krone ...................... Australian Dollar ...................... 1.33 0.81 8.35 1.47 1.21 0.78 9.04 1.48 1.11 0.73 8.95 1.48 1.09 0.73 9.60 1.49 1.11 0.82 9.29 1.49 1.05 0.86 9.09 1.46 3 Significant accounting policies The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below. Oil and natural gas exploration, appraisal, development and production expenditure Acquisition of exploration rights Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalized within the line item “Intangible assets” as “exploration rights — unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortized, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that can show the existence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognized in the profit and loss account as write-off. Lower value exploration rights are pooled and amortized on a straight-line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. When the reclassification is recognized, as well as whether there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration rights are amortized according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortization”). Acquisition of mineral interests Costs incurred for the acquisition of mineral interests are capitalized in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows. Acquired exploration potential is measured under the criteria indicated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are amortized on a UOP basis (see the accounting policy for “UOP depreciation, depletion and amortization”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortized 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 recognized as an expense as incurred. F-14 Costs directly associated with an exploration well are initially recognized within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalized in the following 12-month period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalized if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project; on the contrary, the capitalized costs are recognized in the profit and loss account as write-off. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognized as unproved is reclassified to proved exploration and appraisal costs, within tangible assets in progress. When the reclassification is recognized, as well as whether there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortization”). Development expenditure Development expenditure, including the costs related to unsuccessful and damaged development wells, are capitalized as “Tangible asset in progress — proved”. Development expenditures are costs incurred to obtain access to proved reserves and provide facilities to extract, gather and store the oil&gas. They are amortized, from the commencement of production, generally on a UOP basis (see the accounting policy for “UOP depreciation, depletion and amortization”). 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 amortization Proved oil&gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of oil&gas reserves, by applying, to the depreciable amounts at the end of each quarter a rate representing the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil&gas reserves. Proved exploration rights and acquired proved mineral interests are amortized over proved reserves; proved exploration and appraisal costs and development expenditure are depreciated over proved developed reserves. Production costs Production costs are those costs incurred to operate and maintain wells and field equipment and are recognized 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 production entitlements against both Cost Oil and Profit Oil are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above-mentioned accounting policies. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. Decommissioning and restoration liabilities Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalized, consistently with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis. F-15 Property, plant and equipment Property, plant and equipment, including investment properties, are recognized using the cost model and stated at their purchase or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management. When a substantial period of time is required to make the asset ready for use, the purchase price or construction cost includes the borrowing costs incurred that could have otherwise been avoided if the expenditure had not been made. In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs (a corresponding amount is recognized as part of a specific provision). Changes in provisions due to the passage of time and changes in discount rates are recognized as described in the accounting policy for “Provisions, contingent assets and liabilities”10. Property, plant and equipment are not revalued for financial reporting purposes. Assets under finance lease, or under arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset, are recognized, at the commencement of the lease term, at fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt to the lessor is recognized. These assets are depreciated as described below. If there is no reasonable certainty that the lessee will obtain ownership by the end of the lease term, the assets are depreciated over the shorter of the lease term and the useful life of the asset. Expenditures on upgrading, revamping and reconversion are recognized as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary to obtain future economic benefits from other assets. Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. Property, plant and equipment are depreciated on a systematic basis, using a straight-line method over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company. When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see the accounting policy for “Assets held for sale and discontinued operations” below). A change in the depreciation method, deriving from changes in the asset’s useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, shall be recognized prospectively. Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession or the asset’s useful life. Replacement costs of identifiable parts in complex assets are capitalized and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Leasehold improvement costs are depreciated over the useful life of the improvements or, if lower, over the residual length of the lease, considering any renewal period if renewal depends entirely on the lessee and is virtually certain. Expenditures for ordinary maintenance and repairs are recognized as an expense as incurred. The carrying amount of property, plant and equipment is reviewed for impairment whenever there is any indication that the carrying amounts of those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the 10 These liabilities relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with tangible assets of Refining & Marketing, Chemical and Gas & Power segments/businesses are recognized when the amount of the liability can be reliably estimated, considering that undetermined settlement dates for assets dismantlement and restoration do not allow a discounting estimate of the obligation. With regard to this, Eni performs periodic reviews of its tangible assets of Refining & Marketing, Chemical and Gas & Power segments/ businesses for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability. F-16 asset’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal. Expected cash flows are determined on the basis of reasonable and supportable assumptions that represent management’s best estimate of the range of economic conditions that will exist over the remaining useful life of the asset, giving greater weight to external evidence. With reference to commodity prices, management assumes the price scenario adopted for economic and financial projections and for whole life appraisal for capital expenditures. In particular, for the cash flows associated to oil, natural gas and petroleum products prices (and prices derived from them), the price scenario is approved by the Board of Directors and is based on management’s long-term planning assumptions and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace. When commodity prices fluctuate quite considerably, management considers the most updated variables available. Discounting is carried out at a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the expected future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the asset. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segments where the asset operates. In particular, for the assets belonging to the Gas & Power segment and the Chemical business, taking into account their different risk compared with Eni as a whole, specific WACC rates have been defined on the basis of a sample of companies operating in the same segment/business, adjusted to take into consideration the risk premium of the specific country of the activity. For the other segments, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called “cash-generating unit”. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account. The reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. The carrying amount of property, plant and equipment is derecognized on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognized in the profit and loss account. Intangible assets Intangible assets are identifiable non-monetary assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill acquired in business combinations. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or other legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or together with other assets. An entity controls an intangible asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits. Intangible assets are initially recognized at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes. Intangible assets with finite useful lives are amortized on a systematic basis over their useful life estimated as the period over which the assets will be available for use by the Company; the amount to be amortized and the recoverability of the carrying amount are determined in accordance with the criteria described in the accounting policy for “Property, plant and equipment”. Goodwill and intangible assets with indefinite useful lives are not amortized. Their carrying amounts are tested for impairment at least annually and whenever there is any indication of impairment. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management F-17 purposes. When the carrying amount of the cash-generating unit, including goodwill allocated thereto, calculated considering any impairment loss of the non-current assets belonging to the cash-generating unit, exceeds its recoverable amount11, the excess is recognized as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the unit, up to the recoverable amount of assets with finite useful lives. An impairment loss recognized for goodwill is not reversed in a subsequent period12. Directly attributable customer acquisition costs are capitalized when the following conditions are met: (i) the capitalized costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenues from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty. Costs of technological development activities are capitalized when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits. The carrying amount of intangible assets is derecognized on disposal or when no future economic benefits are expected from its use or disposal; any arising gain or loss is recognized in the profit and loss account. Grants related to assets Government grants related to assets are recognized by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received. Inventories Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realizable value. Net realizable value is the net amount expected to be realized from the sale of inventories in the ordinary course of business, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual sale 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. When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations, are measured using the pricing formulas contractually defined. They are recognized under “Other assets” as “Deferred costs” as a contra to “Other payables” or, after the settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn — the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas, within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, determined adopting the same criteria described for inventories. (11) For the definition of recoverable amount see the accounting policy for “Property, plant and equipment”. (12) Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized. F-18 Financial instruments Current financial assets Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due within 90 days, readily convertible to known amount of cash and subject to an insignificant risk of changes in value. Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets and held-to-maturity financial assets. Held-for-trading financial assets and available-for-sale financial assets are measured at fair value with gains or losses recognized in the line item of the profit and loss account “Finance income (expense)” and in the equity reserve13 related to other comprehensive income, respectively. Changes in fair value of available-for-sale financial assets recognized in equity are charged to the profit and loss account when the assets are derecognized or impaired. The objective evidence that an impairment loss has occurred is verified inter alia, significant breaches of contracts, serious financial difficulties or the risk of considering, bankruptcy and other financial reorganization of the counterparty; impairment losses of available-for-sale financial assets are included in the carrying amount. Interests and dividends on financial assets measured at fair value are accounted for on an accrual basis in “Finance income (expense)”14 and “Other gain (loss) from investments”, respectively. When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date. Receivables are measured at amortized cost (see below the accounting policy for “Non-current financial assets”). Non-current financial assets Investments Investments in equity instruments15 are measured at fair value, with gains or losses recognized in the equity reserve related to other comprehensive income; the amounts recognized in equity are reclassified to the profit and loss account when the investment is impaired or derecognized. When investments do not have a quoted price in an active market and their fair value cannot be reliably measured, they are measured at cost, net of any impairment losses; impairment losses shall not be reversed16. Receivables and held-to-maturity financial assets Receivables and held-to-maturity financial assets are accounted for at cost, that is the fair value of the initial consideration plus transaction costs (e.g. fees, transaction costs, etc.). The initial carrying amount is then adjusted to take into account principal repayments, plus or minus the cumulative amortization of any difference between the initial amount and the maturity amount and minus any reductions for impairment or uncollectibility. Amortization is carried out on the basis of the effective interest rate represented by the rate that equalizes, at the moment of the initial recognition, the present value of expected cash flows to the initial carrying amount (so-called “amortized cost method”). Receivables for finance leases are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease. (13) Changes in the carrying amount of available-for-sale financial assets relating to changes in foreign exchange rates are recognized in the profit and (14) loss account. Interests accrued on held for trading financial assets impact the total fair value measurement of the instrument and are recognized, within the line item “Finance income (expense)”, in the sub-item “Net finance income on financial assets held for trading”. Conversely, interests accrued on financial assets available-for-sale are recognized, within the line item “Finance income (expense)”, in the sub-item “Finance income”. (15) For investments in joint ventures and associates, see “The equity method of accounting”. (16) Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized. F-19 If there is objective evidence that an impairment loss has been incurred (see also the accounting policy for “Current financial assets”), the impairment loss is measured as the difference between the carrying amount and the present value of the expected cash flows discounted at the effective interest rate computed at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and held-to-maturity financial assets are presented net of the allowance for impairment losses; when the impairment loss is definite, the allowance for impairment losses is reversed for charges, otherwise for excess. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as “Finance income (expense)”. Financial liabilities Financial liabilities, other than derivative financial instruments, are measured at amortized cost (see above the accounting policy for “Non-current financial assets”). Derivative financial instruments Derivative financial instruments, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value. Derivatives are designated as hedging instruments when the relationship between the derivative and the hedged item is formally documented and the hedge is regarded as highly effective and reviewed on an ongoing basis. When derivatives hedge the risk of changes in the fair value of the hedged item (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured. When derivatives hedge the exposure to variability in cash flows of the hedged item (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 changes in the fair value of the derivatives, that are designated as effective hedging instruments, are initially recognized in the equity reserve related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account. The changes in the fair value of derivatives, that are not designated as effective hedging instruments, are recognized in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognized in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognized in the profit and loss account line item “Other operating (expense) income”. Embedded derivatives in hybrid instruments are separated from the host contract and accounted for as a derivative if the hybrid instruments are not measured at fair value with changes in fair value recognized in the profit and loss account and if the economic characteristics and risks of the embedded derivatives are not closely related to those of the host contracts. The entity assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows, occurs. Contracts to buy or sell commodities entered into and continue to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognized 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 in the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realize the asset and settle the liability simultaneously). F-20 Derecognition of financial assets and liabilities Transferred financial assets are derecognized when the contractual rights to receive the cash flows from the financial assets are realized, expired or transferred. Financial liabilities are derecognized when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired. Provisions, contingent assets and liabilities A provision is a liability of uncertain timing or amount at the balance sheet date. Provisions are recognized when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties at the balance sheet date. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognized as “Finance income (expense)”. Where an obligation exists for an item of property, plant and equipment (e.g. site dismantling and restoration), the provision is recognized together with a corresponding amount as part of the related item of property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. A provision for restructuring costs is recognized only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring. Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognized in the same profit and loss account line item where the original provision was charged, or, when the liability regards tangible assets (e.g. site dismantling and restoration), changes in the provision are recognized with a corresponding entry to the assets to which they refer, to the extent of the assets’ carrying amounts; any excess amount is recognized in the profit and loss account. Contingent liabilities are disclosed as follows: (i) possible, but not probable obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not recognized unless the realization of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements; if it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are recognized in the financial statements of the period in which the change occurs. 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. F-21 The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. Net interest includes the return on plan assets and the interests cost to be recognized in the profit and loss account. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognized in “Finance income (expense)”. Re-measurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognized within the statement of comprehensive income. Re-measurements of the net defined benefit liability, recognized in the equity reserve related to other comprehensive income, are not reclassified to the profit and loss account in a subsequent period. Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of re-measurements are taken to profit and loss account in their entirety. Treasury shares Treasury shares are recognized as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognized in equity. Revenues and costs Revenues from the sale of products and the rendering of services are recognized when the significant risks and rewards of ownership have been transferred to the customer or when the transaction can be considered settled and the associated revenue can be reliably measured. In particular, revenues are recognized for the sale of: • • • • crude oil, generally upon shipment; natural gas and electricity, upon delivery to the customer; petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales of petroleum products are generally recognized upon shipment; and chemical products and other products, generally upon shipment. Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer. Revenues from crude oil and natural gas production from properties in which Eni has an interest together with other producers are recognized on the basis of Eni’s net working interest in those properties (entitlement method). Higher/lower production volume withdrawn as compared to Eni’s net working interest volume is recognized at current prices at the balance sheet date. Revenues arising from rendering of services are recognized by reference to the stage of completion at the end of the reporting period, provided that: (i) the amount of revenues can be measured reliably; (ii) it is probable that the economic benefits associated with the transaction will flow to the entity; (iii) the stage of completion of the transaction at the end of the reporting period can be measured reliably; and (iv) the related costs can be measured reliably. When the outcome of the transaction involving the rendering of services cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable. Revenues are measured at the fair value of the consideration received or receivable net of returns, discounts, rebates, bonuses and related taxes. Amounts collected or to be collected on behalf of third parties are not revenues. Award credits, related to customer loyalty programs, are recognized as a separately identifiable component of the sales transaction in which they are granted. Therefore, the consideration allocated to the award credits, measured by reference to their fair value, represents deferred revenues and it is recognized in F-22 the line item “Other liabilities”. The deferred revenues are reversed in the profit and loss account at the redemption or forfeiture of the award credits by customers. When goods or services are exchanged for goods or services that are of a similar nature and value, the exchange is not regarded as a transaction which generates a revenue. Costs are recognized 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, determined on the basis of the market prices, are recognized in relation to the amount of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights are recognized as intangible assets net of any imbalance between the amount of actual emissions and the free allowances. Revenues related to emission quotas are recognized when they are sold and, if applicable, purchased emission rights are considered the first to be sold. Monetary receivables granted to replace the free award emission rights are recognized as a contra to the line item “Other income and revenues”. Operating lease payments are recognized as an expense over the lease term. The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized (see above the accounting policy for “Intangible assets”), are included in the profit and loss account when they are incurred. Grants not related to assets are recognized in the profit and loss account on an accrual basis matching the related costs when incurred. Exchange differences Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realizable value are retranslated using the exchange rate at the date when the value is determined. Dividends Dividends are recognized at the date of the general shareholders’ meeting in which they were declared, except when the sale of shares before the ex-dividend date is certain. Income taxes Current income taxes are determined on the basis of estimated taxable income. The estimated liability is included in “Income taxes payable”. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets and liabilities are recognized 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 have been enacted or substantively enacted for future years. Deferred tax assets are recognized when their recoverability is considered probable; in particular, deferred tax assets are recoverable when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognized to the extent that their recoverability is probable. Income tax assets that are uncertain in the amount to be recovered are recognized in accordance to the probable threshold. Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognized 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 F-23 included in non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognized in the line item “Deferred tax assets”; if negative, in the line item “Deferred tax liabilities”. When the results of transactions are recognized directly in shareholders’ equity, the related current and deferred taxes are also charged to the shareholders’ equity. Assets held for sale and discontinued operations Non-current assets and current and non-current assets included within disposal groups, are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through their continuing use. For this to be the case, the sale must be highly probable and the asset or the disposal group must be available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale. The classification of non-current assets (or disposal groups) as held for sale requires the management to perform subjective judgments based on assumptions deemed reasonable in consideration of the information available at the time. Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized in the balance sheet separately from other assets and liabilities. Immediately before the initial classification of a disposal group as held for sale, the assets and liabilities of the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell and their carrying amount. After the classification as held for sale of an equity-accounted investment, the investment, or the portion of the investment, that meets the criteria to be classified as held for sale, is no longer accounted for using the equity method; therefore, in this case, the carrying amount of the investment in accordance with the equity method represents the carrying amount for the measurement as non-current asset held for sale. Any retained portion of the equity-accounted investment that has not been classified as held for sale is accounted for using the equity method until disposal of the portion that is classified as held for sale takes place. After the disposal takes place, any retained investment is measured in accordance with the measurement criteria indicated in the accounting policy for “Non-current financial assets — Investments”, unless the retained interest continues to be an equity-accounted investment. Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale. Non-current assets and current and non-current assets included within disposal groups, classified as held for sale, are considered a discontinued operation if, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognized on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements. If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortisations, impairment losses and reversals that would have been recognized had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell. If the interruption of a plan of sale concerns a subsidiary, joint operation, joint venture, associate, or a portion of an interest in a joint venture or an associate, financial statements for the period since classification as held for sale are amended. If a discontinued operation is reclassified as held for use, its results previously presented in the separate line item of the profit and loss account are reclassified and included in income from continuing operations for all periods presented. Fair value measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement F-24 date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximize the value of the asset. The fair value of a liability, both financial and non-financial, or of a Company’s own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty’s credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the entity’s own credit risk for a financial liability (Debit Valuation Adjustment, DVA). In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. 4 Financial statements17 Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature18. Assets and liabilities are classified as current when: (i) they are expected to be realized/settled in the entity’s normal operating cycle or within twelve months after the balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be realized/ settled within twelve months after the balance sheet date; on the contrary they are classified as non-current. The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS. The statement of changes in shareholders’ equity includes the total comprehensive income 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 is adjusted for the effects of non-cash transactions. 5 Changes in accounting policies In accordance with IAS 8 “Accounting Policies, Changes in Accounting Estimates and Errors”, the in order to increase the adoption of SEM represents a voluntary change in accounting policies, (17) The financial statements are the same presented in the last Annual Report on Form 20-F, with the exception of: (i) the profit and loss account and the statement of cash flows that include the new line item “Write-off ” which presents the loss from the derecognition of property, plant and equipment or intangible assets. The presentation of this new line item is regarded as relevant by management due to the adoption, on a voluntary basis, of the recognition and measurement criteria for the costs related to the oil and gas activities in accordance with the Successful Efforts Method (SEM), as described in note 5 “Changes in accounting policies”; (ii) the profit and loss account that include the new line item “Net impairment losses (reversals)”, which includes the net balance of impairment losses/reversals of tangible and intangible assets. The presentation of this new line item is regarded as relevant by management in order to avoid that the compensation between depreciations/amortizations and net impairment reversals would provide a misleading representation to users of financial statements. (18) Further information on financial instruments as classified in accordance with IFRS is provided in note 38 - Guarantees, commitments and risks — Other information about financial instruments. F-25 comparability with the companies operating in the same industry and provide a reliable and more relevant financial information. SEM has been applied retrospectively; therefore, comparative amounts have been restated. Under the previous accounting policy: (i) the costs for the acquisition of exploration rights were amortized on a straight-line basis over the exploration period as contractually established; (ii) the costs associated with exploration activities were initially capitalized, in order to reflect their nature as capital expenditure, and fully amortized as incurred. Furthermore, because of the withdrawal of Versalis sale plan, the criteria for its classification as disposal group and discontinued operations are no longer met; therefore the 2014 and 2015 comparative figures have been amended as if Versalis had never been classified as held for sale. The financial statements line items affected by the above-mentioned changes are presented below. (€ million) Selected line items only Non-current assets .............................................................. - of which property, plant and equipment ................................. - of which intagible assets ..................................................... Non-current liabilities ......................................................... Total Shareholders’ Equity ................................................... (€ million) Selected line items only Non-current assets .............................................................. - of which property, plant and equipment ................................. - of which intagible assets ...................................................... Non-current liabilities ......................................................... Total Shareholders’ Equity ................................................... January 1, 2014 Adoption of the SEM 4,085 3,524 860 1,081 3,004 January 1, 2015 Adoption of the SEM 4,159 4,029 775 727 3,432 As restated 89,669 67,287 4,736 45,364 64,053 As restated 95,503 75,991 4,420 47,386 65,641 As reported 85,584 63,763 3,876 44,283 61,049 As reported 91,344 71,962 3,645 46,659 62,209 (€ million) December 31, 2015 Selected line items only As reported Current assets ................................................ Non-current assets .......................................... - of which property, plant and equipment.............. - of which intagible assets .................................. Discontinued operations and assets held for sale . Current liabilities ............................................ Non-current liabilities ..................................... Discontinued operations and liabilities directly associated with assets held for sale .................... Total Shareholders’ Equity ............................... 39,982 77,294 63,795 2,433 17,516 29,565 44,488 7,070 53,669 Restatement of Versalis in continuing operations 1,388 889 323 55 (1,983) 370 215 (585) 294 Adoption of the SEM As restated 3,915 3,887 546 469 3,446 41,370 82,098 68,005 3,034 15,533 29,935 45,172 6,485 57,409 F-26 (€ million) 2014 Selected line items only As reported Revenue ........................................................ Operating expense .......................................... Depreciation, amortization .............................. Net impairment (reversal) ................................ Write-off of tangible and intangible assets ......... Operating profit (loss) ..................................... Finance income and expense ............................ Income (expense) from investments ................... Income taxes .................................................. Net profit – continuing operations .................... Net profit – discontinued operations ................. Net profit ...................................................... Net profit attributable to Eni ........................... - attributable to Eni in continuing operations ..... - attributable to Eni in discontinued operations .. Net cash provided by operating activities ........... Net cash used in investing activities .................. Net cash used in financing activities .................. Net cash flow for the period ............................. 94,226 73,930 9,134 1,013 137 7,585 (1,181) 469 6,681 192 658 850 1,291 101 1,190 15,110 (8,943) (5,062) 1,183 Restatement of Versalis in continuing operations Adoption of the SEM As restated 5,078 3,106 99 96 1 1,419 (3) (191) 1,607 (1,607) 1,607 (1,607) (7) 368 (1,557) 161 1,060 (39) 14 10 (24) 9 9 12 12 (368) 368 99,297 77,404 7,676 1,270 1,198 8,965 (1,167) 476 6,466 1,808 (949) 859 1,303 1,720 (417) 14,742 (8,575) (5,062) 1,183 (€ million) 2015 Selected line items only Revenue ........................................................ Operating expense .......................................... Depreciation, amortization .............................. Net impairment (reversal)................................. Write-off of tangible and intangible assets ......... Operating profit (loss) ..................................... Finance income and expense ............................ Income (expense) from investments ................... Income taxes .................................................. Net profit - continuing operations .................... Net profit - discontinued operations .................. Net profit ...................................................... Net profit attributable to Eni ........................... - attributable to Eni in continuing operations ..... - attributable to Eni in discontinued operations .. Net cash provided by operating activities ........... Net cash used in investing activities .................. Net cash used in financing activities .................. Net cash flow for the period ............................. As reported 68,945 53,958 9,654 4,826 25 (2,781) (1,323) 124 3,147 (7,127) (2,251) (9,378) (8,783) (7,680) (1,103) 11,903 (11,177) (1,351) (1,414) Restatement of Versalis in continuing operations 4,603 2,636 108 998 520 3 (20) 486 17 277 294 294 17 277 9 Adoption of the SEM As restated (10) 254 (822) 710 663 (815) 14 1 (511) (289) (289) (289) (289) (254) 254 73,538 56,848 8,940 6,534 688 (3,076) (1,306) 105 3,122 (7,399) (1,974) (9,373) (8,778) (7,952) (826) 11,649 (10,923) (1,351) (1,405) The amendments to IFRSs effective from January 1, 2016 did not have a significant impact on the financial statements. 6 Significant accounting estimates or judgements The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognized in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and F-27 areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, employee benefits and recognition of environmental liabilities. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. The accounting estimates and judgements relevant for the preparation of the Consolidated Financial Statement are described below. Oil and natural gas activities Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil&gas reserves can be categorized as “proved”, the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgment. The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditure required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such carried costs are reviewed on at least an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery. Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision. Upward or downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion charges and impairment charges. Depreciation and depletion rates of oil&gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation and depletion charge. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion charge. Estimated proved reserves are affected, inter alia, by the trend of reference oil and gas commodity prices and by the specific legal agreement for the oil&gas activity. In addition, estimated proved reserves are used to calculate future cash flows from oil&gas properties, which are used to assess any impairment loss. The larger is the volume of estimated reserves, the lower is the likelihood of asset impairment. Impairment of assets Assets are impaired when there are events or changes in circumstances that indicate that carrying amounts of the assets are not recoverable. Such impairment indicators include changes in the Group’s F-28 business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilization of plants and, for oil&gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for demand and supply conditions on a global or regional scale. Similar remarks are valid for assessing the physical recoverability of assets recognized in the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses, as well as for assessing the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the carrying amount of an asset with its recoverable amount. Recoverable amount of an asset is the higher of an asset’s fair value less costs of disposal and its value in use. The estimate of an asset’s value in use is based on the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reasonably determinable, the cash flows expected to be obtained from the disposal of the asset at the end of its useful life after deducting the costs of disposal. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil&gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent specialized analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows. Goodwill and intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets on an annual basis and whenever there is any indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash-generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash-generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash-generating unit, to which goodwill has been allocated, is less than its carrying amount, goodwill allocated to that cash-generating unit is impaired up to that difference; if the carrying amount of goodwill is lower than the amount of the impairment loss, the other assets of the cash-generating unit are impaired pro-rata on the basis of their carrying amounts for the residual difference, up to the recoverable amount of assets with finite useful lives. Decommissioning and restoration liabilities The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The complexity of these estimates is also due to the accounting that requires the initial recognition of the present value of the decommissioning and restoration liabilities as a part of the cost of property, plant and equipment. Then the carrying amount of decommissioning and restoration liabilities is adjusted to reflect the passage of time and any change in the estimates following the modification of amount and timing of future cash flows and discount rates adopted. The discount rate used to determine the provision is based on complex and subjective managerial judgments. Business combinations Accounting for business combinations requires the allocation of the purchase price to the identifiable assets and liabilities of the acquired business generally at their fair values. Any positive residual difference is F-29 recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date are retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors; the purchase price allocation, that requires, also in consideration of the available information, management to make complex judgments, is also relevant for the application of the equity method. Environmental liabilities is subject As other oil&gas companies, Eni to numerous EU, national, regional and local environmental laws and regulations concerning its oil&gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental provisions are recognized when it becomes probable that a liability will be incurred and the liability can be reliably insurance policies obtained to cover estimated. Management, considering the actions already taken, environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements. Employee benefits Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds). The inflation rates reflect market conditions observed in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved. Differences in the amount of liability (asset), deriving from the the net defined benefit re-measurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Re-measurements are recognized within statement of comprehensive income for defined benefit plans and within the profit and loss account for long-term plans. Other provisions In addition to liabilities related to environmental decommissioning and restoration liabilities and employee benefits, Eni recognizes provisions primarily related to legal and tax proceedings. These provisions are estimated on the basis of managerial judgments related to the amounts to recognize and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate. F-30 Revenues and receivables Revenues from the sale of electricity and gas to retail customers include amount accrued for electricity and gas supplied between the date of the last meter reading and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as they rely on other factors, considered by management, which can impact on them. Therefore accrued revenues derive from complex estimates based on distributed and allocated volumes, communicated by third parties; these revenues may be adjusted, according to the applicable regulations, within the fifth year subsequent the one in which they were accrued. Complex and/or subjective judgements are required in assessing the recoverability of overdue receivables and determining whether an allowance against those receivables is required. Factors considered include, among others, the credit rating of the counterparty (if available), the amount and timing of anticipated future payments, any collateral held as a security and other credit enhancements, as well as any possible actions that can be taken to mitigate the risk of non-payment. 7 IFRSs not yet adopted On May 28, 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” (hereinafter IFRS 15), which sets out the requirements for recognizing and measuring revenues arising from contracts with customers, including construction contracts. In particular, IFRS 15 requires that, to recognize revenue, a company shall apply the following five steps: (i) identify the contract with the customer; (ii) identify the performance obligations (that are promises in a contract to transfer to a customer goods and/or services); (iii) determine the transaction price; (iv) allocate the transaction price to each performance obligation on the basis of the relative standalone selling prices of each good or service promised in the contract; and (v) recognize revenue when a performance obligation is satisfied. Moreover, IFRS 15 includes more disclosure requirements about the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. IFRS 15 shall be applied for annual periods beginning on or after January 1, 2018; IFRS 15 shall be applied retrospectively, by providing for the possibility of recognizing the cumulative effect of initially applying IFRS 15 as an adjustment to the opening balance of equity as January 1, 2018, having regard only to the contracts that are not completed at the date of initial application. Furthermore, on April 12, 2016, the IASB issued the document “Clarifications to IFRS 15 Revenue from Contracts with Customers” (hereinafter clarifications to IFRS 15), which provides clarifications to support implementation of the new standard. The clarifications to IFRS 15 shall be applied for annual periods beginning on or after January 1, 2018. In 2016, the Group started analytical activities aimed to identify potentially critical issues for each operating segment, to assess the potential effects on the financial statements and verify the need to adjust internal control system over financial reporting. At the current stage of the analysis, the following areas may be affected by the new provisions of the standard: (i) accounting for certain types of agreements with partners within oil&gas projects, considering their different nature from customers; (ii) representation on a gross or net basis of certain types of costs closely related to supplying of goods or services; (iii) multiple-element arrangements; (iv) capitalization of the customer acquisition costs principally in the Gas & Power segment; (v) contracts with options to acquire additional goods/services that provide a material right that customers would not receive without entering into the contracts; (vi) contracts with variable consideration; (vii) licenses of intellectual property principally in the Refining & Marketing and Chemical segment. On July 24, 2014, the IASB completed its project to replace IAS 39 by issuing the final version of IFRS 9 “Financial Instruments” (hereinafter IFRS 9). In particular, IFRS 9: (i) changes the classification and measurement approach for financial assets, basing it on the characteristics of the financial instrument and on the business model adopted by the entity for managing it; (ii) introduces a new impairment model for financial assets, which considers the expected credit losses; and (iii) includes an improved hedge accounting model. IFRS 9 shall be applied for annual periods beginning on or after January 1, 2018. In 2016, the Group started analytical activities with reference to the three main updated areas above-mentioned. In particular, the Group is assessing if the new classification requirements of IFRS 9 will impact the current way of classification of financial instruments; at the current stage of the analysis, the Group has not identified relevant impacts. An in-depth analysis on the fair value measurements of minority F-31 investments in equity instruments that, under current provisions, are measured at cost when their fair value cannot be reliably measured, is being carried out. With reference to the application of the expected credit loss model, the ongoing activities essentially concern: (i) for counterparties with an identifiable credit risk factor (e.g. the credit rating), the adoption of the expected loss model, defined having regard also to the current credit enhancements held (e.g. collaterals, guarantees, insurance contracts, etc.); (ii) for retail customers, the implementation of provision matrix to represent adequately the credit standing of the counterparty; and (iii) the revision and optimization of the operating processes to ensure the availability of information for implementing the evaluation models and drawing up the financial reporting. In relation to hedge accounting, analyses on the applicability of the new qualifying criteria provided by IFRS 9 and on the implementation of rebalancing mechanism to maintain a hedge ratio that complies with the hedge effectiveness requirements, is being carried out. At the current stage of the analyses, the likely impacts deriving from the application of the new IFRS 15 and IFRS 9 are not yet reasonably estimable. On September 11, 2014, the IASB issued the amendments to IFRS 10 and IAS 28 “Sale or Contribution of Assets between an Investor and its Associate or Joint Venture” (hereinafter the amendments to IFRS 10 and IAS 28), which define the recognition criteria of the economic effects mainly related to the loss of control of an investment as a consequence of its transfer to an associate or a joint venture. On December 17, 2015, the IASB issued an amendment that postpones the application of the amendments to IFRS 10 and IAS 28 indefinitely. On January 13, 2016, the IASB issued IFRS 16 “Leases” (hereinafter IFRS 16), which replaces IAS 17 and related interpretations. In particular, IFRS 16 defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration. The new IFRS eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial statements; for all leases with a term of more than 12 months, the lessee shall recognize an asset, as the right-of-use, and a liability, as the present value of the lease payments. Conversely, a lessor continues to classify its leases as operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and for lessors. IFRS 16 shall be applied for annual periods beginning on or after January 1, 2019. On January 19, 2016, the IASB issued the amendments to IAS 12 “Recognition of Deferred Tax Assets for Unrealized Losses”, which provide clarifications about the recognition and measurement of deferred tax assets. The amendments to IAS 12 shall be applied for annual periods beginning on or after January 1, 2017. On January 29, 2016, the IASB issued the amendments to IAS 7 “Disclosure Initiative”, which enhance disclosures required in case of changes in liabilities arising from financing activities, including both changes arising from cash flows and non-cash changes. The amendments to IAS 7 shall be applied for annual periods beginning on or after January 1, 2017. On December 8, 2016, the IASB issued the IFRIC Interpretation 22 “Foreign Currency Transactions and Advance Consideration” (hereinafter IFRIC 22), which sets out that the exchange rate to use on initial recognition of an asset, expense or income related to an advance consideration, previously paid or received in a foreign currency, is the rate used at the date of initial recognition of the non-monetary asset or non-monetary liability arising from the payment or receipt of that advance consideration. The IFRIC 22 shall be applied for annual periods beginning on or after January 1, 2018. On December 8, 2016, the IASB issued the document “Annual Improvements to IFRS Standards 2014-2016 Cycle”, which include, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual periods beginning on or after January 1, 201819. Eni is currently reviewing these new IFRSs to determine the likely impact on the Group’s results. (19) The clarification of the scope of the IFRS 12 “Disclosure of Interests in Other Entities” shall be applied for annual periods beginning on or after January 1, 2017. F-32 Current assets 8 Cash and cash equivalents Cash and cash equivalents of €5,674 million (€5,209 million at December 31, 2015) included financial assets with maturity of three months or less at the date of inception amounting to €4,379 million (€3,289 million at December 31, 2015) and mainly included short-term deposits having notice of more than 48 hours. The average maturity of financial assets due within 90 days was 7 days and the average interest rate was negative and amounted to 0.01% (positive 0.25% at December 31, 2015). 9 Financial assets held for trading (€ million) Quoted bonds issued by sovereign states ........................................ Other ........................................................................................ December 31, 2015 December 31, 2016 925 4,103 5,028 996 5,170 6,166 Financial assets held for trading of €6,166 million (€5,028 million at December 31, 2015) related to Eni SpA for €6,062 million (€5,028 million at December 31, 2015) and to Eni Insurance DAC per €104 million. Financial assets held for trading of Eni SpA include securities subject to lending agreements of €665 million. The Company has established a liquidity reserve as part of its internal targets and financial strategy. The management of this liquidity reserve is performed through trading activities in view of the financial optimization of returns, within a predefined level of risk tolerance, targeting the preservation of the invested capital and the ability to promptly convert it into cash. The breakdown by currency is provided below: (€ million) December 31, 2015 December 31, 2016 Euro ......................................................................................... U.S. dollar ................................................................................. British pound ............................................................................. Swiss franc ................................................................................ Canadian dollar ......................................................................... Australian dollar ........................................................................ 3,906 272 271 524 36 19 5,028 4,319 699 632 413 52 51 6,166 F-33 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 ....................................................................... Spain ..................................................................... Poland .................................................................... Slovenia .................................................................. Germany ................................................................. Ireland ................................................................... Chile ...................................................................... Slovakia .................................................................. Sweden ................................................................... Floating rate bonds Italy ....................................................................... Spain ..................................................................... Total quoted bonds issued by sovereign states ........................ Other Bonds Fixed rate bonds Quoted bonds issued by industrial companies ...................... Quoted bonds issued by financial and insurance companies ..... European Investment Bank ........................................... Floating rate bonds Quoted bonds issued by financial and insurance companies ..... Quoted bonds issued by industrial companies ...................... Total other bonds ........................................................ Total other financial assets held for trading .......................... 539 158 62 33 23 10 8 5 5 843 100 30 130 973 2,264 1,981 8 4,253 553 231 784 5,037 6,010 548 166 64 36 24 11 8 5 5 867 100 29 129 996 2,344 2,031 8 4,383 556 231 787 5,170 6,166 Baa2 Baa2 A2 Baa3 Aaa A3 Aa3 A2 Aaa Baa2 Baa2 BBB- BBB+ BBB+ A AAA A+ AA- A+ AAA BBB- BBB+ from Aaa to Baa3 from AAA to BBB- from Aaa to Baa3 from AAA to BBB- AAA Aaa from Aaa to Baa3 from AAA to BBB- from Aaa to Baa3 from AAA to BBB- The fair value was determined based on market quotations. The fair value hierarchy is level 1. 10 Financial assets available for sale (€ million) December 31, 2015 December 31, 2016 Securities held for operating purposes Quoted bonds issued by sovereign states ........................................ Quoted securities issued by financial institutions ............................ Securities held for non-operating purposes Quoted bonds issued by sovereign states ........................................ Quoted securities issued by financial institutions ............................ 243 39 282 Total ......................................................................................... 282 210 28 238 238 The breakdown by currency is provided below: (€ million) December 31, 2015 December 31, 2016 Euro ......................................................................................... U.S. Dollar ................................................................................ 241 41 282 199 39 238 F-34 At December 31, 2016, bonds issued by sovereign states amounted to €210 million (€243 million at December 31, 2015). The breakdown is presented below: Nominal value (€ million) Fair Value (€ million) Nominal rate of return (%) Maturity date Rating – Moody’s Rating – S&P Fixed rate bonds Belgium ............................ Spain ................................ Italy ................................. France .............................. Poland .............................. Ireland .............................. Iceland .............................. Slovakia ............................ Finland ............................. Portugal ............................ Czech Republic ................... Slovenia ............................ United States of America ....... Canada ............................. Netherlands ....................... Total ................................. 27 25 22 17 16 16 15 10 9 7 7 7 7 5 1 191 32 28 22 19 19 18 16 10 9 8 8 8 7 5 1 210 from 3.75 to 4.25 from 1.40 to 5.50 from 0.00 to 3.50 from 1.00 to 3.25 from 4.50 to 6.38 from 0.80 to 4.40 from 2.50 to 5.88 from 1.50 to 4.20 from 1.13 to 1.75 4.75 3.63 2.25 from 1.25 to 3.13 1.63 4.00 from 2019 to 2021 from 2018 to 2021 from 2017 to 2020 from 2018 to 2023 from 2019 to 2022 from 2019 to 2022 from 2020 to 2022 from 2017 to 2018 from 2017 to 2019 2019 2021 2022 from 2019 to 2020 2019 2018 Aa3 Baa2 Baa2 Aa2 A2 A3 A3 A2 Aa1 Ba1 A1 Baa3 Aaa Aaa Aaa AA BBB+ BBB- AA BBB+ A+ BBB+ A+ AA+ BB+ AA- A AA+ AAA AAA Quoted securities amounting to €28 million (€39 million at December 31, 2015) were issued by financial institutions with a rating from Aaa to Aa1 (Moody’s) and from AAA to AA (S&P). Securities held for non-operating purposes of €238 million related to the Group’s insurance company Eni Insurance DAC. From January 1, 2016, insurance companies are required to meet certain capital and solvency ratios as minimum requirements to continue performing the insurance activity based on the provisions of EU Solvency II Directive (the so-called Minimum Capital Requirement — MCR — and Solvency Capital Requirement — SCR). Therefore, while it is advisable to maintain a sound investment policy of the proceeds associated with the business, insurance companies have been waived from committing financial assets to funding the loss provisions. Accordingly, available-for-sale securities held by Eni’s subsidiary Eni Insurance DAC at the opening balance for €282 million have been reclassified as held for non-operating purposes. The same reclassification has been applied to financial receivables held by Eni Insurance DAC (see note 11 — Trade and other receivables). The effects of fair value measurement of securities are set out below: (€ million) Carrying amount at December 31, 2015 Changes recognized in equity Reversal of the year Carrying amount at December 31, 2016 Fair value .............................................. Deferred tax liabilities ............................. Other reserves of shareholders’ equity ........ 9 (1) 8 (3) (3) (1) (1) 5 (1) 4 The fair value was determined based on market quotations. The fair value hierarchy is level 1. F-35 11 Trade and other receivables (€ million) Trade receivables ........................................................................ Financing receivables - for operating purposes – short-term ............................................ - for operating purposes – current portion of long-term receivables ... - for non-operating purposes ........................................................ Other receivables - from disposals .......................................................................... - other ....................................................................................... December 31, 2015 December 31, 2016 12,616 11,186 375 1,247 685 2,307 33 6,684 6,717 21,640 86 72 385 543 171 5,693 5,864 17,593 Trade receivables decreased by €1,430 million, of which €1,298 million in the Gas & Power segment because an increased volume of receivables were sold to financial institutions as a result of factoring transactions. Receivables are stated net of the valuation allowance for doubtful accounts of €2,371 million (€2,083 million at December 31, 2015): (€ million) Trade receivables ................. Financing receivables ........... Other receivables ................. Carrying amount at December 31, 2015 1,915 66 102 2,083 Additions Deductions Other changes 503 367 870 (607) (4) (611) 6 2 21 29 Carrying amount at December 31, 2016 1,817 68 486 2,371 Additions to allowance for doubtful accounts amounted to €503 million (€588 million in 2015) and related mainly to the Gas & Power segment for €399 million. This is reflective of the continuing difficulties in the collection of overdue receivables in the retail customers segment. The mitigation measures regarding the counterparty risk executed by Eni through specific actions of recovery and through specialized external services have led to a reduction of overdue receivables during the year 2016. Utilizations amounting to €607 million (€249 million in 2015) related to the Gas & Power segment for €559 million and related to the recognition of losses on doubtful accounts in the retail business. At December 31, 2016, Eni sold without recourse trade receivables due in 2017 for €1,769 million to financial institutions (€750 million at December 31, 2015 due in 2016). Derecognized receivables related to the Gas & Power segment (€1,434 million) and to the Refining & Marketing and Chemical segment (€335 million). Trade receivables outstanding at December 31, 2016 comprised receivables of €1,764 million for hydrocarbons supplies made by the Exploration & Production segment to national oil companies. That amount includes overdue receivables related to: (i) State-owned oil companies in Egypt, which overdue amount was €420 million. This was significantly lower than the overdue amount of €771 million outstanding at December 31, 2015 and was driven by the implementation of a plan intended to trim the overdue amounts, which comprised the settlement of certain commercial and industrial agreements with the counterparties. The residual amount outstanding at the reporting date has been further reduced by a payment dated January 2017 amounting to $240 million (€228 million); (ii) State-owned companies in Iran as part of a settlement agreement signed in 2015 regarding the recovery of past costs associated to certain petroleum projects already completed for €264 million. This amount was curtailed compared to December 31, 2015 (€312 million). The State counterparties expressed their willingness to negotiate a repayment plan of overdue receivables based on arrangements relating the sale of volumes of the Iranian counterpart equity crude and the attribution to Eni of a percentage of the sale proceeds. This agreement F-36 has been firstly enacted in the last months of 2016 with a reimbursement to Eni of $44 million (€42 million). Negotiations are underway to identify additional crude volumes to be marketed, some of which have already been awarded to Eni in early 2017, with the aim of fully recovering the overdue amounts. The ageing of trade and other receivables is presented below: (€ million) Neither impaired nor past due ................................... Impaired (net of the valuation for doubtful accounts) ................................................................ Not impaired and past due in the following periods: - within 90 days ...................................................... - 3 to 6 months ....................................................... - 6 to 12 months ..................................................... - over 12 months ..................................................... December 31, 2015 December 31, 2016 Trade receivables Other receivables Trade receivables Other receivables 9,814 5,371 9,243 4,869 1,085 1,080 110 226 301 1,717 12,616 93 92 502 485 174 1,253 6,717 759 744 49 69 322 1,184 11,186 432 58 81 249 175 563 5,864 The Group has not booked any counterparty loss on certain trade and other receivables which were overdue at the balance sheet date, because they pertained to highly-rated Italian and foreign public administrations, to other highly-reliable counterparties for supplies of oil, natural gas, refined and chemical products and to retail customers of the Gas & Power segment overdue by less than 90 days. Trade receivables in currencies other than euro amounted to €3,629 million (€3,995 million at December 31, 2015). Financing receivables associated with operating purposes of €158 million (€1,622 million at December 31, 2015) included loans granted to joint ventures and associates to fund the execution of Eni’s capital projects for €28 million (€1,135 million at December 31, 2015). The decrease for €1,464 million comprised the reclassification for €1,054 million to other non-current financial assets of the financing loan granted to the equity-accounted investee CARDÓN IV SA (Eni’s share being 50%) (€1,112 million at December 31, 2015). Financing receivables for operating purposes outstanding at December 31, 2015, of €287 million relating to Eni Insurance DAC were reclassified as financing receivables not associated with operating activities following the adoption of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale. Financing receivables not associated with operating activities amounted to €385 million (€685 million at December 31, 2015) and related to: (i) restricted deposits in escrow for €137 million of Eni Trading & Shipping SpA (€209 million at December 31, 2015) of which €113 million with BNP Paribas and €24 million with Citibank relating to derivatives; (ii) deposits of Eni Insurance DAC for €225 million. Financing receivables in currencies other than euro amounted to €121 million (€1,329 million as of December 31, 2015). Receivables from divestments amounted to €171 million (€33 million at December 31, 2015), of which €166 million related to the current portion of the receivable arising from the divestment finalized in 2008 of a 1.71% interest in the Kashagan project to the local partner KazMunayGas for a total amount of €463 million. The reimbursement of the receivable is scheduled in three annual instalments commencing from the date when the agreed production target is achieved. The receivable accrues interest income at market rates. Due to the restart of the project, the production milestone was reached in the fourth quarter 2016 and, consequently, the first installment of the sale price including interests has been repaid (€152 million). The description of the transaction is provided in note 23 — Other non-current assets. Other receivables of €5,693 million (€6,684 million at December 31, 2015) included €4,111 million of receivables owed by Eni’s partners in unincorporated joint ventures that are currently executing exploration F-37 and production projects. The largest outstanding amount as of December 31, 2016 related to partners in Nigeria (€1,775 million) and among these the Nigerian national oil company NNPC in respect of: (i) receivables of €382 million (€773 million at December 31, 2015) related to the contractual recovery of costs incurred for two oil projects (one of which is operated) under arbitration procedures. After the issuance of favorable arbitration rulings, the Company is negotiating a settlement agreement with the aim of being reimbursed of a part of the amount awarded by the arbitration procedures. The amount being negotiated will be reimbursed through the assignment to Eni of crude oil quantities owned by the state company over a period of three years. The impairment loss related to the receivables resulting from the agreement under negotiation amounted to €332 million plus the discount effect of the expected future cash flows, which reflected the mineral risk (€42 million); (ii) receivables of €716 million were overdue at the balance sheet date in relation to the cash calls owed by NNPC at certain projects operated by Eni. At the opening balance, part of these receivables was denominated in local currency and consequently their carrying amounts were negatively affected by the currency devaluation occurred in 2016. Eni and NNPC agreed on a repayment plan providing for a reimbursement in U.S. dollars and the attribution to Eni of a portion of the proceeds from the sale of the hydrocarbon productions which will be obtained from development activities with a low risk profile (rigless) in order to fully repay the overdue amounts within a period of five years. The expenses through profit included foreign exchange losses for $80 million (€72 million) and the discounting effect for $96 million (€87 million), which was determined taking into account the mineral risk. Other receivables were as follows: (€ million) December 31, 2015 December 31, 2016 Receivables originated from divestments ............................................. Accounts receivable from - joint venture partners in exploration and production ........................ - prepayments for services ............................................................... - insurance companies ..................................................................... - non-financial government entities ................................................... - factoring arrangements ................................................................. - non-Italian oil entities for oil tax refunds ......................................... - other receivables ........................................................................... 33 4,656 540 113 104 90 27 1,154 6,684 6,717 171 4,111 372 147 49 81 40 893 5,693 5,864 Receivables from joint venture partners in exploration and production activities of €60 million (€281 million at December 31, 2015) included the liability for benefit plans (see note 31 — Provisions for employee benefits). Receivables from factoring arrangements of €81 million (€90 million at December 31, 2015) related to Serfactoring SpA and consisted of advances for factoring arrangements with recourse and receivables for factoring arrangements without recourse. Other receivables in currencies other than euro amounted to €5,253 million (€5,913 million at December 31, 2015). Because of the short-term maturity and conditions of remuneration of trade and other receivables, the fair value approximated the carrying amount. Receivables with related parties are described in note 47 — Transactions with related parties. F-38 12 Inventories (€ million) Raw and auxiliary materials and consumables .. Products being processed and semi-finished products ................................................... Work in progress ........................................ Finished products and goods ........................ Certificates and emission rights...................... December 31, 2015 December 31, 2016 Crude oil, gas and petroleum products 222 97 1,573 1,892 Chemical products Other Total Crude oil, gas and petroleum products Chemical products Other Total 142 1,933 2,297 550 135 1,903 2,588 9 448 599 1 7 107 7 72 2,093 75 75 2,088 4,579 99 1,394 2,043 9 389 533 1 2 109 2 86 1,869 69 69 2,061 4,637 Other inventories of raw and auxiliary materials and consumables of €1,903 million (€1,933 million at December 31, 2015) related to the Exploration & Production segment for €1,699 million (€1,732 million at December 31, 2015) and primarily comprised materials relating to perforation activities and the maintenance of infrastructures and facilities. Certificates and emission rights of €69 million (€75 million at December 31, 2015) are measured at the fair value determined based on market quotations. The fair value hierarchy is level 1. Inventories of €82 million (€87 million at December 31, 2015) were pledged to guarantee the potential balancing with respect to Snam Rete Gas SpA. Changes in inventories and in the loss provision were as follows: (€ million) 2015 Gross carrying amount ......................... Loss provision ..................................... Net carrying amount ............................. 2016 Gross carrying amount ......................... Loss provision ..................................... Net carrying amount ............................. Carrying amount at the beginning of the year Changes New or increased provisions Deductions Currency translation differences Other changes Carrying amount at the end of the year 8,027 (472) 7,555 4,887 (308) 4,579 (1,082) (1,082) (29) (29) (93) (93) (125) (125) 212 212 163 163 249 (10) 239 61 (5) 56 (2,307) 55 (2,252) (27) 20 (7) 4,887 (308) 4,579 4,892 (255) 4,637 Negative changes of the period amounting to €29 million related to the Chemical business line for €96 million partially offset by the increase in the Refining & Marketing segment for €75 million. The increase in loss provision of €125 million related to the Exploration & Production segment for €72 million. Deductions of €163 million for loss provision primarily related to the Refining & Marketing business line (€122 million). Other changes of €2,252 million as of December 31, 2015, included the reclassification of €2,183 million as discontinued operations. 13 Current tax assets (€ million) Italian subsidiaries ........................................................................... Subsidiaries outside Italy .................................................................. December 31, 2015 December 31, 2016 182 178 360 134 249 383 Income taxes are described in note 43 — Income tax expense. F-39 14 Other current tax assets (€ million) December 31, 2015 December 31, 2016 VAT ............................................................................................. Excise and customs duties ............................................................... Other taxes and duties .................................................................... 386 121 123 630 447 161 81 689 15 Other current assets (€ million) Fair value of derivative financial instruments ..................................... Other current assets ........................................................................ December 31, 2015 December 31, 2016 3,220 422 3,642 2,248 343 2,591 The fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments. Other assets amounting to €343 million (€422 million at December 31, 2015) included gas volumes prepayments that were made in previous reporting period due to the take-or-pay obligations in the Company’s long-term supply contracts, as the Company is forecasting to make-up the underlying gas volumes in the next 12 months. The residual amount as of December 31, 2016 for €90 million reflected the off-taken of underlying volumes achieved during the period that reduced the amount outstanding at the end of 2015 by €108 million. In 2016, the carrying amount of the prepayment, assimilated to a receivable in kind, was written down by €24 million to align it to the current prices of gas. Transactions with related parties are described in note 47 — Transactions with related parties. Non-current assets 16 Property, plant and equipment (€ million) 2015 Land . . . . . . . . . . . . . . . . . . . . Buildings . . . . . . . . . . . . . . . Plant and machinery . . . . . . . . . . . . . . Industrial and commercial equipment Other assets . . . . . . . . . . . . Tangible assets in progress and advances . 2016 Land . . . . . . . . . . . . . . . . . . . . Buildings . . . . . . . . . . . . . . . Plant and machinery . . . . . . . . . . . . . . Industrial and commercial equipment Other assets . . . . . . . . . . . . Tangible assets in progress and advances . Net book amount at the beginning of the year Additions Depreciation Net Impairments/ reversal Write-off Currency translation differences Reclassification to discontinued operations and assets held for sale Net book amount at the end of the year Gross book amount at the end of the year Other changes Provisions for depreciation and impairments 615 1,633 1 32 (70) (47) (13) 16 (98) (602) 5 (144) 510 818 534 3,374 24 2,556 47,506 369 (8,403) (3,624) 3,276 (6,264) 7,807 40,667 147,969 107,302 590 458 49 57 (85) (88) (1) (6) (2) 14 17 25,189 75,991 10,669 11,177 (8,646) (2,312) (5,990) (676) (678) 2,009 5,319 510 818 1 22 (66) (64) (3) 1 1 40,667 204 (7,087) 345 (198) 1,329 (197) (37) (311) (7,509) (8) (2) (1) (42) 2 326 403 1,368 2,169 1,042 1,766 (9,287) 25,281 (1,659) 68,005 29,835 185,249 4,554 117,244 8 40 448 810 537 3,416 89 2,606 15,011 50,270 167,007 116,737 326 403 32 42 (66) (89) 25,281 68,005 8,766 9,067 (7,308) (1) (17) (174) 86 (2) 4 11 (34) 300 309 1,415 2,160 1,115 1,851 (89) (289) 551 1,886 (11) (15,679) 18,656 (643) 70,793 22,737 197,272 4,081 126,479 F-40 A breakdown by segment of capital expenditures made in 2016 is provided below: (€ million) 2015 2016 Capital expenditure Exploration & Production ............................................................... Gas & Power .................................................................................. Refining & Marketing and Chemical ................................................. Engineering & Construction ............................................................ Corporate and other activities .......................................................... Elimination of intragroup profits ..................................................... 9,943 109 614 550 46 (85) 11,177 8,217 66 655 42 87 9,067 Capital expenditures included capitalized finance expenses of €105 million (€165 million in 2015) and related to the Exploration & Production segment (€90 million). The interest rates used for capitalizing finance expense ranged from 2.7% to 5.3% (2.4% and 5.3% at December 31, 2015). The main depreciation rates used were substantially unchanged from the previous year and ranged as follows: (%) Buildings ................................................................................................................. Plant and machinery ................................................................................................. Industrial and commercial equipment .......................................................................... Other assets .............................................................................................................. 2 2 4 6 - - - - 10 15 33 33 The criteria adopted by Eni for determining net impairments/reversals is reported in note 19 — Impairment/reversal of tangible and intangible assets. Write-off of €289 million (€678 million in 2015) related for €193 million to the EST conversion plant units at the Sannazzaro refinery, damaged in an accident occurred in December 2016. The Exploration & Production booked €93 million of asset write-offs (€676 million in 2015), of which €88 million mainly relating exploration wells capitalized in previous reporting periods. Wells write-offs comprised suspended exploration wells that did not encountered enough quantities of commercial hydrocarbons to justify their completion as productive wells in Libya, Angola, Congo and Indonesia. Foreign currency translation differences of €1,886 million primarily related to translations of entities accounts denominated in U.S. dollar (€1,761 million), Norwegian krone (€318 million) and, as decrease, in in British pound (€215 million). Other changes of €643 million related to the initial recognition and change in estimates of decommissioning costs and site restoration in the Exploration & Production segment amounting to €665 million (€817 million at December 31, 2015) mainly due to a steeper discount rate curve, especially for the U.S. dollar and to the revision of cost estimates. These effects were partially offset by the recognition of new obligations incurred during the year. Other changes in tangible assets in progress and advances of €15,679 million included the reclassification from plant and machinery of the carrying amount of the idle units of the EST plant of the Sannazzaro refinery for €485 million until the re-entry into operations of the damaged section. F-41 Tangible assets in progress and advances include costs related to exploration activities and appraisal and tangible assets in progress and advances of the Exploration & Production segment: (€ million) 2015 Exploration activity and appraisal Exploratory wells in progress .................. Exploratory wells completed and being evaluated ........................................... Exploratory successful wells in progress .... Other tangible assets in progress Unproved mineral interest ...................... Wells and plants in progress ................... 2016 Exploration activity and appraisal Exploratory wells in progress .................. Exploratory wells completed and being evaluated ........................................... Exploratory successful wells in progress .... Other tangible assets in progress Unproved mineral interest ..................... Wells and plants in progress ................... Abandonment cost .............................. Book amount at the beginning Net impairments/ of the year Additions reversals Write-off Reclassifications Other changes and currency translation differences Book amount at the end of the year 196 558 1,568 813 2,577 3,092 17,958 21,050 23,627 558 9,346 9,346 9,904 (91) (91) (998) (866) (1,864) (1,955) 93 402 1,737 807 2,637 2,212 19,458 21,670 24,307 402 2 7,777 7,779 8,181 (5) (5) 190 (210) (20) (25) (106) (501) (607) (69) (69) (676) (109) (109) (6) 27 21 (88) (572) 520 5 (47) (203) (8,107) (8,310) (8,357) (282) 6 78 (198) (35) (15,699) (15,734) (15,932) 17 150 80 247 321 1,196 1,517 1,764 8 50 33 91 81 370 55 506 597 93 1,737 807 2,637 2,212 19,458 21,670 24,307 221 1,684 913 2,818 2,450 11,690 82 14,222 17,040 Reclassifications of €15,932 million mainly related to wells and production plants started to production in the year for €15,699 million, particularly due to the start-up of major oil&gas projects such as the Kashagan project in Kazakhstan, the Goliat project in Norway and the ‘Mpungi field in the West Hub project, Block 15/06 in Angola. The following information relates to the stratification of the suspended wells pending final determination of proved reserves (aging) and the projects to which they relate: (€ million) 2014 2015 Costs for exploratory wells suspended at the beginning of the period ......... Additions pending the determination of proved reserves ...................... Amounts charged to expense ............................................................. Reclassification to productive wells on determination of proved reserves Sales .............................................................................................. Exchange differences ........................................................................ Costs for exploratory wells suspended at the end of the period ................. 1,618 373 (267) (314) 158 1,568 1,568 550 (501) (30) (4) 154 1,737 2016 1,737 282 (109) (276) 50 1,684 F-42 2014 2015 2016 (number of wells in Eni’s interest) (number of wells in Eni’s interest) (€ million) (number of wells in Eni’s interest) (€ million) (€ million) Costs capitalized and suspended for exploratory well activity ............................ - within 1 year ......................................... - between 1 and 3 years ............................. - beyond 3 years ...................................... Costs capitalized for suspended wells - fields including wells drilled over the last 12 months ............................................... - fields for which the delineation campaign is in progress ........................................... - fields including commercial discoveries that are progressing to sanctioning ............. 392 756 420 1,568 7.85 15.07 12.87 35.79 392 7.85 1,043 21.90 368 634 735 1,737 368 228 5.32 11.14 18.97 35.43 5.32 4.13 16 609 1,059 1,684 9 251 1.05 10.25 21.55 32.85 0.55 3.51 133 1,568 6.04 35.79 1,141 1,737 25.98 35.43 1,424 1,684 28.79 32.85 The unproved mineral interests were recognized in connection with the purchase price allocation as part of business combinations or acquisitions of individual properties: (€ million) of the year Acquisitions Book amount at the beginning Net reversals (impairments) Reclassification to proved mineral interest Other changes and currency translation differences Book amount at the end of the year 2015 Congo .......................................... Nigeria ......................................... Turkmenistan ................................ Algeria .......................................... USA ............................................. Egypt ............................................ 2016 Congo .......................................... Nigeria ......................................... Turkmenistan ................................ USA ............................................. Egypt ............................................ 1,214 823 524 373 123 35 3,092 1,021 908 165 109 9 2,212 (201) (411) (386) (998) 190 2 2 190 (127) (22) (20) (34) (203) (31) (4) (35) 135 85 52 35 6 8 321 43 30 4 4 81 1,021 908 165 109 9 2,212 1,254 938 138 113 7 2,450 In 2016, Eni recorded reversals of previous impairment losses for €190 million (see note 19 – Impairment/reversal of tangible and intangible assets). Unproved mineral interest comprised a property known as Oil Prospecting License 245 (“OPL 245”), located offshore Nigeria, with a net book value of €932 million, which corresponded to the price paid to the Nigeria Government to acquire a 50% interest in OPL 245, with the partner Shell acquiring the remaining 50%. As of December 31, 2016, the net book value of the property was €1,255 million, including capitalized exploration costs and pre-development costs. The acquisition of OPL 245 is subject to judicial proceedings in Italy and in Nigeria for alleged corruption and money laundering in respect of the Resolution Agreement signed on April 29, 2011, relating to the purchase of the license by Eni and Shell. Those proceedings are disclosed in note 38 - Guarantees, Commitments and Risks. On January 27, 2017, Eni subsidiary Nigerian Agip Exploration Ltd became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court, sitting in Abuja, upon request from the Economic and Financial Crime Commission (EFCC), attaching the property OPL 245, pending the Nigerian proceeding. Both Eni and Shell made a prompt application to discharge the Order. On March 17, 2017, the Nigerian Court discharged the Order. Management has concluded that no impairment of the asset was required. After the inception of the judicial proceeding in Italy, which dates back to July 2014, Eni’s Board of F-43 Statutory Auditors jointly with the Eni Watch Structure has engaged a US leading law firm to perform an independent review of the issue. Based on the outcome of this review, during which the law firm has also assessed material and the information made available from the judicial authorities, no wrongdoing has been detected on Eni side in the awarding process to Eni of the license. Accumulated provisions for impairments amounted to €17,558 million (€17,480 million at December 31, 2015). At December 31, 2016, Eni pledged property, plant and equipment for €24 million primarily as collateral against certain borrowings (€21 million at December 31, 2015). Government grants recorded as a decrease of property, plant and equipment amounted to €90 million (€96 million at December 31, 2015). Assets acquired under financial lease agreements amounted to €29 million (€26 million at December 31, 2015) and related to service stations of the Refining & Marketing business line. Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 38 — Guarantees, commitments and risks — Liquidity risk. Property, plant and equipment under concession arrangements are described in note 38 – Guarantees, commitments and risks — Assets under concession arrangements. Property, plant and equipment by segment (€ million) December 31, 2015 December 31, 2016 Property, plant and equipment, gross Exploration & Production ................................................................... Gas & Power ..................................................................................... Refining & Marketing and Chemical .................................................... Corporate and other activities ............................................................. Elimination of intragroup profits ......................................................... Accumulated depreciation, amortization and impairment losses Exploration & Production ................................................................... Gas & Power ..................................................................................... Refining & Marketing and Chemical .................................................... Corporate and other activities ............................................................. Elimination of intragroup profits ......................................................... Property, plant and equipment, net Exploration & Production ................................................................... Gas & Power ..................................................................................... Refining & Marketing and Chemical .................................................... Corporate and other activities ............................................................. Elimination of intragroup profits ......................................................... 154,064 6,169 23,818 1,854 (656) 185,249 92,569 4,287 19,154 1,436 (202) 117,244 61,495 1,882 4,664 418 (454) 68,005 165,559 6,276 24,119 1,886 (568) 197,272 101,131 4,584 19,477 1,518 (231) 126,479 64,428 1,692 4,642 368 (337) 70,793 17 Inventory — compulsory stock Compulsory inventories of €1,184 million (€909 million at December 31, 2015) were primarily held by Italian subsidiaries for €1,167 million (€893 million at December 31, 2015) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws. F-44 18 Intangible assets (€ million) 2015 Intangible assets with finite useful lives Exploration expenditures Concessions, licenses, trademarks and similar items . . . . . . . . . . . . . . . . . . . . . . . Industrial patents and intellectual property rights . . . . . . . . . . . . . . . . . . . . . . Service concession arrangements . . . . . . . . . . . . . Intangible assets in progress and advances . . . . Other intangible assets . . . Intangible assets with indefinite useful lives Goodwill . . . . . . . . . . . . . . . . . . 2016 Intangible assets with finite useful lives Exploration expenditures Concessions, licenses, trademarks and similar items . . . . . . . . . . . . . . . . . . . . . . . Industrial patents and intellectual property rights . . . . . . . . . . . . . . . . . . . . . . Service concession arrangements . . . . . . . . . . . . . Intangible assets in progress and advances . . . . Other intangible assets . . . Intangible assets with indefinite useful lives Goodwill . . . . . . . . . . . . . . . . . . 1,081 479 285 32 179 167 2,223 2,197 4,420 735 363 276 32 148 166 1,720 1,314 3,034 Net book amount at the beginning Net impairments/ of the year Additions Amortization reversals Write-off Reclassification to discontinued operations and assets held for sale Currency translation differences Net book amount at the end of the year Gross book amount at the end of the year Other changes Provisions for amortization and impairments 8 8 26 54 29 125 15 6 26 1 49 16 113 (63) (369) (10) 102 (14) 735 2,195 1,460 (117) (2) (74) (2) (47) (303) (7) (5) (383) (161) (544) (10) (10) (1) 1 2 104 34 138 (4) (31) (7) (1) (43) 363 2,499 2,136 69 2 (71) 21 7 276 32 148 166 1,720 1,407 1,131 51 153 2,576 8,881 19 5 2,410 7,161 (363) (406) (393) (386) 1,314 3,034 125 (303) (18) 385 (61) 36 1,092 2,216 1,124 (113) (81) (2) (39) (253) 4 389 (61) (1) 255 2,462 2,207 1,467 1,208 52 153 2,599 8,949 21 5 2,435 7,000 38 259 31 (49) 21 9 148 164 1,949 1,320 3,269 9 (4) 32 6 38 113 (253) 389 (61) Exploration rights €1,092 million (€735 million at December 31, 2015) comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on the UOP criteria and are regularly reviewed for impairment. Furthermore, they include the cost of unproved areas which are suspended pending a final determination of the success of the exploratory activity or until management confirms its commitment to the initiative. Reversals of previous impairment losses of €385 million (impairments losses of €369 million were recorded in 2015) were recognized at proved license acquisition costs in Angola and Congo. More information is provided in note 19 — impairments and reversal of tangible and intangible assets. Write-offs for €61 million (€10 million in 2015) were booked at unproved exploratory rights due to the negative outcome of certain exploration projects, the most important being an initiative in Angola. The breakdown of exploration rights by type of asset was as follows: (€ million) December 31, 2015 December 31, 2016 Proved license and leasehold property acquisition costs ...................... Unproved license and leasehold property acquisition costs .................. Other mineral interests .................................................................... 90 611 34 735 497 579 16 1,092 Concessions, licenses, trademarks and similar items for €255 million (€363 million at December 31, 2015) primarily comprised transmission rights for natural gas imported from Algeria of €223 million (€323 million at December 31, 2015) and concessions for mineral exploration of €13 million (€15 million at December 31, 2015). F-45 Industrial patents and intellectual property rights of €259 million (€276 million at December 31, 2015) related to Eni SpA for €235 million (€250 million at December 31, 2015) and essentially concerned costs for the acquisition and internal development of software and rights for the use of production processes and software. Service concession arrangements of €31 million primarily pertained to gas distribution activities outside Italy (€32 million at December 31, 2015). Intangible assets in progress and advances of €148 million (same amount as of December 31, 2015) related to Eni SpA for €44 million (€49 million at December 31, 2015) and primarily concerned cost for software development. Other intangible assets with finite useful lives of €164 million (€166 million at December 31, 2015) comprised: (i) royalties for the use of licenses by Versalis SpA for €40 million (same amount as of December 31, 2015); (ii) the estimated costs of Eni’s social responsibility projects in relation to oil development programs in Val d’Agri and in the North Adriatic area connected to mineral rights under concession for €41 million (€49 million at December 31, 2015) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna. The criteria adopted by Eni for determining net impairments/reversals and the relevant breakdown by segment are reported in note 19 — Impairment/reversal of tangible and intangible assets. The main amortization rates used were substantially unchanged from the previous year and ranged as follows: (%) Exploration rights ................................................................................................... Concessions, licenses, trademarks and similar items ..................................................... Industrial patents and intellectual property rights ........................................................ Service concession arrangements ............................................................................... Other intangible assets ............................................................................................. 14 3 20 2 4 - - - - - 33 33 33 4 25 The carrying amount of goodwill at the end of the year was €1,320 million (€1,314 million at December 31, 2015) net of cumulative impairments charges amounting to €2,524 million (€2,525 million at December 31, 2015). A breakdown of the stated goodwill by operating segment is provided below: (€ million) December 31, 2015 December 31, 2016 Gas & Power ................................................................................. Exploration & Production ............................................................... Refining & Marketing ..................................................................... 1,025 196 93 1,314 1,025 202 93 1,320 More information about goodwill is reported in note 19 — Impairment/reversal of tangible and intangible assets. 19 Impairment/reversal of tangible and intangible assets (€ million) 2015 2016 Impairment losses Tangible assets ............................................................................... Intangible assets ............................................................................. less: - reversal of tangible assets .............................................................. - reversal of intangible assets ............................................................ (5,993) (544) (6,537) 3 (6,534) (1,067) (1,067) 1,153 389 475 F-46 In order to verify the recoverability of the carrying amounts of tangible and intangible assets, management assesses at the end of the year whether there are any indications that assets may be impaired. External impairment indicators comprise evidence that the carrying amount of the net assets of Eni are above Eni market capitalization, expectations about future trends in the prices and margins of commodities, forecast trends in monetary variables (interest rates, exchange rates, inflation), country risk or changes in the regulatory/contractual framework. Internal impairment indicators comprise evidence of reservoirs underperformance, increases in costs/investments, obsolescence and other factors. In case of a recovery in the trading environment or better industrial performance with respect to the comparative period, management assesses whether the factors underlying previous impairment losses may no longer exist or may have decreased. In assessing whether impairment is required, the carrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is the higher of an asset’s fair value less costs to sell and its value-in-use. In the event of an asset’s impairment being reversed, the reversal may not raise the carrying amount above the value it would have stood at taking into account depreciation, if no impairment had originally been recognized. Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by estimating assets’ values-in-use (VIU). The valuation is carried out for individual asset or for the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets, or groups of assets (cash generating unit — CGU). The Group has identified the following CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields where technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power segment, in addition to the CGUs to which goodwill arisen from business combinations was allocated, electricity generation plants, international pipelines and LNG vessels; (iii) in the Refining & Marketing business line, refining plants, retail networks and assets related to other distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) the Chemical business line has been assessed to be a single CGU. 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, 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 and the associated projections of operating costs and development expenditures. The CGUs of the Refining & Marketing business line and each power plant are evaluated based on the plant economic and technical life and the associated, normalized projections of operating costs and expenditures to support plant efficiency. The CGUs of the gas market business to which goodwill has been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0%. The Chemical business CGU considers the average economic useful life of the underlying assets and factors a normalized EBITDA (to reflect the cyclicality of the sector) defined based on the average contribution margin of the plan and applying to the fixed costs the expected inflation rate. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns. The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair. Values-in-use is estimated by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production and Refining & Marketing to the Company’s weighted average cost of capital F-47 (WACC) net of the risk factors attributable to the Gas & Power segment and the Chemical business line the WACC of which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC). Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. From the second half of 2016, the oil market has staged a recovery on the back of a better balance between global supply and demand of crude oil, driven by cuts in investments made by oil companies during the downturn and by the year-end agreement of OPEC countries to curb the cartel output, joined also by important non-OPEC countries (in particular Russia). Considering the historical minimum reached in the first half of the year, the price of the crude oil has recovered about 60% of its value. Based on those improved fundamentals, management revised upwardly its long-term assumption for the benchmark Brent price to 70$ per barrel in 2020 real terms, from a previous 65$ per barrel, in elaborating the Group financial projections of the financial report 2016. Furthermore, at the balance sheet date, the market capitalization of Eni amounted to €55.7 billion exceeding the book value of the consolidated net assets equal to €53.1 billion, thereby discontinuing a two-year long downward trend. the 2017 – 2020 industrial plan and the estimations of Finally, the 2016 WACC of Eni, which is the driver for calculating the WACC of the oil&gas and refining business segments to assess the value-in-use of their relevant CGUs, recorded a marginal decrease, down by 0.1 percentage point to 6.4% compared to 2015. This reduction was driven by a lower premium for the sovereign risk incorporated into the yields on Italian ten-year bonds and a marginal a reduction in the cost of borrowings, offset by an increase in the beta of Eni. The WACC used in the Chemical business line decreased by 1 percentage point to 9% due to a lower country risk, considering that the activities are concentrated in Europe, and to the reduction of the risk-free rate. The WACC in the Gas & Power segment increased by 0.4 percentage points to 5.8% due to a higher country risk of some activities outside Europe. The adjusted WACC rates for 2016 highlighted dispersion compared to the average value of Eni amounting to 6.5%. This reflected a noticeable increase in the country risk in certain upstream areas. The adjusted WACC rates used for impairment test purposes in 2016 ranged from 4.8% to 15.0%. Considering the upward revision of the long-term Brent price, the Company recorded reversals of previous impairment losses in the Exploration & Production segment for a total of €1,440 million reflecting the increased value-in-use of a number of oil&gas assets. The main reversals were recorded at a CGU which includes unproved mineral interests for €190 million, mainly in Congo; license acquisition costs with proved reserves for €385 million, particularly in Angola; property, plant and equipment for €865 million, particularly in Angola, USA, Algeria, Turkmenistan, United Kingdom and Norway. The post-tax WACC relating to reversals of impairments of more than €100 million regarded two CGUs and was 6%, corresponding to a pre-tax rate ranging from 9.64% to 18.13%, respectively. These reversals, which correspond to about 28% of the impairment losses recorded in 2015, were partially offset by the recognition of impairment losses of €740 million. Those losses were driven by a weaker price outlook in the gas market in Europe, which negatively affected the recoverable amounts of Italian gas CGUs, and by downward reserve revisions, contractual changes and an increased country risk, which negatively impacted the recoverable amounts at a number of oil&gas properties in various locations. Impairment losses of more than €100 million regarded two CGUs with a post-tax WACC ranging from 4.8% to 6.1%, restated in a pre-tax rate ranging from 7.9% to 25.86%. Impairment losses recognized in the Refining & Marketing business line of €120 million related to the investments of the year for compliance and stay-in-business related to CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review. Impairment losses net of reversals recognized in the Gas & Power segment amounted to €81 million mainly related to the gas transportation network GreenStream, following the increase in the discount rate for country risk and LNG carriers. Considering the volatility in the oil scenario and the increased financial and geopolitical instability in certain countries where the Eni’s reserves are located, management assessed the fairness of its assumptions and the outcome of the impairment review by stress testing the headroom of the Group’s properties in high-risk locations. This sensitivity analysis was performed increasing by a full percentage point the discount rate applied to future cash flows with a view of factoring in a higher country risk premium. This exercise comprised Eni’s oil&gas properties in Libya, Egypt, Iraq, Venezuela and Nigeria, which base WACC are still significantly higher than the average WACC of Eni. No major changes in the properties headroom were detected. F-48 A breakdown by segment of impairments losses recorded in 2016 and the associated tax effect is provided below: (€ million) Impairment losses Exploration & Production ............................................................... Gas & Power .................................................................................. Refining & Marketing and Chemical ................................................. Corporate and other activities .......................................................... Tax effects Exploration & Production ............................................................... Gas & Power .................................................................................. Refining & Marketing and Chemical ................................................. Corporate and other activities .......................................................... Impairments net of the relevant tax effects Exploration & Production ............................................................... Gas & Power .................................................................................. Refining & Marketing and Chemical ................................................. Corporate and other activities .......................................................... 2015 4,682 153 1,138 20 5,993 1,837 38 38 2 1,915 2,845 115 1,100 18 4,078 2016 740 167 120 40 1,067 216 35 32 283 524 132 88 40 784 A breakdown of impairment losses and reversals in the Exploration & Production segment and the associated tax effect is provided below: (€ million) Impairments (reversal), net Impairments of tangible assets ......................................................... Impairments of intangible assets ...................................................... Reversals of tangible assets .............................................................. Reversals of intangible assets ........................................................... Tax effects Impairments of tangible assets ......................................................... Impairments of intangible assets ...................................................... Reversals of tangible assets............................................................... Reversals of intangible assets ........................................................... Impairments (reversal) net of the relevant tax effects Impairments of tangible assets ......................................................... Impairments of intangible assets ...................................................... Reversals of tangible assets .............................................................. Reversals of intangible assets ........................................................... 2015 4,682 530 5,212 1,837 106 1,943 2,845 424 3,269 2016 740 (1,055) (385) (700) 216 (315) (120) (219) 524 (740) (265) (481) Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition. The amount of goodwill outstanding at the reporting date mainly related to the Gas & Power segment. A breakdown is disclosed below. (€ million) December 31, 2015 December 31, 2016 Domestic gas market ...................................................................... European gas market ...................................................................... - of which European market .............................................................. 835 190 188 1,025 835 190 188 1,025 F-49 Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of the former Italgas SpA minorities in 2003 through a public offering (€706 million). The acquired entity engaged in the retail sale of gas to the residential sector and middle and small-sized businesses in Italy. In addition, further goodwill amounts have been allocated over the years following business combinations with small, local companies selling gas to residential customers in focused territorial reach and municipalities synergic to Eni’s activities. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU including any allocated goodwill. Goodwill allocated to the CGU European gas market, amounting to €188 million, was recorded following the business combinations of Altergaz SA (now Eni Gas & Power France SA) in France, and Nuon Belgium NV (now merged in Eni Gas & Power NV) in Belgium, which represent two stand-alone CGUs. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of both CGUs including any allocated goodwill. In assessing the recoverability of the carrying amount of the Gas & Power CGUs, including the allocated portion of goodwill, management determined the value in use of those CGUs considering the sales margin exclusively of the retail market (excluding the wholesale margins on sales to wholesalers, industrial and power generation customers). The assessment was performed considering the cash flows of the four-year plan approved by management and incorporating the perpetuity of the last year of the plan to determine the terminal value by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of 4.5% for Italy and 5.0% for Europe. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. The excess of the recoverable amount of the CGU Domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to €1,461 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 69% on average in the projected commercial margins; (ii) an increase of 10 percentage points in the discount rate; and (iii) a negative nominal growth rate of 19%. 20 Investments Equity-accounted investments (€ million) 2015 Investments in unconsolidated entities controlled by Eni . . . . . . . . . . . . . . . . . . . . Joint ventures . . . . . . . . Associates . . . . . . . . . . . . 2016 Investments in unconsolidated entities controlled by Eni . . . . . . . . . . . . . . . . . . . . Joint ventures . . . . . . . . Associates . . . . . . . . . . . . Book amount at the beginning of the year Additions and subscriptions Divestments and reimbursements Share of profit of equity- accounted investments Share of loss of equity- accounted investments Deduction for dividends Changes in the scope of consolidation Currency translation differences Other changes Book amount at the end of the year 196 1,269 1,707 3,172 175 1,275 1,403 2,853 8 93 124 225 8 1,085 63 1,156 (8) (8) (138) (138) 66 59 25 150 10 50 17 77 (18) (60) (537) (615) (8) (208) (154) (370) (92) (28) (22) (142) (2) (45) (53) (100) 15 15 5 564 569 17 74 168 259 5 12 29 46 (17) (124) (62) (203) 175 1,275 1,403 2,853 (25) (58) 30 (53) 168 2,675 1,197 4,040 In 2016, additions and share capital increases of €1,156 million related to the subscription of the share capital increase of Saipem SpA for €1,069 million. Divestments and reimbursements of €138 million primarily related to a capital reimbursement of €130 million relating to Angola LNG Ltd. F-50 Eni’s share of profit of equity-accounted investments and dividend decrease pertained to the following entities: (€ million) PetroJunín SA ........................ United Gas Derivatives Co ...... Gas Distribution Company of Thessaloniki – Thessaly SA ...... Eni BTC Ltd .......................... Eteria Parohis Aeriou Thessalias AE ........................ Unión Fenosa Gas SA ............ PetroSucre SA ........................ Unimar Llc ............................ Other investments ................... December 31, 2015 December 31, 2016 Share of profit of equity- accounted investments Deduction for dividends Eni’s interest (%) Share of profit of equity- accounted investments Deduction for dividends Eni’s interest (%) 29 20 11 59 5 26 150 40.00 33.33 49.00 100.00 49.00 50.00 26.00 50.00 21 8 90 4 13 6 142 30 14 10 6 3 2 12 77 40.00 33.33 49.00 100.00 50.00 26.00 50.00 14 10 5 30 16 25 100 Eni’s share of losses of equity-accounted investments related to the following entities: (€ million) Saipem SpA ......................................................... PetroSucre SA ...................................................... Angola LNG Ltd .................................................. PetroBicentenario SA ............................................ CARDÓN IV SA ................................................. Matrìca SpA ........................................................ Newco Tech SpA .................................................. Unión Fenosa Gas SA ........................................... Unimar Llc .......................................................... Westgasinvest Llc .................................................. Other investments ................................................. December 31, 2015 December 31, 2016 Share of loss of equity- accounted investments Eni’s interest (%) Share of loss of equity- accounted investments Eni’s interest (%) 26.00 13.60 40.00 50.00 50.00 81.59 50.00 50.00 50.01 66 469 4 17 5 25 7 1 21 615 30.76 26.00 13.60 40.00 50.00 50.00 80.00 50.00 50.00 50.01 144 92 62 26 20 4 4 3 15 370 Based on the outcome of the impairment testing of the underlying project, the book value of the investment in Petrosucre and the dividends receivable were written off (€65 million). Regarding the projects related to PetroBicentenario and Cardón IV, Eni recorded net losses of €26 million and €20 million, respectively. Losses at the equity-accounted investment of Angola LNG Ltd of €62 million (€469 million in 2015) related to pre-production expenses and operating costs associated with the start-up of the liquefaction plant and an impairment loss of €25 million; in 2015 the amount included impairment charges relating the reduced commodity prices outlook (€433 million). Other negative changes of €53 million related to the impairment of Unión Fenosa Gas SA of €84 million due to lower profitability prospects. Changes in the scope of consolidation of €569 million include the initial recognition of the retained interest in Saipem SpA of €564 million (and, in addition to this, the subscription pro-quota of the share capital increase for €1,069 million). On January 22, 2016, Eni closed the sale of a 12.503% interest in Saipem to the Italian governmental agency, CDP Equity SpA. Concurrently, a shareholder agreement between Eni and the acquiree entered into force, which established the joint control of the two parties over the target entity. Those transactions triggered loss of control of Eni over Saipem and its derecognition. The retained interest of 30.55% has been recognized as an investment in an equity-accounted joint venture with F-51 an initial carrying amount aligned to the share price at the closing date of the transaction (€4.2 per share) recognizing a loss through profit and loss of €441 million. This loss has been recognized in the Group consolidated accounts as part of gains and losses of discontinued operations. At the balance sheet date, the fair value of the Eni’s investment in Saipem, corresponding to the portion of the market capitalization, is higher than the net book value recorded in Eni’s financial statements. However, considering the volatility of the market environment where Saipem is currently engaging, management assessed the soundness of the investment book value by estimating the value in use of the investment based on the projections of future earnings and cash flows elaborated by a panel of independent sell-side analysts. That review confirmed the recoverability of the carrying amount. The net carrying amount of equity-accounted investments was related to the following entities: (€ million) Investments in unconsolidated entities controlled by Eni Eni BTC Ltd ..................................... Other investments (*) ........................... Joint ventures Saipem ............................................. Unión Fenosa Gas SA ......................... PetroJunín SA ................................... CARDÓN IV SA ............................... Gas Distribution Company of Thessaloniki – Thessaly SA ................... Lotte Versalis Elastomers Co Ltd ............ Unimar Llc ....................................... Eteria Parohis Aeriou Thessalias AE ....... PetroBicentenario SA .......................... Other investments (*) ........................... Associates Angola LNG Ltd ............................... United Gas Derivatives Co .................... Novamont SpA .................................. AET - Raffineriebeteiligungsgesellschaft mbH ............................................... PetroSucre SA ................................... Other investments (*) ........................... December 31, 2015 December 31, 2016 Net carrying amount Number of shares held Eni’s interest (%) Net carrying amount Number of shares held Eni’s interest (%) 34,000,000 100.00 273,100 44,424,000 8,605 94,839,500 16,520,000 50 35,652,008 40,000 1,591,200,000 950,000 6,667 5,727,800 50.00 40.00 50.00 49.00 50.00 50.00 49.00 40.00 13.60 33.33 25.00 33.33 26.00 96 79 175 503 174 211 109 64 57 43 27 87 1,275 1,019 113 77 123 71 1,403 2,853 106 62 168 1,497 434 211 197 150 74 42 70 2,675 916 117 77 34 53 1,197 4,040 34,000,000 100.00 3,087,679,689 273,100 44,424,000 8,605 130,491,508 19,200,000 50 30.76 50.00 40.00 50.00 49.00 50.00 50.00 40,000 40.00 1.551.760.000 950,000 6,667 1 5,727,800 13.60 33.33 25.00 33.33 26.00 (*) Each individual amount included herein was lower than €25 million. Equity-accounted investments are disclosed in note 46 — Information by industry segment and by geographical area. Carrying amounts of equity-accounted investments included differences between the purchase price of the interest acquired and the book value of the corresponding fraction of net equity amounting to €100 million related to Unión Fenosa Gas SA for €62 million and Novamont SpA for €38 million. This goodwill is supported by the profitability outlook of the acquired companies. As of December 31, 2016, the market value of the investments listed in stock markets was as follows: Saipem SpA......................................................... 3,087,679,689 30.76 0.535 1,652 Number of shares held Eni’s interest (%) Share price (€) Market value (€ million) F-52 The table below sets out the provisions for losses included in the provisions for contingencies of €151 million (€126 million at December 31, 2015), primarily related to the following equity-accounted investments: (€ million) Industria Siciliana Acido Fosforico – ISAF – SpA (in liquidation) ........................................................................................... VIC CBM Ltd ........................................................................................... Société Centrale Eletrique du Congo SA ....................................................... Agip Oleoducto de Crudos Pesados BV ........................................................ PetroBicentenario SA ................................................................................. Polimeri Europa Elastomeres France SA ....................................................... Other investments ...................................................................................... December 31, 2015 December 31, 2016 93 10 8 8 7 126 95 34 7 7 6 2 151 Additional information is included in note 48 — Other information about investments. Other investments (€ million) 2015 Investments in unconsolidated entities controlled by Eni .......... Associates .................. Other investments: ........ - valued at fair value ...... - valued at cost ............. 2016 Investments in unconsolidated entities controlled by Eni .......... Associates .................. Other investments ......... - valued at fair value ...... - valued at cost ............. Net book amount at the beginning of the year Additions Divestments and reimbursements Valuation at fair value Currency translation differences Other changes Value at the end of the year Gross book amount at the end of the year Accumulated impairment charges 14 12 1,744 245 2,015 25 10 368 257 660 3 3 5 3 8 (1,425) (10) (1,435) 49 49 (368) (31) (399) 1 21 22 (2) 6 4 8 (3) 1 6 (1) (1) 5 3 25 10 368 257 660 29 10 237 276 26 10 368 260 664 30 10 240 280 1 3 4 1 3 4 Divestments and reimbursements of the investments valued at fair value of €368 million related the sale of 2.22% interest in Snam SpA through: (i) exercise of the conversion right by the holders of convertible bonds related to 76,888,264 shares, representing approximately 2.2% of the share capital, for a total consideration of €332 million corresponding to a price of €4.32 per share and a loss recognized in profit and loss of €32 million; (ii) sale of the remaining 792,619 shares on the open market for a consideration of €4 million. F-53 The net carrying amount of other investments of €276 million (€660 million at December 31, 2015) was related to the following entities: (€ million) Investments in unconsolidated entities controlled by Eni (*) ........ Associates ............................... Other investments: - Nigeria LNG Ltd ................... - Darwin LNG Pty Ltd ............. - Snam SpA ............................. - other(*) .................................. December 31, 2015 December 31, 2016 Net carrying amount Number of shares held Eni’s interest (%) Net carrying amount Number of shares held Eni’s interest (%) 25 10 109 60 368 88 625 660 118,373 213,995,164 77,680,883 10.40 10.99 2.22 29 10 112 49 76 237 276 118,373 213,995,164 10.40 10.99 (*) Each individual amount included herein was lower than €25 million. Additional information is included in note 48 — Other information about investments. 21 Other financial assets (€ million) Receivables held for operating purposes ............................................ Securities held for operating purposes ............................................... December 31, 2015 December 31, 2016 949 77 1,026 1,785 75 1,860 Financing receivables held for operating purposes are stated net of the valuation allowance for doubtful accounts of €480 million (€347 million at December 31, 2015). (€ million) Amount at December 31, 2015 Additions Currency translation differences Amount at December 31, 2016 Reserve of allowance for doubtful accounts of financing receivables .................................................................. 347 121 12 480 Financing receivables held for operating purposes of €1,785 million (€949 million at December 31, 2015) primarily pertained to loans granted by the Exploration & Production segment (€1,471 million), the Gas & Power segment (€133 million) and Refining & Marketing and Chemical segment (€109 million). Financing receivables granted to joint ventures and associates amounted to €1,350 million (€396 million at December 31, 2015).The greatest exposure is towards the joint venture CARDÓN IV SA (Eni’s interest 50%) in Venezuela, which is currently operating and developing the Perla offshore gas field. Due to a deteriorated financial outlook of PDVSA and the continuing refinancing of the outstanding loan granted by Eni to the joint venture, the relevant operating financing receivable was reclassified to non-current assets and, as of December 31, 2016, the recoverability was assessed based on the outcome of the impairment review of the underlying industrial project. At December 31, 2016, Eni’s exposure towards the joint venture amounted to €1,054 million (€1,112 million at 31 December 2015). The receivable is accruing interest income at a rate equal to Libor plus 700 basis points as provided by the agreement between Eni and Cardón IV, which were approved by Eni’s Board of Directors with a cap to the financing up to $1.5 billion. The loan will be repaid through the cash flows generated by the gas produced by the field and supplied to the Venezuelan State-owned company, PDVSA, on the base of a gas sale agreement expiring in 2036. In assessing the recoverability of the financing receivable granted to the joint venture Cardón IV, management has evaluated that the loan approximates the provision of equity capital, and its recoverability mainly depends upon the capacity of the joint venture to pay down the loan with its cash flows from F-54 operations. Therefore, the recoverability of the financing receivable has been assessed based on the present value of the project future cash flows, as part of the project impairment review, discounted by using the Eni’s WACC for Venezuela, which takes into account the business risk and the country risk. The project VIU was then compared to the sum of the book values of Eni’s interest in Cardón IV and of the financing receivable with the VIU exceeding the assets book values. Furthermore, given the counterparty risk considering the deteriorated financial situation in Venezuela, the value-in-use has been stress-tested assuming either: i) a two-year delay in the payment of gas supplies to the joint venture by PDVSA; ii) the collection of proceeds on only 70% of the gas sales in line with the current securitization agreements. Under both of these scenarios, the value-in-use retained a headroom over the assets book values. Allowances for doubtful accounts of financing receivables of €121 million included an impairment for €93 million of a financing receivable granted to Matrìca SpA (Eni’s share 50%), a joint venture with Novamont SpA for the production of chemical products from renewable sources, to reflect the repayment capacity of the venture considering the industrial risks of the project. Financing receivables held for operating purposes in currencies other than euro amounted to €1,606 million (€649 million at December 31, 2015). Financing receivables held for operating purposes due beyond five years amounted to €1,519 million (€623 million at December 31, 2015). The valuation at fair value of financing receivables of €1,799 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from -0.2% to 2.6% (0% and 2.7% at December 31, 2015). Securities of €75 million (€77 million at December 31, 2015), designated as held-to-maturity investments, are listed bonds issued by sovereign states for €71 million (€70 million at December 31, 2015) and by the European Investment Bank for €4 million (€7 million at December 31, 2015). 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 ................................. Spain ............................... Ireland .............................. Iceland ............................. Poland .............................. Slovenia ............................ Belgium ............................ Floating rate bonds Italy ................................. Mozambique ...................... Total sovereign states ............ European Investment Bank ................................ 24 15 9 3 3 2 2 11 2 71 4 75 24 14 8 3 2 2 2 11 2 68 4 72 26 15 9 3 3 2 2 11 2 73 4 77 from 0.45 to 4.75 from 2017 to 2025 from 1.40 to 4.30 from 2019 to 2020 from 4.40 to 4.50 from 2018 to 2019 2020 2020 2020 2018 2.50 4.20 4.13 1.40 Baa2 BBB- Baa2 BBB+ A3 A+ A3 BBB+ A2 BBB+ A AA Baa3 Aa3 from 2018 to 2019 from 2017 to 2019 Baa2 Caa3 BBB- B- 2018 Aaa AAA Securities have a maturity within five years (beyond five years for €1 million at December 31, 2015). The fair value of securities was derived from quoted market prices. Receivables with related parties are described in note 47 — Transactions with related parties. F-55 22 Deferred tax assets Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for €4,286 million (€3,355 million at December 31, 2015). (€ million) Deferred tax assets .......................... Provisions for impairments .............. Amount at December 31, 2015 Additions Deductions Currency translation differences 8,952 (5,099) 3,853 2,994 (667) 2,327 (1,208) 254 (954) 185 (80) 105 Other changes (1,511) (30) (1,541) Amount at December 31, 2016 9,412 (5,622) 3,790 Deferred tax assets related for €1,690 million (€1,911 million at December 31, 2015) to the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes. Those assets were recorded on the pre-tax loss of the year and on the recognition of deferred deductible expenses within the limits of the amounts expected to be recovered in future years based on availability of expected future taxable profit. Additions to the impairment provision of €667 million were explained by projections of lower future taxable profit at Italian subsidiaries (€433 million). Deferred tax assets are further described in note 32 — Deferred tax liabilities. Income taxes are described in note 43 — Income taxes. 23 Other non-current assets (€ million) Tax receivables from: - Italian tax authorities December 31, 2015 December 31, 2016 - income tax ............................................................................... - interest on tax credits ................................................................. - non-Italian tax authorities ............................................................. Other receivables: - related to divestments ................................................................... - other non-current ......................................................................... Fair value of derivative financial instruments ..................................... Other asset .................................................................................... 44 63 107 287 394 567 46 613 218 533 1,758 73 64 137 365 502 222 52 274 108 464 1,348 Receivables from divestments amounted to €222 million (€567 million at December 31, 2015) and included the long-term portion of €166 million (€463 million at December 31, 2015) of a receivable related to the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunayGas in 2008 based on the agreements defined between the international partners of the North Caspian Sea PSA and the Kazakh government, which enacted a new contractual framework and a new setup for managing project operations. The repayment of the first of the three installments of the receivable took place in the fourth quarter of 2016 with the achievement of the agreed target production level. The receivable accrues interest income at market rates. The current portion of the receivable is indicated in note 11 — Trade and other receivables. The fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments. F-56 Other non-current assets amounted to €464 million (€533 million at December 31, 2015), of which €113 million (€277 million at December 31, 2015) were deferred costs of take-or-pay gas volumes in connection with the Company’s long-term supply contracts. The amount was recognized due to the obligation to pay the contractual price of the volumes of gas, which the Company failed to collect up to the minimum contractual take in previous reporting periods in order to fulfill the take-or-pay clause provided by the relevant long-term supply contracts. The Company is entitled to off-take the prepaid volumes in future years alongside contract execution, up to contract expiration or in a shorter term as the case may be. Those deferred costs, which are equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-year impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. In 2016, based on this accounting, an impairment of €31 million was recorded. The reduction in the amount of the deferred costs at the reporting date compared to 2015 was due to the reclassification to other current assets of volumes expected to be recovered by 2017 (€133 million). A portion of the deferred costs has remained classified non-current, because the Company plans to lift the prepaid quantities beyond the term of 12 months. In spite of weak market conditions in the European gas sector due to sluggish demand growth and strong competitive pressures fuelled by oversupplies, management plans to recover volumes underlying the deferred cost within the plan horizon. Transactions with related parties are described in note 47 — Transactions with related parties. Current liabilities 24 Short-term debt (€ million) Commercial papers ......................................................................... Banks ........................................................................................... Other financial institutions .............................................................. December 31, 2015 December 31, 2016 4,962 142 616 5,720 2,738 155 503 3,396 The decrease in short-term debt of €2,324 million primarily related to net reimbursements for €2,645 million and, as increase, currency translation differences relating to foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €452 million. Commercial papers of €2,738 million (€4,962 million at December 31, 2015) were issued by the Group’s financial subsidiaries Eni Finance USA Inc for €1,750 million (€2,189 million at December 31, 2015) and Eni Finance International SA for €988 million (€2,773 million at December 31, 2015). The breakdown by currency of short-term debt is provided below: (€ million) December 31, 2015 December 31, 2016 Euro ............................................................................................. U.S. dollar ..................................................................................... Other currencies ............................................................................. 3,056 2,616 48 5,720 1,405 1,982 9 3,396 As of December 31, 2016, the weighted average interest rate on short-term debt was 0.9% (0.6% as of December 31, 2015). As of December 31, 2016, Eni retained undrawn committed and uncommitted borrowing facilities amounting to €41 million and €12,267 million, respectively (€40 million and €12,708 million at December 31, 2015, respectively). Those facilities bore interests and charges for undrawn that reflect prevailing market conditions. As of December 31, 2016, Eni did not report any default on covenants or other contractual provisions in relation to borrowing facilities. F-57 Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount. Payables due to related parties are described in note 47 — Transactions with related parties. 25 Trade and other payables (€ million) December 31, 2015 December 31, 2016 Trade payables ............................................................................... Advances ...................................................................................... Other payables ............................................................................... - related to capital expenditures ......................................................... - others .......................................................................................... 9,605 637 1,884 2,816 4,700 14,942 11,038 526 2,158 2,981 5,139 16,703 The increase in trade payables amounting to €1,433 million primarily related to the Gas & Power segment (€985 million). Down payments and advances for €526 million (€637 million at December 31, 2015) related to the Refining & Marketing business line for €263 million (€253 million at December 31, 2015) and to the Exploration & Production segment for €153 million (€71 million at December 31, 2015). Other payables were as follows: (€ million) December 31, 2015 December 31, 2016 Payables related to capital expenditures due to Suppliers in relation to investing activities ......................................... Joint venture operators in exploration and production activities ........... Other ............................................................................................ Other payables Joint venture operators in exploration and production activities ........... Employees ..................................................................................... Social security entities ..................................................................... Non-financial government entities .................................................... Other ............................................................................................ 1,544 283 57 1,884 1,750 207 100 5 754 2,816 4,700 1,835 219 104 2,158 2,057 180 94 6 644 2,981 5,139 Because of the short-term maturity and conditions of remuneration of trade payables, the fair value approximated the carrying amount. Payables due to related parties are described in note 47 — Transactions with related parties. 26 Income tax payable (€ million) Italian subsidiaries ......................................................................... Non-Italian subsidiaires .................................................................. December 31, 2015 December 31, 2016 65 366 431 97 329 426 Income tax payable is described in note 43 — Income taxes. F-58 27 Other tax payable (€ million) Excise and customs duties ............................................................... Other taxes and duties .................................................................... December 31, 2015 December 31, 2016 716 738 1,454 634 659 1,293 28 Other current liabilities (€ million) December 31, 2015 December 31, 2016 Fair value of derivatives financial instruments ................................... Other liabilities .............................................................................. 4,261 451 4,712 2,108 491 2,599 Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments. Other current liabilities of €491 million (€451 million at December 31, 2015) included the current portion of advances received from Suez following a long-term agreement for supplying natural gas and electricity for €73 million (€76 million at December 31, 2015). Non-current portion is disclosed in note 33 — Other non-current liabilities. Advances cashed in by gas customers were utilized in 2016 for €10 million (versus €11 million at the opening balance). Those customers off-took lower volumes than the contractual minimum take provided by the relevant long-term supply contract in previous reporting periods, paying Eni the relevant cash advance. Transactions with related parties are described in note 47 — Transactions with related parties. Non-current liabilities 29 Long-term debt and current portion of long-term debt (€ million) Maturity range 2015 2016 Current maturity 2017 2018 2019 2020 2021 After Total At December 31, Long-term maturity Banks ............................ 2017 – 2032 484 Ordinary bonds .............. 2017 – 2043 17,608 19,003 2,959 1,168 2,503 2,422 Convertible bonds ........... Other financial institutions ..................... 2017 – 2031 864 1,485 4,286 3,920 2022 272 206 339 383 48 341 940 840 4,014 9,011 16,044 383 383 123 22,073 23,843 3,279 2,080 4,038 2,909 1,284 10,253 20,564 171 50 19 48 3 3 Long-term debt and current portion of long-term debt of €23,843 million (€22,073 million at December 31, 2015) increased by €1,770 million. The increase comprised new issuance of €4,202 million net of repayments made for €2,323 million and, as decrease, currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €28 million. Debt due to other financial institutions of €171 million (€206 million at December 31, 2015) included €29 million of finance lease transactions (€26 million at December 31, 2015). Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the maintenance of certain financial ratios based on the Consolidated Financial F-59 Statements of Eni or a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees would be required to be agreed upon with the European Investment Bank. In addition, Eni entered into long and medium-term facilities with Citibank Europe Plc providing for conditions similar to those applied by the European Investment Bank. At December 31, 2016, debts subjected to restrictive covenants amounted to €1,953 million (€2,127 million at December 31, 2015). Eni complied with those covenants. Ordinary bonds of €19,003 million (€17,608 million at December 31, 2015) consisted of bonds issued within the Euro Medium Term Notes Program for a total of €16,528 million and other bonds for a total of €2,475 million. The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2016: Discount on bond issue and accrued expense Maturity Rate % Total Currency from to from to (€ million) Amount Issuing entity Euro Medium Term Notes Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni Finance International SA ..... Eni Finance International SA ..... Eni Finance International SA ..... Other bonds Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni SpA ............................... Eni USA Inc .......................... 1,500 1,250 1,200 1,000 1,000 1,000 1,000 1,000 1,000 900 800 800 750 750 700 600 527 395 170 16,342 1,109 427 333 215 379 2,463 18,805 15 6 17 36 31 26 19 6 6 (7) 1 (3) 13 6 (6) 14 5 1 186 10 3 1 (2) 12 198 1,515 1,256 1,217 1,036 1,031 1,026 1,019 1,006 1,006 893 801 797 763 756 700 594 541 400 171 16,528 1,119 430 333 216 377 2,475 19,003 EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR GBP EUR YEN EUR USD USD EUR USD 2019 2017 2025 2020 2018 2029 2020 2026 2023 2024 2021 2028 2019 2024 2022 2028 2021 2043 2037 2017 2020 2040 2017 2027 4.125 4.750 3.750 4.250 3.500 3.625 4.000 1.500 3.250 0.625 2.625 1.625 3.750 1.750 0.750 1.125 6.125 5.441 2.810 4.875 4.150 5.700 variable 7.300 4.750 3.750 1.955 2018 2017 2019 As of December 31, 2016, ordinary bonds maturing within 18 months of €3,724 million were issued by Eni SpA for €3,622 million and by Eni Finance International SA for €102 million. During 2016, Eni SpA issued new bonds for €2,984 million. F-60 The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, 2016: (€ million) Issuing entity Eni SpA ............................ Discount on bond issue and accrued expense Total Currency Maturity Rate% (17) (17) 383 383 EUR 2022 0.000 Amount 400 400 In 2016, Eni issued a non-dilutive equity-linked bond for a total nominal value of €400 million with a redemption value linked to the market price of Eni’s shares. The bondholders will have “conversion” rights at certain times and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, the issue and the conversion of the bonds will not give right to any share of Eni and there will be no dilution for shareholders. To hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The bonds will have a six-year maturity and will pay no interest and, accordingly, the coupon will be equal to 0%. The bonds were issued at a price equal to 100.5% of par and will be redeemed at par at maturity, unless previously converted or redeemed under their terms. The initial conversion price for the bonds has been set at €17.6222, representing a 35% premium above the share reference price of €13.0535 determined as the arithmetic average of the daily volume-weighted average prices of an ordinary share of Eni on the Milan Stock Exchange over a period of seven consecutive scheduled trading days starting from 7 April 2016. The settlement and closing took place on 13 April 2016. The convertible bond is measured at amortized cost. The conversion option, embedded in the financial instrument issued, and the call option on Eni’s shares acquired are valued at fair value with effects recognized through profit and loss. The bond convertible into ordinary shares of Snam SpA, amounting to €339 million as of 31 December 2015, expired on 18 January 2016. Following the exercise of the conversion rights, Eni delivered to the bondholders 76,888,264 shares ordinary representing approximately 2.20% of the share capital of Snam SpA. The residual bonds, amounting to €3.4 million, for which it was not exercised the conversion rights, were redeemed for cash. The following table provides a breakdown by currency of long-term debt, its current portion and the related weighted average interest rates. Euro ............................................................. U.S. dollar ..................................................... British pound ................................................. Japanese yen .................................................. December 31, 2015 (€ million) Average rate (%) December 31, 2016 (€ million) Average rate (%) 19,623 1,660 629 161 22,073 3.2 5.0 5.3 2.6 21,545 1,587 540 171 23,843 2.7 5.2 5.3 2.6 As of December 31, 2016, Eni retained undrawn long-term committed borrowing facilities of €6,236 million (€6,577 at December 31, 2015), of which €700 million due in 2017. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. As of 31 December 2016, Eni did not utilize any of its currently committed long-term borrowing facilities (€1 million at December 31, 2015) considering the amount of the liquidity reserves retained by the Company. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €16.3 billion were drawn as of December 31, 2016. The Group has credit ratings of BBB+ outlook stable and A-2, respectively for long and short-term debt, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked to the Company’s industrial fundamentals and trends in the trading environment and, in addition, to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. F-61 Fair value of long-term debt, including the current portion of long-term debt amounted to €25,358 million (€23,899 million at December 31, 2015): (€ million) December 31, 2015 December 31, 2016 Ordinary bonds ............................................................................. Convertible bonds .......................................................................... Banks ........................................................................................... Other financial institutions .............................................................. 18,984 341 4,356 218 23,899 20,501 435 4,244 178 25,358 Fair value of financial debt was calculated by discounting the expected future cash flows at discount rates ranging from -0.2% to 2.6% (0% and 2.7% at December 31, 2015). At December 31, 2016, Eni did not pledge restricted deposits as collateral against its borrowings. Information on net borrowings In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS as endorsed by IASB less: cash, cash equivalents, held-for-trading securities and other financial assets, and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and available-for-sale securities not related to operations. Held-for-trading securities and other financial assets are part of a strategic reserve of liquidity that management has established by reinvesting proceeds from the Group disposal plans and is intended to provide a certain degree of financial flexibility in case of a prolonged price downturn, tight financial markets or in view of other Company’s purposes. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Available-for-sale securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities. Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according 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 calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies. December 31, 2015 December 31, 2016 (€ million) A. Cash and cash equivalents ...................... B. Held-for-trading financial assets ............... C. Available-for-sale financial assets .............. D. Liquidity (A+B+C) ............................... E. Financing receivables .............................. F. Short-term debt towards banks ................. G. Long-term debt towards banks ................ H. Bonds ............................................... I. Short-term debt towards related parties ....... L. Other short-term liabilities ...................... M. Other long-term liabilities ...................... N. Total borrowings (F+G+H+I+L+M) ......... O. Net borrowings (N-D-E) ......................... Current 5,209 5,028 10,237 685 142 455 2,176 208 5,370 45 8,396 (2,526) Non- current 3,465 15,771 161 19,397 19,397 Total 5,209 5,028 10,237 685 142 3,920 17,947 208 5,370 206 27,793 16,871 Current 5,674 6,166 238 12,078 385 155 272 2,959 191 3,050 48 6,675 (5,788) Non- current 4,014 16,427 123 20,564 20,564 Total 5,674 6,166 238 12,078 385 155 4,286 19,386 191 3,050 171 27,239 14,776 F-62 Financial assets held for trading of €6,166 million (€5,028 million at December 31, 2015) related to Eni SpA for €6,062 and to Eni Insurance DAC for €104 million. For further information see note 9 — Financial assets held for trading. Available-for-sale securities of €238 million were held for non-operating purposes and related to Eni Insurance DAC. Furthermore, Eni held certain held-to-maturity and available-for-sale securities destined to operating purposes amounting to €75 million (€359 million at December 31, 2015). These securities are excluded from the calculation above. The decrease of €282 million was mainly due to the reclassification of securities retained by Eni Insurance DAC to securities held for non-operating purposes. In previous reporting periods, those securities were committed to fund the loss reserve of the insurance company. The change in the destination of those assets was permitted by the entry into force from January 1, 2016, of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale. Current financing receivables of €385 million (€685 million at December 31, 2015) were held for non-operating purposes. At the reporting date, the Company held financing receivables which were destined to operating purposes amounting to €158 million (€1,622 million at December 31, 2015), of which €28 million (€1,135 million at December 31, 2015) were in respect of financing granted to joint ventures and affiliates which executed capital projects and investments on behalf of Eni’s Group companies. The decrease of €300 million was mainly due to the repayment of receivables related to margins on derivatives of Eni Trading & Shipping SpA for €457 million and, as increase, the reclassification to financial receivables of €287 million as a consequence of the adoption starting from January 1, 2016, of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale. 30 Provisions for contingencies (€ million) Provision for decommissioning and social projects .......................... Environmental provision .... Provision for litigations ...... Provision for taxes ............ Loss adjustments and actuarial provisions for Eni’s insurance companies ......... Provision for redundancy incentives ....................... Provision for onerous contracts ........................ Provision for losses on investments ..................... Provision for OIL insurance cover ............................. Provision for disposal and restructuring ................... Provision for green certificates ...................... Other (*) ......................... Carrying amount at December 31, 2015 New or increased provisions Initial recognition and changes in estimates Accretion discount Utilization Reversal of unutilized provisions Currency translation differences Other changes Carrying amount at December 31, 2016 8,998 2,737 1,725 484 323 201 273 128 72 80 190 164 15,375 (647) 297 8 3 3 (336) (249) (1,099) (30) (184) (13) (103) (1) (37) (25) (2) (8) (6) (11) 55 1 21 (7) 2 53 (3) 175 1 16 (8) (1) (7) (16) (11) (2) 8,419 2,691 954 732 207 176 165 153 88 58 235 177 258 52 1 6 41 16 7 213 1,006 (647) 1 312 (13) (72) (2,115) (1) (7) (109) (175) (51) 1 252 13,896 4 74 (*) Each individual amount included herein was lower than €50 million. The Group makes full provision for the future costs of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The decommissioning provisions at the reporting date amounted to €8,419 million and included future costs for social projects. Those for provisions comprised the discounted estimated costs the Company expects to incur that F-63 decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration of the Exploration & Production segment for €7,901 million. Negative estimates’ revisions of €647 million were primarily due to a rise in the discount rate curve in particular for the U.S. dollar and to the revision of previous estimates of decommissioning costs, partially offset by new provisions of the year. The accretion discount recognized in the profit and loss account for €297 million was determined by adopting discount rates ranging from -0.01% to 5.8% (from 0.2% to 4.6% at December 31, 2015). Main expenditures associated with decommissioning operations are expected to be incurred over a 40-year period. Provisions for environmental risks of €2,691 million included the estimated costs for environmental remediation and restoration of soil and groundwater in areas owned or under concession where the Group conducted in the past industrial operations which were progressively divested, shut down, dismantled or restructured. The provision has been accrued because at balance sheet date there is a legal or constructive obligation for Eni to carry out cleaning-up operations and the expected costs can be estimated reliably. The provision includes the expected charges associated with strict liability related to obligations of restoring the contaminated sites that met the parameters set by the law at the time when the pollution occurred or because Eni assumed the liability of third operators when took over the ownership of the site. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to perform certain cleaning-up and restoration projects and reliable cost estimation is available. At December 31, 2016, environmental provision primarily related to Syndial SpA for €2,211 million and to the Refining & Marketing business line for €364 million. Additions of €235 million primarily related to Syndial SpA for €110 million and to the Refining & Marketing business line for €99 million. Utilizations of €249 million primarily related to the Refining & Marketing business line for €124 million Syndial SpA for €89 million. Provisions for litigations of €954 million comprised the expected liabilities associated with legal proceedings and out of court proceedings arising from contractual claims, contract renegotiations, including arbitration, fines and penalties due to antitrust proceedings and administrative matters. These provisions represented the Company’s best estimate of the expected probable liabilities associated with pending litigation and commercial proceedings and primarily related to the Gas & Power segment for €546 million and the Exploration & Production segment for €261 million. Additions and utilizations of €177 million and €1,099 million, respectively, mainly related to the Gas & Power segment and were recognized to take account of gas price revisions at long-term supply and sale contracts, including the settlement of certain arbitrations. Other changes of €175 million related to the reclassification to provisions for litigation of the expected liability incurred in connection with a dispute between EniPower and an Italian authority for the national grid on the use of certain allowances for the fulfillment of the obligations concerning GHG emissions at certain Eni’s plant for the production of co-generative power. Provisions for taxes of €732 million included the estimated charges that the Company expects to incur for unsettled tax claims in connection with uncertainties in the application of tax rules at certain Italian and foreign subsidiaries in the Exploration & Production segment (€704 million). Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC of €207 million represented the estimated liabilities accrued on the basis for third parties claims. Against such liability was recorded a receivable of €147 million recognized towards insurance companies for reinsurance contracts. Provisions for redundancy incentives of €176 million were recognized due to a restructuring program involving the Italian personnel related to past reporting periods. Provisions for onerous contracts of €165 million related to the execution of contracts where the expected costs exceed the relevant benefits. In particular, the provision comprised the estimated expected losses on unutilized infrastructures for gas transportation and on a regasification project. Provisions for losses on investments of €153 million were made with respect to certain investees for which expected or incurred losses exceeded carrying amounts. Provisions for the OIL mutual insurance scheme of €88 million included the estimated future increase of insurance premiums which will be charged to Eni in the next five years and that accrued at the reporting date because of the effective accident rate occurred in past reporting periods. F-64 Provisions for disposal and restructuring of €58 million essentially related to the Chemical business line (€32 million) and to Syndial SpA (€14 million). 31 Provisions for employee benefits (€ million) December 31, 2015 December 31, 2016 TFR ............................................................................................. Foreign defined benefit plans ........................................................... Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans ...................................................................... Other foreign long-term benefit plans ............................................... 281 533 156 153 1,123 298 276 124 170 868 Provisions for benefits upon termination of employment primarily related to a provisions accrued by Italian companies for employee retirement, determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code. The benefit is paid upon retirement as a lump sum, the amount of which corresponds to the total of the provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in the law regime, from January 1, 2007, accruing benefits have been contributing to a pension fund or a treasury fund held by the Italian administration for post-retirement benefits (INPS). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, contributions of future TFR provisions to pension funds or the INPS treasury fund determines that these amounts will be treated in accordance to a defined contribution scheme. Amounts already accrued before January 1, 2007 continue to be accounted for as defined benefits to be assessed based on actuarial assumptions. Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and the United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement. Group companies provide healthcare benefits. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company for retired managers. Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers, jubilee awards and a defined benefit plan for certain employees engaged in the retail gas activity. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses that will be granted to those managers who will achieve certain individual performance goals weighted with the likelihood that the Company delivers the planned profitability targets. The benefit has a three-year vesting period and incurs when the commitment arises towards Eni’s management, based on the achievement of corporate goals. The estimate is subject to adjustments in subsequent years based on the results achieved and the update of the result forecasted (above or below the target). This benefit is applied pro-rata temporis over the three-year period depending on the results of the performance parameters. Provisions for the long-term incentive scheme are assessed on the basis of the estimated trends of a performance indicator as benchmarked against a group of international oil companies. Both of these incentive schemes normally vest over a three-year period. Jubilee awards are benefits due following the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration. The a defined benefit plan for certain employees engaged in the retail gas activity is a supplementary pension plan set up in the 70’s and managed by the Italian national agency for welfare. This fund, previously considered a defined contribution plan, became a defined benefit plan due to certain regulatory changes. The Eni personnel engaged in the gas activity came from the merger of the former “Italgas Più”. F-65 Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following: (€ million) December 31, 2015 December 31, 2016 Foreign defined benefit plans Fisde and other foreign medical plans Other long-term benefit plans TFR Foreign defined benefit plans Fisde and other foreign medical plans Other long-term benefit plans Total TFR (5) 4 (19) (25) 6 (26) (9) 1 1 (56) Present value of benefit liabilities at beginning of year .................................. 376 1,282 41 Current cost ........................................ 41 Interest cost ........................................ (20) Remeasurements: ................................. - actuarial (gains) losses due to changes in demographic assumptions ........................ - actuarial (gains) losses due to changes in financial assumptions ............................. - experience (gains) losses ....................... (26) Past service cost and (gains) losses settlements .......................................... Plan contributions: - employee contributions .......................... Benefits paid ....................................... Reclassification to discontinued operations and asset held for sale ............................ Currency translation differences and other changes .............................................. Present value of benefit liabilities at end of year (a) .............................................. 281 1,240 Plan assets at beginning of year ................ 710 24 Interest income .................................... Return on plan assets ............................ (11) Past service cost and (gains) losses settlements .......................................... Administration expenses paid .................. Plan contributions: ............................... - employee contributions .......................... - employer contributions .......................... Benefits paid ....................................... Reclassification to discontinued operations and asset held for sale ............................ Currency translation differences and other changes .............................................. Plan assets at end of year (b) .................... Net liability recognized at end of year (a-b) .. 281 (1) 42 1 41 (24) 53 707 533 (181) (86) (52) 141 2 174 2 3 (1) 191 54 1 (17) 2,023 281 1,240 28 34 22 97 6 51 (64) 19 156 2 3 (17) 153 56 1 1 (5) (2) (2) (1) (2) 2 (3) (1) (14) (3) 13 (7) (53) (8) 11 (51) 10 30 (6) (2) (14) 2 3 1 1 (141) (8) (7) 1 1 (33) (6) (31) 2 1 (3) Total 1,830 86 44 25 (7) 41 (9) (8) 1 1 (78) (23) (41) (297) 9 5 157 (390) (16) (7) (413) 156 153 1,830 298 710 24 (11) (1) 42 1 41 (24) (86) 53 707 156 153 1,123 298 895 707 20 42 (3) 25 1 24 (19) (153) 619 276 124 170 124 170 1,487 707 20 42 (3) 25 1 24 (19) (153) 619 868 Foreign defined benefit plans amounting to €276 million (€533 million at December 31, 2015) primarily related to pension plans for €184 million (€402 million at December 31, 2015). Foreign employee benefit plans included the liability attributable to joint venture partners operating in exploration and production activities of €60 million (€281 million at December 31, 2015). Eni recorded a receivable for an amount equivalent to such liability. Other employee benefit plans of €170 million (€153 million at December 31, 2015) related to: (i) defined benefit plans for €12 million (€11 million at December 31, 2015) related to the Gas fund; and (ii) long-term benefit plans for €158 million (€142 million at December 31, 2015) of which deferred monetary incentive plans for €99 million (€87 million at December 31, 2015), jubilee awards for €28 million (€27 million at December 31, 2015), long-term incentive plan for €14 million (€6 million at December 31, 2015) and other foreign long-term plans for €17 million (€22 million at December 31, 2015). F-66 Costs charged to the profit and loss account consisted of the following: (€ million) 2015 Current cost ................................. Past service cost and (gains) losses on settlements .................................. Interest cost (income), net: - interest cost on liabilities ................ - interest income on plan assets .......... Total interest cost (income), net ........ - of which recognized in “Payroll and related cost” ................................. - of which recognized in “Financial income (expense)” ......................... Remeasurements for long-term plans .. Other costs/Administration expenses paid ........................................... Total .......................................... - of which recognized in “Payroll and related cost” ................................. - of which recognized in “Financial income (expense)” ......................... 2016 Current cost ................................. Past service cost and (gains) losses on settlements .................................. Interest cost (income), net: - interest cost on liabilities ................ - interest income on plan assets .......... Total interest cost (income), net ........ - of which recognized in “Payroll and related cost” ................................. - of which recognized in “Financial income (expense)” ......................... Remeasurements for long-term plans Total .......................................... - of which recognized in “Payroll and related cost” ................................. - of which recognized in “Financial income (expense)”.......................... Foreign defined benefit plans Fisde and other foreign medical plans Other long-term benefit plans TFR 41 (9) 41 (24) 17 17 1 50 33 17 28 (4) 34 (20) 14 14 38 24 14 2 (1) 3 3 3 4 1 3 2 2 3 3 3 7 4 3 54 13 1 1 1 (17) 51 51 56 (3) 1 1 1 (1) 53 53 6 6 6 6 6 6 6 6 6 6 Total 97 3 51 (24) 27 1 26 (17) 1 111 85 26 86 (5) 44 (20) 24 1 23 (1) 104 81 23 Costs recognized in other comprehensive income consisted of the following: (€ million) Remeasurements Actuarial (gains)/losses due to changes in demographic assumptions .............................. Actuarial (gains)/losses due to changes in financial assumptions .... Experience (gains) losses ............... Return on plan assets ................... 2015 Foreign defined benefit plans Fisde and other foreign medical plans Total TFR Foreign defined benefit plans TFR 2016 Fisde and other foreign medical plans Other benefit plans Total (5) 4 (19) 11 (9) (26) (26) (5) (2) 6 (48) 11 (36) 11 10 19 (2) 30 (6) (42) (20) 2 (3) (1) (1) (2) (14) (17) 1 1 2 (4) 40 (10) (42) (16) F-67 Plan assets consisted of the following: (€ million) December 31, 2015 Plan assets with a quoted market price ... Plan assets without a quoted market price .................................................. December 31, 2016 Plan assets with a quoted market price ... Plan assets without a quoted market price .................................................. Cash and cash equivalents Equity securities Debt securities Real estate Derivatives Investment funds Assets held by insurance company Other Total 41 96 254 10 41 105 96 49 254 270 10 11 105 49 270 11 2 2 1 1 2 2 65 65 23 6 29 14 3 17 273 701 6 273 707 101 616 3 101 619 Plan assets are generally managed by external asset managers pursuing investment strategies, defined by Eni’s companies, with the aim of ensuring that assets are sufficient to pay the benefits. For this purpose, the investments are aimed at maximizing the expected return and limit the risk level through proper diversification. The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2016 consisted of the following: TFR Foreign defined benefit plans FISDE and other foreign medical plans Other long-term benefit plans 2015 Discount rate .................................................. Rate of compensation increase .......................... Rate of price inflation ...................................... Life expectations on retirement at age 65 ............. 2016 Discount rate .................................................. Rate of compensation increase .......................... Rate of price inflation ...................................... Life expectations on retirement at age 65 ............. (%) (%) (%) (years) (%) (%) (%) (years) 2.0 3.0 2.0 1.0 2.0 1.0 0.8-15.3 2.0-13.3 0.6-9.7 13-24 0.6-17.5 1.0-15.0 0.6-13.5 13-24 2.0 2.0 24 1.0 1.0 24 0.5-2.0 2.0 0.0-1.0 1.0 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 2015 Discount rate ......................................... Rate of compensation increase ................ Rate of price inflation ............................. Life expectations on retirement at age 65 ... 2016 Discount rate ......................................... Rate of compensation increase ................ Rate of price inflation ............................. Life expectations on retirement at age 65 ... (%) (%) (%) (years) (%) (%) (%) (years) 2.0 2.0-3.0 2.0 21-22 1.0-2.0 1.0-3.0 1.0-1.8 21-22 0.8-3.8 2.5-4.7 0.6-3.0 22-24 0.6-2.7 2.3-3.8 0.6-3.4 23-24 3.5-15.3 5.0-13.3 3.5-9.7 13-15 3.5-17.5 5.0-15.0 3.5-13.5 13-15 9.4-9.5 10.0 5.5-8.2 7.3-8.1 7.8-10.0 5.0-5.5 Foreign defined benefit plans 0.8-15.3 2.0-13.3 0.6-9.7 13-24 0.6-17.5 1.0-15.0 0.6-13.5 13-24 The discount rate used was determined on the base of corporate bond yields (rating AA) in countries with a significant market, or in the absence, of government bond yields. The demographic tables adopted are those used by each country for the assessments of IAS 19. The inflation rate is consistent with the discount rate adopted determined based on the inflation rate implicit in the securities financial markets. F-68 The effects of a possible change in the main actuarial assumptions at the end of the year are listed below: (€ million) 0.5% Increase 0.5% Decrease 0.5% Increase 0.5% Increase 0.5% Increase 0.5% Increase Discount rate Rate of price inflation Rate of increases in pensionable salaries Healthcare cost trend rate Rate of increases to pensions in payment December 31, 2015 Effect on DBO TFR .................................................. Foreign defined benefit plans ................... FISDE and other foreign medical plans ...... Other long-term benefit plans ................................................. December 31, 2016 Effect on DBO TFR .................................................. Foreign defined benefit plans ................... FISDE and other foreign medical plans ...... Other long-term benefit plans ................................................. (17) (75) (8) (2) (15) (57) (7) (2) 18 84 9 2 16 66 8 2 12 46 1 10 33 1 26 15 9 8 54 23 The sensitivity analysis was performed based on the results for each plan through assessments calculated considering modified parameters. The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €87 million, of which €52 million related to defined benefit plans. The following is an analysis by maturity date of the liabilities for employee benefit plans: (€ million) December 31, 2015 2016 .............................................................. 2017 .............................................................. 2018 .............................................................. 2019 .............................................................. 2020 .............................................................. 2021 and thereafter ......................................... December 31, 2016 2017 .............................................................. 2018 .............................................................. 2019 .............................................................. 2020 .............................................................. 2021 .............................................................. 2022 and thereafter ......................................... TFR 4 5 6 8 10 248 13 14 15 17 19 220 Foreign defined benefit plans FISDE and other foreign medical plans Other long-term benefits 31 33 43 34 37 355 31 44 33 33 38 97 5 5 5 5 6 130 5 5 5 5 5 99 31 37 57 2 2 47 37 59 52 3 3 42 The weighted average duration of the liabilities for employee benefit plans was the following: 2015 Weighted average duration ........... 2016 Weighted average duration ........... (years) (years) Foreign defined benefit plans FISDE and other foreign medical plans Other long-term benefits 16.5 17.9 14.1 13.9 4.3 3.4 TFR 12.0 10.3 F-69 32 Deferred tax liabilities Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for €4,286 million (€3,355 million at December 31, 2015). (€ million) Amount at December 31, 2015 Additions Deductions Currency translation differences Other changes Amount at December 31, 2016 7,425 1,796 (1,486) 229 (1,297) 6,667 Deferred tax assets and liabilities consisted of the following: (€ million) December 31, 2015 December 31, 2016 Deferred tax liabilities ................................................................. Deferred tax assets available for offset ........................................... Deferred tax assets not available for offset ..................................... Net deferred tax liabilities ............................................................ 10,780 (3,355) 7,425 (3,853) 3,572 10,953 (4,286) 6,667 (3,790) 2,877 Net deferred tax liabilities of €2,877 million (€3,572 million at December 31, 2015) included the recognition of the deferred tax effect against equity of: (i) the fair value measurement of derivatives designated as cash flow hedge (deferred tax liabilities for €57 million); (ii) the revaluation of defined benefit plans (deferred tax liabilities for €13 million); and (iii) the fair value measurement of available-for-sale securities (deferred tax liabilities for €1 million). The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below: (€ million) Carrying amount at December 31, 2015 Additions Deductions Currency translation differences Other changes Carrying amount at December 31, 2016 Deferred tax liabilities Accelerated tax depreciation ........................................ Difference between the fair value and the carrying amount of assets acquired ........................................................ Site restoration and abandonment (tangible assets) ............. Application of the weighted average cost method in evaluation of inventories ......................................................... Capitalized interest expense ......................................... Other ................................................................... Deferred tax assets, gross Carry-forward tax losses ............................................ Site restoration and abandonment (provisions for contingencies) ......................................................... Timing differences on depreciation and amortization ........... Accruals for impairment losses and provisions for contingencies .......................................................... Impairment losses .................................................... Employee benefits .................................................... Unrealized intercompany profits ................................... Other ................................................................... Impairments of deferred tax assets ................................. Deferred tax assets, net .............................................. 8,424 1,527 (583) 168 (637) 8,899 1,150 644 46 77 439 10,780 114 41 114 1,796 (3,598) (1,377) (2,415) (2,195) (1,380) (902) (171) (257) (1,389) (12,307) 5,099 (7,208) (768) (253) (370) (121) (33) (72) (2,994) 667 (2,327) (207) (171) (7) (9) (509) (1,486) 95 186 140 337 224 16 3 207 1,208 (254) 954 42 20 1 1 (3) 229 (88) 5 (63) (2) 2 (39) (185) 80 (105) 170 (145) (53) 299 (366) 246 111 111 (105) 25 134 58 580 30 610 1,269 348 81 16 340 10,953 (4,722) (2,881) (2,260) (1,413) (906) (163) (118) (1,235) (13,698) 5,622 (8,076) Net deferred tax liabilities ............................................ 3,572 (531) (532) 124 244 2,877 Italian taxation law allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. An average 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 rate for foreign subsidiaries was 36%. F-70 Carry-forward tax losses amounted to €16,478 million and can be used indefinitely for €13,083 million. Carry-forward tax losses regarded Italian companies for €9,889 million and foreign companies for €6,589 million. Deferred tax assets recognized on these losses amounted to €2,330 million and €2,392 million, respectively. Provisions for impairments of deferred tax assets of €5,622 million related to Italian companies for €4,020 million and foreign companies for €1,602 million. 33 Other non-current liabilities (€ million) December 31, 2015 December 31, 2016 Fair value of derivatives financial instruments ...................................... Current income tax liabilities ............................................................ Other payables towards tax authorities ............................................... Cautionary deposits ....................................................................... Other payables .............................................................................. Other liabilities ............................................................................. 98 23 29 267 81 1,354 1,852 161 35 9 265 51 1,247 1,768 Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments. Cautionary deposits of €265 million (€267 million at December 31, 2015) related for €224 million (€232 million at December 31 2015) to deposits from retail customers for the supply of gas and electricity. Other liabilities of €1,247 million (€1,354 million at December 31, 2015) included advances received from Suez following a long-term agreement for supplying natural gas and electricity of €664 million (€736 million at December 31, 2015). The current portion is described in note 28 — Other current liabilities. Liabilities with related parties are described in note 47 — Transactions with related parties. F-71 34 Derivative financial instruments (€ million) Non-hedging derivatives Derivatives on exchange rate - Currency swap .............................................................. - Interest currency swap ..................................................... - Outright ..................................................................... Derivatives on interest rate - Interest rate swap ........................................................... Derivatives on commodities - Future ....................................................................... - Over the counter ........................................................... - Options ...................................................................... - Other ......................................................................... Trading derivatives Derivatives on commodities - Over the counter ........................................................... - Future ....................................................................... - Options ...................................................................... Cash flow hedge derivatives - Over the counter ........................................................... - Future ....................................................................... Embedded derivatives Option embedded in convertible bonds Gross amount Offsetting ..................................................................... Net amount Of which: - current ....................................................................... - non-current ................................................................. December 31, 2015 December 31, 2016 Fair value asset Fair value liability Level of Fair value Fair value asset Fair value liability Level of Fair value 2 2 2 2 1 2 2 1 2 2 1 2 2 223 97 7 327 30 30 311 33 2 346 20 20 1,586 550 1,483 491 2,136 2,493 1,974 2,340 2,647 409 153 3,209 19 107 126 20 3,054 559 176 3,789 614 614 5,848 (2,410) 3,438 26 6,769 (2,410) 4,359 3,220 218 4,261 98 2 2 2 2 2 1 2 2 2 1 2 2 1 2 188 38 17 243 10 10 624 133 4 761 1,014 1,495 561 211 2,267 309 1 310 268 83 15 366 12 12 611 120 1 5 737 1,115 1,490 574 157 2,221 150 18 168 46 3,637 (1,281) 2,356 46 3,550 (1,281) 2,269 2,248 108 2,108 161 Derivative fair values were estimated on the basis of market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace. Fair values of non-hedging derivatives consisted of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not relate to specific trade or financing transactions. Fair values of trading derivatives consisted of derivatives entered for trading purposes and proprietary trading. Fair value of cash flow hedge derivatives related to the hedges entered by the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanism 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 36 — Shareholders’ equity and in note 40 — Operating expenses. Information on hedged risks and hedging policies is disclosed in note 38 — Guarantees, commitments and risks — Risk factors. Options embedded in convertible bonds of €46 million as of December 31, 2016, related to equity-linked cash settled bonds. Options embedded in convertible bonds of €26 million as of December 31, 2015, related to the convertible bond into ordinary shares of Snam SpA expired on January 18, 2016. More information is disclosed in note 29 — Long-term debt and current portion of long-term debt. During the 2016, there were no transfers between the different hierarchy levels of fair value. F-72 35 Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale Discontinued operations Saipem On January 22, 2016, following the fulfillment of all the conditions precedent, among which the consensus of the Antitrust Authority, Eni closed the sale transaction of 12.503% of the share capital of Saipem SpA to CDP Equity SpA. The transaction referred to 55,176,364 Saipem shares at a price of €8.3956 per share for a total consideration of €463 million. At the same date, a shareholder agreement between Eni and CDP Equity entered into force and established the joint control of the two shareholders over Saipem. Therefore, following the loss of control, Saipem was derecognized from Eni’s consolidated accounts and accounted for using the equity method. At the date of the loss of the control (January 22, 2016), the retained interest of 30.42% in the former subsidiary was aligned to the market price of €4.2 per share corresponding to a carrying amount of €564 million with a charge through profit and loss of €441 million (with respect to the carrying amount at the opening balance). Versalis In 2016, Eni’s chemical segment ceased to be classified as a disposal group in accordance to IFRS 5 due to termination of the negations with US-based SK Capital hedge fund, that had shown an interest in acquiring a 70% stake in Eni subsidiary Versalis SpA, the parent company of the chemical business. Therefore, Eni’s consolidated accounts as of and for the year 2016 have been prepared accounting this business as part of the continuing operations. Based on IFRS 5 provisions, in case of cessation of classification as held for sale, management is required to amend financial statements retrospectively to the date of initial classification as held for sale, December 31, 2015, as though the disposal group never qualified as held for sale. Accordingly, the opening balance of the consolidated accounts 2016 were amended to reinstate the criteria of the continuing use to evaluate Versalis by aligning its book value to the recoverable amount, given by the higher of fair value less cost to sell and value-in-use. Under IFRS 5, Versalis was measured at the lower of its carrying amount and fair value less cost to sell. Management estimated the value-in-use of the fixed assets of Versalis’ business units by identifying a single Cash Generating Unit consistently with Eni’s industrial plan for the four-year period 2016-2019 used at December 31, 2015 that considered Versalis as an integrated unit with a view to disposing or monetizing it as a whole. The value-in-use was estimated by discounting the future expected cash flows of the industrial plan of a standalone Versalis, which factored in the earnings volatility of a pool of chemical peers of Versalis, thus determining a beta parameter independent from Eni in the same manner as the Gas & Power segment. Further information is provided in note 16 — Property, plant and equipment. This amendment in Versalis evaluation marginally affected the opening balance of Eni’s consolidated net assets (an increase of €294 million) and was neutral to the Group’s net borrowings. The main economic and financial data of the discontinued operations net of intragroup transactions are provided below. Saipem (€ million) Revenues ............................................................................. Operating expenses ................................................................ Operating profit .................................................................... Finance income (expense) ........................................................ Income (expense) from investments ............................................ Profit before income taxes ....................................................... Income taxes ........................................................................ Net profit ............................................................................ - attributable to Eni ................................................................ - attributable to non-controlling interest ....................................... Earnings per share .............................................. (€ per share) Net cash provided by operating activities ..................................... Net cash flow from investing activities ........................................ Net cash used in financing activities ........................................... Capital expenditures .............................................................. 2014 11,644 12,731 (1,087) 116 24 (947) (2) (949) (417) (532) (0.12) 273 (684) 126 694 2015 10,277 12,199 (1,922) 60 30 (1,832) (142) (1,974) (826) (1,148) (0.23) (1,226) (456) (57) 561 2016 (413) (413) (413) (413) (0.12) F-73 Net loss for 2016 included: (i) a loss from measurement at fair value of the retained interest in Saipem at the date of the loss of control (22 January 2016) for €441 million; (ii) a net gain from utilization of the reserve for exchange differences and of the reserve for the valuation at fair value of cash flow hedge derivatives for €28 million. Assets held for sale and liabilities directly associated with assets held for sale Assets held for sale amounted to €14 million and related to tangible assets and investments. In 2016, Eni sold to MOL Group, a Hungarian oil&gas company, a 100% stake of the subsidiaries Eni Slovenija doo and Eni Hungaria Zrt, two companies operating in the retail and wholesale marketing of fuels with activities in Slovenia and Hungary for a total consideration of €69 million. More information is provided in note 37 — Other information — Supplemental cash flow information and note 42 — Income (expense) from investments. 36 Shareholders’ equity Non-controlling interest (€ million) Saipem SpA .................................................... Others ............................................................ Net profit Shareholders’ equity 2015 (600) 5 (595) 2016 7 7 December 31, 2015 December 31, 2016 1,872 44 1,916 49 49 Eni shareholders’ equity (€ million) Share capital .................................................................................. Legal reserve .................................................................................. Reserve for treasury shares ................................................................. Reserve related to the fair value of cash flow hedging derivatives net of the tax effect ........................................................................................... Reserve related to the fair value of available-for-sale securities net of the tax effect Reserve related to the defined benefit plans net of tax effect .......................... Other reserves ................................................................................ Cumulative currency translation differences ............................................. Treasury shares ............................................................................... Retained earnings ............................................................................ Interim dividend ............................................................................. Net loss for the year ......................................................................... Other items of comprehensive income related to discontinued operations .......... December 31, 2015 December 31, 2016 4,005 959 581 (474) 8 (101) 180 9,129 (581) 51,985 (1,440) (8,778) 20 55,493 4,005 959 581 189 4 (112) 211 10,319 (581) 40,367 (1,441) (1,464) 53,037 Share capital As of December 31, 2016, the parent company’s issued share capital consisted of €4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (same amounts as of December 31, 2015). On May 12, 2016, Eni’s Shareholders’ Meeting declared to distribute a dividend of €0.40 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2015 dividend of €0.80 per share, of which €0.40 per share paid as interim dividend. The balance was paid on May 25, 2016, to shareholders on the register on May 23, 2016, record date on May 24, 2016. F-74 Legal reserve This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law. Reserve for treasury shares The reserve for treasury shares of €581 million (same amount as of December 31, 2015) represents the reserve that was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings. Reserves related to the fair value measurement of cash flow hedging derivatives, available-for-sale financial assets and defined benefit plans The reserves related to the valuation at fair value of cash flow hedging derivatives, available-for-sale financial instruments and defined benefit plans, net of the related tax effect, consisted of the following: Cash flow hedge derivatives Available-for-sale financial instruments Defined benefit plans Gross reserve (384) (439) Deferred tax liabilities Net reserve Gross reserve Deferred tax liabilities Net reserve Gross reserve Deferred tax liabilities Net reserve Gross reserve 100 108 (284) (331) 13 (4) (2) 1 11 (3) (154) 34 (122) (525) 14 (409) 130 89 Total Deferred tax liabilities Net reserve (395) (320) (€ million) Reserve as of December 31, 2014 .... Changes of the year 2015 ............ Reclassification to discontinued operations ............................... Foreign currency translation differences ............................... Reversal of the year 2015 ............. Reserve as of December 31, 2015 ... Changes of the year 2016 ............ Foreign currency translation differences ............................... Reversal of the year 2016 ............ Reserve as of December 31, 2016 .... 5 (1) 4 181 (637) 360 (44) 163 (90) 137 (474) 270 523 246 (130) (57) 393 189 32 (20) (2) 10 (1) 9 (3) (1) 5 (1) (1) 8 (3) (111) 16 10 (35) (4) 12 (99) (13) (1) 4 8 15 (3) 12 (1) (1) 181 (101) (739) (19) 373 8 (4) 522 (112) 152 (44) 172 (125) 12 (130) (71) (1) 137 (567) 248 8 392 81 Reserve for available-for-sale financial instruments net of tax effect of €4 million (€8 million at December 31, 2015) related to the fair value valuation of securities. Other reserves Other reserves amounting to €211 million (€180 million at December 31, 2015) related to: • • • • • a reserve of €247 million representing the increase in Eni shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiary Snamprogetti SpA to Saipem Projects SpA (both merged into Saipem SpA) at a price higher than the book value of the interest transferred (same amount as of December 31, 2015); a reserve of €63 million deriving from Eni SpA’s equity (same amount as of December 31, 2015); a reserve of €21 million relating to the share of “Other comprehensive income” on equity accounted entities (a negative reserve of €11 million at December 31, 2015); a reserve of €4 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 48.55% in the subsidiary Tigáz Zrt (€5 million for the acquisition of 47.60% at December 31, 2015); a negative reserve of €124 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 45.99% in the subsidiary Altergaz SA, now Eni Gas & Power France SA (same amount as of December 31, 2015). Cumulative foreign currency translation differences The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro. F-75 Treasury shares A total of 33,045,197 Eni’s ordinary shares (same amount as of December 31, 2015) were held in treasury for a total cost of €581 million (same amount as of December 31, 2015). Interim dividend The interim dividend for the year 2016 amounted to €1,441 million corresponding to €0.40 per share, as resolved by the Board of Directors on September 15, 2016, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 21, 2016, record date on September 19, 2016. Distributable reserves As of December 31, 2016, Eni shareholders’ equity included distributable reserves of approximately €48.2 billion. Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity (€ million) Net profit Shareholders’ equity 2015 2016 December 31, 2015 December 31, 2016 As recorded in Eni SpA’s Financial Statements ........................................ Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company (10,778) (5,480) Consolidation adjustments: - difference between purchase cost and underlying carrying amounts of net 2,183 4,521 39,562 41,935 18,508 12,384 equity ........................................................................................ - adjustments to comply with Group account policies .............................. - elimination of unrealized intercompany profits ..................................... - deferred taxation .......................................................................... - other adjustments ......................................................................... Non-controlling interest ................................................................... As recorded in Consolidated Financial Statements .................................... (44) (188) (56) (210) (58) (523) 96 (270) (23) (9,373) (1,457) (7) (8,778) (1,464) 595 308 1,137 (1,219) (880) (7) 57,409 (1,916) 55,493 240 461 (801) (1,133) 53,086 (49) 53,037 F-76 37 Other information Supplemental cash flow information (€ million) 2014 2015 2016 Investment in consolidated subsidiaries and businesses Current assets .................................................................... Non-current assets .............................................................. Net borrowings .................................................................. Current and non-current liabilities ........................................ Net effect of investments ...................................................... Fair value of investments held before the acquisition of control . Purchase price .................................................................... less: Cash and cash equivalents Investment in consolidated subsidiaries and businesses net of cash and cash equivalent .............................................................. Disposal of consolidated subsidiaries and businesses Current assets .................................................................... Non-current assets .............................................................. Net borrowings .................................................................. Current and non-current liabilities ........................................ Net effect of disposals .......................................................... Reclassification of foreign currency translation differences among other items of comprehensive income .......................... Fair value of share capital held after the sale of control ............ Gain (loss) on disposal ........................................................ Non-controlling interest ...................................................... Selling price ....................................................................... less: Cash and cash equivalents ..................................................... Disposal of consolidated subsidiaries and businesses net of cash and cash equivalent .............................................................. 96 265 (19) (291) 51 (15) 36 36 5 2 (2) 5 (5) 44 125 (77) (45) 47 (34) 66 79 (6) 73 6,526 8,615 (5,415) (6,334) 3,392 7 (1,006) 11 (1,872) 532 (894) (362) Cash flow from disposals of 2016 related to: (i) the consideration of €463 million received from the sale of 12.503% of Saipem to CDP Equity SpA, which was reported net of Saipem’s cash and cash equivalents disposed of for €889 million (as established by IAS 7). Due to the presentation of the Saipem Group as discontinued operations in 2015 Financial Statements, such cash and cash equivalents were included as reconciliation item in 2016 and 2015 Cash Flow Statement, in order to present the Group cash and cash equivalents net of those related to discontinued operations; (ii) the sale of a 100% stake in Eni Slovenija doo and Eni Hungaria Zrt for a total consideration of €69 million and cash and cash equivalents divested of €5 million. 38 Guarantees, commitments and risks Guarantees (€ million) Eni Consolidated subsidiaries .............................................. Unconsolidated subsidiaries .......................................... Consolidated joint operations ........................................ Joint ventures and associates .......................................... Others ...................................................................... Engineering & Construction Consolidated subsidiaries .............................................. Joint ventures and associates .......................................... F-77 December 31, 2015 December 31, 2016 Unsecured guarantees Other guarantees Total Unsecured guarantees Other guarantees Total 7,929 113 6 75 216 8,339 3,349 68 3,417 11,756 7,929 113 6 6,197 223 14,468 3,349 218 3,567 18,035 6,122 7 6,129 150 150 6,279 5,869 246 2,112 202 8,429 5,869 246 8,236 202 14,553 6,124 6,124 6,124 8,429 14,553 Other guarantees issued on behalf of consolidated subsidiaries of €5,869 million (€7,929 million at December 31, 2015) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for €1,965 million (€4,381 million at December 31, 2015). The decrease of €2,416 million related to the reclassification to joint ventures and associates of the guarantees given on behalf of Saipem Group for €2,483 million as of December 31, 2015; (ii) VAT recoverable from tax authorities for €1,380 million (€1,310 million at December 31, 2015); (iii) a bank guarantee of €1,010 million issued on behalf of GasTerra in order to obtain the renunciation to a temporary seizure order on Eni’s investment in Eni International BV, requested and obtained by a Netherlands Court in July 2016; and (iv) insurance risk for €141 million reinsured by Eni (€140 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €5,785 million (€7,808 million at December 31, 2015). Other guarantees issued on behalf of unconsolidated subsidiaries of €246 million (€113 million at December 31, 2015) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for €240 million (€102 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €53 million (€113 million at December 31, 2015). Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of €8,236 million (€6,197 million at December 31, 2015) primarily consisted of: (i) an unsecured guarantee of €6,122 million (same amount as of December 31, 2015) given by Eni SpA to Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating to the Milan-Bologna fast track railway by CEPAV (Consorzio Eni per l’Alta Velocità) Uno (Saipem 50.36%); consortium members, excluding Saipem Group, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) guarantees given to third parties relating to bid bonds and performance bonds for €1,705 million given on behalf of Saipem Group; and (iii) unsecured guarantees and other guarantees given to banks in relation to loans and lines of credit received for €82 million (€12 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €2,109 million (€72 million at December 31, 2015). Unsecured and other guarantees given on behalf of third parties of €202 million (€223 million at December 31, 2015) primarily consisted of guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%) as security against payment commitments of fees in connection with the regasification activity for €193 million (€187 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €202 million (€214 million at December 31, 2015). Commitments and risks (€ million) Commitments ............................................................................ Risks ........................................................................................ December 31, 2015 December 31, 2016 21,241 422 21,663 20,682 605 21,287 Other commitments of €20,682 million (€21,241 million at December 31, 2015) related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to €12,415 million (€12,794 million at December 31, 2015); (ii) commitments entered by the Exploration & Production segment for leasing contracts (chartering, operation and maintenance) of FPSO vessels to be used for development projects in Angola and Ghana. Total commitments amounted to approximately €4,344 million and have a duration ranging between 14 and 16 years (€4,364 million at December 31, 2015); (iii) commitments assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service for the acquisition of volumes of regasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031) and towards Gulf LNG Energy for the acquisition of regasification capacity at the Pascagoula terminal (5.8 BCM/y) over a twenty-year period (until 2031). The expected commitments have been estimated at €2,541 million and €1,156 million, respectively (€2,590 million and €1,191 million at December 31, 2015, respectively) and have been included in off-balance sheet contractual commitments in the following paragraph “Liquidity risk”; and (iv) a memorandum of intent signed with F-78 the Basilicata Region, whereby Eni has agreed to invest €129 million (€133 million at December 31, 2015) 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”. Risks of €605 million (€422 million at December 31, 2015) primarily concerned potential risks associated with contractual assurances given to acquirers of certain investments and businesses of Eni for €334 million (€326 million at December 31, 2015) and the value of assets of third parties under the custody of Eni for €271 million (€96 million at December 31, 2015). Non-quantifiable commitments A parent company guarantee was issued on behalf of CARDÓN IV SA (Eni’s interest 50%), a joint venture that is currently operating development activities at the Perla gas field located in Venezuela, for the supplying to PDVSA GAS of the volumes of gas produced by the field until 2036 (end of the concession agreement). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective due to a revision of the contractual terms. In case of failure on part of the operator to deliver the contractual gas volumes out of production, the amount of the guarantee execution will be determined by applying the local legislation. The Eni share (50%) of the contractual volumes of gas to be delivered to PDVSA GAS amounted to a total of $16 billion (€15.2 billion). Notwithstanding this amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued to Eni by PDVSA relating to the fulfillment of the commitments relating to the gas quantities to be collected by PDVSA GAS. Following the integration signed on April 19, 2011, Eni confirmed to RFI - Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) on October 15, 1991, to guarantee a correct and timely execution of the section Milano-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as general contractor. In order to pledge the guarantee given, the regulation of CEPAV (Consorzio Eni per l’Alta Velocità) Due binds the associates to give proper sureties and guarantees on behalf of Eni. 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. F-79 Risk factors Financial risks Financial risks are managed in respect of guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting of the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the aim of the risk management, the valuation methodology, the structure of limits, the relation model and the hedging and mitigation instruments. Market risk Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Finance International SA, Eni Finance USA Inc and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni’s finance department and Eni Finance International SA manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies different from commodities are managed by the parent company. The commodity risk associated with commercial exposures of each business unit (Eni’s business line or subsidiaries) is pooled and managed by the Midstream business line, which manages the market risk component in a view of portfolio, while Eni Trading & Shipping SpA executes the negotiation of commodity derivatives over the market. Eni SpA and Eni Trading & Shipping SpA (also through its subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non-European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar and brokerage platforms (i.e. SEF), and over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into these operations through Eni Trading & Shipping and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As the proprietary trading is considered separately from the other activities in specific portfolios of Eni Trading & Shipping, its exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s policies and guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon; (ii) limits of revision strategy, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given; and (iii) VaR which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account of the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s guidelines define rules to manage the commodity risk F-80 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 on the marketplace. According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni has decided to retain a cash reserve to face any extraordinary requirement. Eni’s finance department, with the aim of optimizing the efficiency and ensuring maximum protection of the capital, manages such reserve and its immediate liquidity within the limits assigned. The management of strategic cash is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity. The four different market risks, whose management and control have been summarized above, are described below. Market risk - Exchange rate Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro. Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries, which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance department, which pools Group companies’ positions, hedging the Group net exposure by using certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value based on market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss, as they do not meet the formal criteria to be recognized as hedges. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period. Market risk - Interest rate Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. The Group’s central finance department pools borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with management plans, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to manage effectively the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account, as they do not meet the formal criteria to be accounted for under the hedge accounting method. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 20-day holding period. F-81 Market risk - Commodity Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil&gas prices generally, has a negative impact on Eni’s results of operations and vice versa, and may jeopardize the achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk. These exposures include those associated with the program for the production of proved and unproved oil&gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors as of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments, to the components related to the time horizon of the four-year plan and budget and the relevant activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not finalized to the 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). In the proprietary trading exposures are included the origination activities, if not connected to contractual or physical assets. Strategic risk is not subject to systematic activity of management/coverage that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging activities related to strategic risks are delegated to the top management. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable economic results. The commodity risk and the exposure to commodity prices fluctuations embedded in commodities quoted in currencies other than the euro at each business line (Eni’s Divisions or subsidiaries) is pooled and managed by the Portfolio Management unit for commodities, and by Eni’s finance department for exchange rate requirements. The Portfolio Management unit manages business lines’ risk exposures to commodities, pooling and optimizing Group companies’ exposures and hedging net exposures on the trading venues through the trading unit of Eni Trading & Shipping. In order to manage commodity price risk, Eni uses derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, electricity or emission certificates. Such derivatives are evaluated at fair value based on market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a 95% confidence level and a one-day holding period. Market risk - Strategic liquidity Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual funds) would affect the value of these instruments when evaluated at fair value. 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. The setting up and maintenance of the reserve of strategic liquidity is mainly aimed to: (i) guarantee of financial flexibility. Liquidity should allow Eni Group to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions); and (ii) ensure a full coverage of short-term debts and a coverage of medium and long-term financial debts due within a time horizon of 24 months, even in case of restrictions to credit. F-82 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, duration, ratings, liquidity and instruments to invest on. Financial leverage or short selling is not allowed. Activities in terms of strategic liquidity management started in the second half of the year 2013 and throughout the course of the years 2014 and 2015, the investment portfolio has maintained an average credit rating of A/A-, accordingly with the decrease in the Company’s credit rating. The following table shows amounts in terms of VaR, recorded in 2016 (compared with 2015) relating to interest rate and exchange rate risks in the first section and commodity risk. Regarding the management of strategic liquidity, the sensitivity to change of interest rates is expressed by the values of “Dollar Value per Basis Point” (DVBP). (Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%) (€ million) High Low Average At year end High Low Average At year end Interest rate(a) .............................. Exchange rate(a) ........................... 6.21 0.52 2.45 0.05 4.06 0.13 4.40 0.13 5.27 0.34 2.55 0.04 3.62 0.14 3.42 0.17 2015 2016 (a) Value at risk deriving from interest and exchange rates exposures include the following finance department: Eni Corporate Treasury Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc. (Value at risk — Historic simulation weighted method; holding period: 1 day; confidence level: 95%) (€ million) High Low Average At year end High Low Average At year end Commercial exposures Management Portfolio(a) ............. Trading(b) .................................. 61.91 4.07 3.37 0.40 26.82 1.38 3.37 0.55 19.03 2.58 4.23 0.27 10.24 0.87 9.41 1.35 2015 2016 (a) (b) Refers to the Midstream Department (risk exposure from Refining & Marketing Division and Gas & Power Division), Versalis, Eni Trading & Shipping commercial portfolio and branches outside Italy pertaining to the Divisions. For the Midstream Department starting from 2014, 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, in the year the VaR pertaining to the Midstream Department presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon. 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) (€ million) High Low Average At year end High Low Average At year end Strategic liquidity(a) ...................... 0.31 0.25 0.29 0.25 0.42 0.23 0.35 0.35 2015 2016 (a) Management of strategic liquidity portfolio starting from July 2013. Credit risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of the business. F-83 The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. In addition, credit litigation and receivable collection activities are assessed. Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties deriving from current and strategic use of liquidity, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group operating finance department, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and Divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty on a daily basis. 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 in order to meet short-term finance requirements and to settle obligations. Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt in terms of: (i) maximum ratio between net financial debt and net equity (leverage); (ii) minimum incidence of medium and long-term debts over the total amount of financial debts; (iii) minimum amount of fixed-rate debts over the total amount of medium and long-term debts; and (iv) minimum level of liquidity reserve. For this purpose, Eni holds a significant amount of liquidity reserve (financial assets plus committed credit lines), which aims to: (i) ensure a full coverage of short-term debt and the coverage of medium and long-term debts with a maturity of 24 months, even in case of restrictions to the credit access; (ii) deal with identified risk factors that could significantly affect the cash flow expected in the Financial Plan (i.e. changes in the scenario and/or production volumes, delays in disposals); (iii) ensuring the availability of an adequate level of financial flexibility to support the Group’s development plans; and (iv) maintaining/ improving the current credit rating. The financial asset reserve is employed in short-term marketable financial instruments, favouring investments with very low risk profile. At present, the Group believes to have access to sufficient funding to meet the current foreseeable borrowing requirements as a consequence of the availability of financial assets and lines of credit and the access to a wide range of funding at competitive costs through the credit system and capital markets. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.3 billion were drawn as of December 31, 2016. The Group has credit ratings of BBB+ outlook stable and A-2, respectively for long and short-term debt, outlook stable, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked in addition to the Company’s industrial fundamentals and trends in the trading environment to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. In the course of the 2016, Eni issued bonds amounting to €3.0 billion related to the Euro Medium Term Notes Program and equity-linked bonds amounting to €0.4 billion. As of December 31, 2016, Eni maintained short-term unused borrowing facilities of €12,308 million, of which €41 million committed. Long-term committed unused borrowing facilities amounted to €6,236 million, of which €700 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. F-84 Finance debt repayments including expected payments for interest charges and derivatives The table below summarizes the Group main contractual obligations for finance liability repayments, including expected payments for interest charges and derivatives. Maturity year (€ million) 2016 2017 2018 2019 2020 2021 and thereafter Total December 31, 2015 Non-current financial liabilities .................. Current financial liabilities ......................... Fair value of derivative instruments ............. Interest on finance debt ............................. Financial guarantees ................................. 2,336 5,720 4,261 12,317 737 169 3,013 2,038 3,827 2,599 8,001 56 3,069 654 1 2,039 525 33 3,860 453 2,599 354 8 8,009 1,673 21,814 5,720 4,359 31,893 4,396 169 Maturity year (€ million) 2017 2018 2019 2020 2021 2022 and thereafter Total December 31, 2016 Non-current financial liabilities .................... Current financial liabilities ........................... Fair value of derivative instruments .............. Interest on finance debt ............................... Financial guarantees ................................... 2,988 3,396 2,108 8,492 696 84 2,090 4,044 2,914 1,285 10,332 36 2,126 557 76 4,120 486 2,914 386 46 1,331 277 3 10,335 1,605 23,653 3,396 2,269 29,318 4,007 84 Trade and other payables The table below summarizes the Group trade and other payables by maturity. (€ million) December 31, 2015 Trade payables ........................................................................ Other payables and advances ..................................................... (€ million) December 31, 2016 Trade payables ........................................................................ Other payables and advances ..................................................... Maturity year 2016 2017-2020 2021 and thereafter Total 9,605 5,337 14,942 58 58 23 23 9,605 5,418 15,023 Maturity year 2017 2018-2021 2022 and thereafter Total 11,038 5,665 16,703 29 29 22 22 11,038 5,716 16,754 Expected payments by period under contractual obligations The Group has in place a number of contractual obligations arising in the normal course of the business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations pertain to 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. F-85 The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis. Maturity year (€ million) 2017 2018 2019 2020 2021 Operating lease obligations(a) ................. Decommissioning liabilities(b) .................. Environmental liabilities ........................ Purchase obligations(c) ........................... - Gas 593 253 281 10,891 - take-or-pay contracts ...................... - ship-or-pay contracts ...................... 8,429 1,569 - Other take-or-pay or ship-or-pay obligations .......................................... - Other purchase obligations(d) ............... Other obligations .................................. - Memorandum of intent relating Val d’Agri ........................................... 114 779 9 257 417 255 9,511 231 400 202 8,839 199 184 71 7,961 2022 and thereafter 785 14,447 1,631 73,758 Total 2,418 16,281 2,689 120,225 8,277 943 7,916 724 7,312 478 70,851 1,853 110,697 6,620 101 190 2 96 103 2 80 91 2 228 826 111 724 2,184 129 353 580 249 9,265 7,912 1,053 105 195 3 9 12,027 3 10,450 2 10,442 2 9,674 2 8,417 111 90,732 129 141,742 (a) (b) Operating leases primarily regarded assets for drilling and production activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings. 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. Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. (c) (d) Mainly refers to arrangements to purchase capacity entitlements at certain regasification facilities in the U.S. (€1,226 million). Capital investment and capital expenditure commitments In the next four years, Eni expects capital investments and capital expenditures of €31.6 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. (€ million) Maturity year 2017 2018 2019 2020 2021 and thereafter Total Committed projects ................................................ 6,733 6,679 4,218 2,441 3,685 23,756 F-86 Other information about financial instruments The carrying amount of financial instruments and the relevant economic and equity effect as of and for the years ended December 31, 2015 and 2016 consisted of the following: 2015 2016 (€ million) Held-for-trading financial instruments Securities(a) .......................................... Non-hedging and trading derivatives(b) ........ Held-to-maturity financial instruments Securities(a) .......................................... Available-for-sale financial instruments Securities(a) .......................................... Investments valued at fair value Non-current investments(c) ....................... Receivables and payables and other assets/ liabilities valued at amortized cost Trade receivables and other(d) .................... Financing receivables(a) ........................... Trade payables and other(e) ....................... Financing payables(a) .............................. Net assets (liabilities) for hedging derivatives(f)........................................... 5,028 (921) 3 (327) 77 282 368 19,946 3,256 15,023 27,793 1 8 286 (716) (118) 83 (812) (179) Finance income (expense) recognized in Profit and loss account Other comprehensive income Carrying amount Finance income (expense) recognized in Profit and loss account Other comprehensive income (21) (465) 9 (4) Carrying amount 6,166 87 75 238 (4) 17,324 2,328 16,754 27,239 (1,116) 128 287 (291) (256) (524) 883 (a) (b) (c) (d) (e) (f) Income or expense were recognized in the profit and loss account within “Finance income (expense)”. In the profit and loss account, economic effects were recognized as income within “Other operating income (loss)” for €17 million (loss for €487 million in 2015) and as loss within “Finance income (expense)” for €482 million (income for €160 million in 2015). In the profit and loss account, economic effects were recognized as income within “Income (expense) from investments” In the profit and loss account, economic effects were essentially recognized as expense within “Purchase, services and other” for €840 million (expense for €641 million in 2015) (impairments net of reversal) and as expense for €276 million within “Finance income (expense)” (expense for €75 million in 2015) (exchange rate differences at year-end and amortized cost). In the profit and loss account, exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were primarily recognized within “Finance income (expense)”. In the profit and loss account, income or expense were recognized within “Net sales from operations” and “Purchase, services and other” as expense for €523 million (expense for €181 million in 2015) and as expense within “Finance income (expense)” for €1 million (income for €2 million in 2015) (time value component). Disclosures about the offsetting of financial instruments The table below summarizes the disclosures about the offsetting of financial instruments. (€ million) Gross amount of financial assets and liabilities Gross amount of financial assets and liabilities subject to offsetting Net amount of financial assets and liabilities December 31, 2015 Financial assets Trade and other receivables ..................................................... Other current assets ............................................................... Financial liabilities Trade and other liabilities ....................................................... Other current liabilities ........................................................... December 31, 2016 Financial assets Trade and other receivables ..................................................... Other current assets ............................................................... Financial liabilities Trade and other liabilities ....................................................... Other current liabilities ........................................................... 22,351 6,052 15,653 7,122 18,489 3,872 17,599 3,880 711 2,410 711 2,410 896 1,281 896 1,281 21,640 3,642 14,942 4,712 17,593 2,591 16,703 2,599 F-87 The offsetting of financial assets and liabilities related to: (i) for €1,281 million (€2,410 million at December 31, 2015) the offsetting assets and liabilities for current financial derivatives pertaining to Eni Trading & Shipping SpA for €1,145 million (€2,389 million at December 31, 2015) and Eni Trading & Shipping Inc for €136 million (€21 million at December 31, 2015); and (ii) for €896 million (€711 million at December 31, 2015) the offsetting of receivables and payables pertaining to the Exploration & Production segment towards state entities for €845 million (€664 million at December 31, 2015) and the offsetting of trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €51 million (€47 million at December 31, 2015). 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 30 — Provisions for contingencies and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements. A description of the most significant proceedings currently pending is provided in the following paragraph. 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) Syndial SpA (company incorporating EniChem Agricoltura SpA - Agricoltura SpA in liquidation - EniChem Augusta Industriale Srl - Fosfotec Srl) — Proceeding about the industrial site of Crotone. A criminal proceeding is pending 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’s subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrial waste from Montedison activities until 1989 and then no additional waste was discharged there. Eni’s subsidiary carried out the clean-up of the landfill in 1999 through 2000. The defendants are certain managers at Eni’s subsidiaries that have owned and managed the landfill since 1991. Independent consultants performed an assessment during the 2014. Once the consultants completed their work, the acts returned to the Public Prosecutor of Crotone for the next step and possible indictment. The proceeding continues with the examination of the dismissal request submitted by the defense. The City of Crotone will act as offended party. (ii) Eni SpA — Industrial site of Praia a Mare. Based on complaints filed by certain offended persons, the Public Prosecutor of Paola started an enquiry about alleged diseases related to tumors that those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. Based on the findings of independent appraisal reports, in the course of 2009 the Public Prosecutor resolved that a number of ex-manager of that industrial complex would stand trial. In the preliminary hearing held in November 2010, 189 persons entered the trial as plaintiff; while 107 persons were declared as having been offended by the alleged crime. The plaintiffs have requested that both Eni and Marzotto SpA would bear civil liability. However, compensation for damages suffered by the offended persons has yet to be determined. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants would stand trial for culpable manslaughter, culpable injuries, environmental disaster and negligent conduct about safety measures on the workplace. Following a settlement agreement with Eni, Marzotto SpA entered settlement agreements with all plaintiffs, except for the local administrations. In December 2014, the Tribunal issued an acquittal sentence for all defendants, as the indictment was found groundless. The Public Prosecutor appealed against the sentence. (iii) Syndial SpA and Versalis SpA — Porto Torres dock. In July 2012, the Judge for the Preliminary Hearing, following a request of the Public Prosecutor of Sassari, requested the performance of a probationary evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by F-88 Syndial SpA) and its capacity to avoid the dispersion of contamination released by the site in the near portion of sea. Syndial SpA and Versalis SpA have been notified that its chief executive officers and other managers are being investigated. The Public Prosecutor of the Municipality of Sassari requested that the above-mentioned individuals would stand trial. The Judge for preliminary investigation authorized that the two Eni’s subsidiaries would be arraigned to compensate any possible damage in connection with the proceeding. The trial was held with an abbreviated procedure. The plaintiffs Ministry of Environment and the Sardinia Region claimed environmental damage in an amount of €1 billion and €500 million, respectively. On the hearing dated July 22, 2016 the Judge pronounced an acquittal sentence for Syndial and Versalis. Certain of Eni’s employees were found guilty: the environmental manager of the area, the environmental manager of Porto Torres site and the manager in charge of the Syndial’s groundwater treatment plant, who were all condemned to one year, with a suspended sentence, for environmental disaster, which took place in the area in the period limited to August 2010 – January 2011. The provisional settlement awards compensation payment of €200,000 to the Ministry, €100,000 to the Sardinia Region and €100,000 to the Municipality of Sassari. The Judge did not mention any possible malfunctioning of the hydraulic barrier of Porto Torres site or ineffective implementation of any emergency safety measure, as claimed by the Public Prosecutor. Syndial will file an appeal against this decision. (iv) Syndial SpA - The illegal landfill in Minciaredda area, Porto Torres site. On July 7, 2015, the Judge for the Preliminary Hearing of the Court of Sassari, on request of the Public Prosecutor, decided the seizure of the Minciaredda landfill area, near the western border of the Porto Torres site. All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure provision involved as well Syndial in accordance with the Legislative Degree No. 231 of 2001 that held companies liable for the crimes committed by their employees. The investigations are underway. With a reference to the clean-up activities in the Minciaredda area, on January 27, 2016 the administrative body responsible for sanctioning clean-up projects approved: i) the operative project “Nuraghe” which provides for the soil clean-up in the area “Peci” (deposit of pitch from dimethyl terephthalate – DMT) and in the area “Palte Fosfatiche” (phosphates deposit) in the Minciaredda area; and ii) an addendum to the operative project of clean-up of the groundwater in the Minciaredda area. Syndial obtained the necessary ministerial and judicial authorizations to start the remediation project. The investigations are underway. (v) Syndial SpA - The Phosphate deposit at Porto Torres site (1). On June 30, 2015 the Judge for the Preliminary Hearing of the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, sentenced to seize — as a preventive measure — the area of “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster and carrying out an unauthorized disposal of hazardous wastes. Subsequently to a specific request, both the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari authorized to implement better delimitation of the landfill area, to provide the area with devices to monitor the level of environmental pollutants and meteoric waters. The investigations are underway. (vi) Syndial SpA - Phosphate deposit at Porto Torres site (2). On December 16, 2015, the Public Prosecutor at the Court of Sassari sentenced to seize — as a probative measure — the containment systems for the meteoric waters in the area “Palte Fosfatiche” (phosphates deposit). These waters are being collected by Syndial following authorizations of the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up, management of radioactive waste and spill of waters containing hazardous substances. The Public Prosecutor decided to suspend the activities of collection, containment and preservation of the area, in spite that those activities have already been authorized. Syndial filed a request to continue conducting clean-up operations to the Judge for the Preliminary Hearing of the Court of Sassari. The investigations are underway. (vii) Syndial SpA - Public Prosecutor of Gela. An investigation is pending before the Public Prosecutor of Gela regarding 17 former managers of the Eni Group. The proceeding regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged work-related diseases that those persons may have contracted at the plant of Clorosoda. Alleged crimes relate to the period from 1969, when the Clorosoda plant commenced operations till 1998 when the plant was shut down and clean-up activities were performed. The Public Prosecutor requested the performance of a medico-legal appraisal on over 100 people that were employed at the above-mentioned plant. This appraisal was performed by independent consultants designated by the Judge for preliminary investigation F-89 and did not find any evidence that the various diseases which underwent the medical appraisal could be directly linked to the exposure to emissions related to the production of chlorine and caustic soda. The consultants also found that production activities were in compliance with applicable laws and regulations on health and safety. On January 23, 2015, the Judge for preliminary investigation declared that the gathering of evidence before a trial was concluded. The Public Prosecutor issued a notice of the conclusion of preliminary investigations deciding not to ask for dismiss of charges only in relation to the one specific case, which regards one former employee which in the meantime had died, compared to the initial complaint that concerned several (over a hundred) cases of personal injury and manslaughter. Therefore, the proceeding has been downsized compared to the initial claim. The rest of the accusatory assumptions, however, seems to be groundless in the light of the results of assessment performed by independent consultants appointed by the Judge for the preliminary investigation. The criminal proceeding is still pending. (viii) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria — Prosecuting body: Public Prosecutor of Castrovillari. Certain areas owned by Eni in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria have been preventively seized by the Judicial Authority, following a pending investigation about an alleged improper handling of industrial waste from the processing of zinc ferrites at the industrial site of Pertusola Sud, alleged illegally stored. The circumstances under investigation are the same considered in a criminal action for alleged omitted clean-up that was concluded in 2008 without any negative outcome on part of Eni’s employees. Eni’s subsidiary Syndial SpA has removed any waste materials from the landfills. Besides that, Syndial defined an agreement with the Municipality of Cerchiara and the Municipality of Cassano to settle all claims relating to alleged damages caused by the unauthorized waste disposal in the landfills on the territory of the two Municipalities. The criminal proceeding is still pending. The remediation activities have been completed and the company filed a memorandum to request the closing of the proceeding. (ix) Syndial SpA - Proceeding on the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna about the crimes of culpable manslaughter, injuries and environmental disaster, which would have been allegedly committed by former Syndial employees at the site of Ravenna. The site was taken over by Syndial following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are 77 affected victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. The advocacy of Syndial claimed the statute of limitation about the instance of environmental disaster for certain instances of diseases and deaths. The Judge for the Preliminary Hearing at Ravenna decided that all defendants would stand trial and ascertained the statute of limitation only with reference to certain instances of crime of culpable injury. Concluded the trial, the proceeding entered the hearing phase for the final discussion. Syndial has signed some settlements. On November 24, 2016, the Judge, lifted the reserve, acquitted all the accused for 76 of the 77 contested cases and sentenced 6 of the 15 defendants for a single case of asbestosis. (x) 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 environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. Raffineria di Gela SpA has been sued for administrative offence in accordance with the Law Decree No. 231 of 2001. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, in addition to the pollution of the sea water near the coast 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. On the closure of the preliminary investigation, the Public Prosecutor of Gela reunited in this proceeding the other investigations related to the pollution occurred at the other sites of the Gela refinery as well as hydrocarbon spills of EniMed. The proceeding is still pending. (xi) Proceeding Val d’Agri. The Italian Public Prosecutor’s Office of Potenza started a criminal investigation in order to ascertain existence of an illegal handling of wastes material produced at the Viggiano oil center, part of the Eni-operated Val d’Agri oil complex, and disposed at treatment plants in the national territory. After a two-year investigation, the Prosecutors decided for the domiciliary detention of 5 Eni employees and to put under seizure certain plants functional to the production activity of the Val d’Agri complex which, as a consequences, was shut down (60 kboe/d net to Eni), to be then resumed on 10 August 2016. From the commencement of the investigation, Eni has carried out several and in-depth F-90 technical and environmental surveys, with support of independent experts of international reach, who recognized full compliance of the plant and the industrial process with requirements of applicable laws, as well as with best available technologies and international best practices. The Company sought to obtain a repeal of the seizure before the jurisdictional authorities without an outcome. The Company studied certain corrective measures to upgrade plants which, although being not a structural solution, were intended to address the claims made by the public prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those measures comprise building a gathering system of waters associated with the extraction of hydrocarbons at the gas lines. Those corrective measures were favourably reviewed by the public prosecutor, who granted Eni a temporary repeal of the seizure in order to allow the Company perform the works. The in-charge department of the Italian Ministry of Economic Development duly authorized the works and established a strict schedule to execute the plant upgrading as requested by the public prosecutor. The plant modification works were completed on July 10, 2016 and on July 20, 2016, the Carabinieri of NOE, assisted by the Technical Consultant of the Prosecutor, conducted the inspection to verify the state of the site and the compliance of the correct execution of the plant upgrading. Following the report prepared by the Technical Consultant, as a consequence of the inspection conducted, the Prosecutor issued the decision for the definitive release from seizure of the plant while the Region took note the measure for the part of competence. On August 10, 2016, the plant was restarted with re-injection into the well Costa Molina 2. Simultaneously with the restart of the plant, the Company began the review procedure at AIA by presenting the documents within the deadline of 14 August 2016. The proceeding is at the preliminary hearings. 1.2 Civil and administrative proceedings in the matters of environment, health and safety (i) Syndial SpA - Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore - Prosecuting body: Ministry of the Environment. In May 2003, the Ministry of the Environment summoned Syndial to obtain a sentence condemning the Eni subsidiary to compensate an alleged environmental damage caused by the activity of the Pieve Vergonte plant in the years 1990 through 1996. With a temporarily executive sentence dated July 3, 2008, the District Court of Turin sentenced the subsidiary Syndial SpA to compensate environmental damages amounting to €1,833.5 million, plus legal costs that accrued from the filing of the decision. Syndial and Eni technical legal consultants have considered the decision and the amount of the compensation to be without factual and legal basis and have concluded that a negative outcome of this proceeding is unlikely. Particularly, Eni and its subsidiary deem the amount of the environmental damage to be absolutely groundless as the sentence lacks sufficient elements to support such a material amount of the liability charged to Eni and its subsidiary with respect to the volume of pollutants ascertained by the Italian Environmental Minister. Based on these technical legal advices, which is also supported by external accounting consultants, no provisions have been made with respect to the proceeding. In July 2009, Syndial filed an appeal against the above-mentioned sentence, and consequently the proceeding continued before a Second Degree Court of Turin. In the hearing of June 15, 2012, before the Second Degree Court of Turin, the Minister of the Environment, formalized trough the Board of State Lawyers its decision to not enforce the sentence until a final verdict on the matter is reached. The Second Degree Court requested Syndial to stand as defendant and then requested a technical appraisal of the matter. This technical appraisal was favorable to Syndial; however, the Board of State Lawyers questioned such outcome. On July 8, 2015, the Court of Appeal of Turin requested the consultants appointed by the Court to perform again a technical appraisal of the matter with aim to identify adequate measures for environmental restoration of the external areas. On June 13, 2016, the consultants filed an integration to the technical appraisal. In brief, the consultants validated the technical review of the matter and other technical assessments which were carried out by the Company together with local and national (i) no further measure for environmental restoration is required; (ii) there was no significant and measurable impact on the environment and the usability of the ecosystem, therefore no restoration or damage compensation should be claimed. The only impact which could be recorded concerns fishing, with an estimated damage of €7 million which can be already restored by means of the measures proposed by Syndial; (iii) the necessity and convenience of dredging should be definitely excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the Syndial’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. On March 6, 2017, a second-degree Court issued a sentence repealing the first-degree court verdict, which had sentenced Syndial to compensate environmental damage in excess of €1.8 billion. The second-degree Court reaffirmed that monetary compensation is no longer applicable and requested Syndial to perform the already approved cleanup project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The technical entities. The consultants concluded that: F-91 value of these compensatory works requested by the Court, in case of Syndial failure to perform or misperformance, is estimated at €9.5 million. The cleanup project was filed by Syndial, was ratified by local and governmental authorities and is currently being executed. Expenditures expected to be incurred by Syndial have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were rejected. (ii) Ministry for the Environment — Augusta harbor. The Italian Ministry for the Environment with various administrative acts required companies that were running 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 the Priolo petrochemical site. The above mentioned companies opposed said industrial activity of administrative actions, objecting in particular to the way in which remediation works have been designed and modes whereby information on pollutants concentration has been gathered. A number of administrative proceedings were started on this matter, which were reunified before the Regional Administrative Court of Catania. In October 2012, said Court ruled in favor of Eni’s subsidiaries against the Ministry prescriptions about the removal of pollutants and the construction of a physical barrier. The proceeding is still pending. (iii) Claim for preventive technical inquiry - Court of Gela. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and Syndial 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 33 parents of children born malformed in the Municipality of Gela between 1992 and 2007. The claim for preventive technical inquiry aims at verifying the relation of causality between the malformation pathologies suffered by the children of the plaintiffs and the environmental pollution caused by the Gela site (pollution deriving from the existence and activities at the industrial plants of Raffineria di Gela SpA and Syndial SpA), quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. In any case, the same issue was the subject of previous criminal proceedings, of which one closed without ascertainment of any illicit behavior on part of Eni or its subsidiaries, while a further criminal proceeding is still pending. The consultants appointed by the Court and those designated by the plaintiffs performed a technical appraisal of the matter, reaching however very different outcomes. Thus, parties failed to reach a settlement of the matter. On December 22, 2015, the three involved Eni companies were sued following a claim of the parents of a girl, whose case was assessed by the above-mentioned technical appraisal. Subsequently, the Eni’s companies were sued in relation to other 30 case. The proceeding is pending. (iv) Environmental claim relating to the Municipality of Cengio - Plaintiffs: the Ministry for the the Environment and the Delegated Commissioner for Environmental Emergency in the territory of Municipality of Cengio. The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio summoned Eni’s subsidiary Syndial before a Civil Court and sentenced the Eni’s subsidiary to compensate for the environmental damage relating to the site of Cengio. The plaintiffs accused Syndial of negligence in performing the clean-up and remediation of the site. On the contrary, Syndial believes they have executed the clean-up work properly and efficiently in accordance with the framework agreement signed with the involved administrations including the Ministry of the Environment in 2000. On February 6, 2013, a Court in Genoa ruled the resumption of the proceeding and established a technical appraisal to verify the existence of the environmental damage. Following failed attempts to define a settlement agreement of the matter among the involved parties, the Judge resumed the trial. The next stop in the procedure is the performance of an independent appraisal of the matter by a consultant appointed by the Judge. (v) Syndial SpA and Versalis SpA — Porto Torres — Prosecuting body: Public Prosecutor of Sassari. The Public Prosecutor of Sassari (Sardinia) resolved that a number of officers and senior managers of companies engaging in petrochemical operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s fully-owned subsidiary Syndial, would stand trial due to allegations of environmental damage and poisoning of water and crops. The Province of Sassari, the Municipality of Porto Torres and other entities have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine F-92 fauna of the industrial port of Porto Torres. The proceeding continues before the Prosecutor of Sassari. In February 2013, the Prosecutor of Sassari has notified the conclusion of preliminary investigations and requested a new imputation for negligent behaviour instead of illicit conduct. In the conclusions of the preliminary hearing, the GUP of Sassari dismissed the accusation because of the statute of limitations. The Public Prosecutor filed an appeal before a Third Instance Court. After a hearing on a question of constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the Constitutional Court. (vi) Syndial SpA and Versalis SpA — Summon for alleged environmental damage caused by illegal waste disposal in the municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Syndial and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff claimed the responsibilities of Syndial and Versalis for the production of waste and because they commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001-2003 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 (this landfill is located about 2 kilometers from the town of Melilli). The claim amounts to €500 million and refers to two Group’s subsidiaries and SMA.RI, the company that carries out activities of waste disposal, being jointly and severally liable. On February 8, 2016, the Judge accepted an explanation of Eni’s subsidiaries stating that the request of municipality was not admissible, so that the request was rejected. The proceeding is still pending. (vii) Summon for Eni, Raffineria di Gela SpA, EniMed SpA and Syndial SpA. 273 Gela residents filed an appeal to the Court of Gela requesting to halt all the production activities conducted by Eni’s subsidiaries at Gela site in order to put an end to environmental pollution affecting the health of the local population. The claimants also requested the appointment of commissioners in charge of carrying out the plants shutdown and of continuing to implement clean-up activities in the area. Besides that, they requested the Court to order to the Municipality of Gela — as a competent body in the field of health protection — to adopt certain provisions aimed to preserve the health of the local population. This proceeding arose in connection with an alleged environmental damage caused by the industrial activities of the site and consequent necessity to protect the population from serious harm to the health. The initiative was underpinned by certain technical assessments performed by consultants appointed by the Court on the preliminary stage. The aim of these assessments was to establish cause-and-effect relationship between the industrial contamination and congenital anomalies reported in the town of Gela. 2. Court inquiries and of other Regulatory Authorities (i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. On January 23, 2013, the Italian airline company Alitalia which was undergoing a reorganization procedure, summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to obtain a compensation for alleged damages caused by a presumed anti-competitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a deliberation filed by the Italian Antitrust Authority on June 14, 2006. The antitrust deliberation accused Eni and other five petroleum companies of anti-competitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. The antitrust findings were substantially endorsed by an administrative court. Alitalia has made a claim against the three petroleum companies jointly and severally presenting two alternative ways to assess the alleged damages. A first assessment of the overall damages amounted to €908 million. This was based on the presumption that the anti-competitive agreements among the defendants would have prevented Alitalia from autonomously purchasing supplies of jet fuel in the years when the existence of the anti-competitive agreements were ascertained by the Italian Antitrust Authority and in subsequent years until Alitalia ceased to operate airline activity. Alitalia asserts the incurrence of higher supply costs of jet fuel of €777 million excluding interest accrued and other items which add to the lower profitability caused by a reduced competitive position in the marketplace estimated at €131 million. An alternative assessment of the overall damage made by Alitalia stands at €395 million of which €334 million of higher purchase costs for jet fuel and €61 F-93 million of lower profitability due to the reduced competitive position on the marketplace. With a decision dated May 23, 2014, the Court of Rome declared the connection with a judgment previously proposed by Alitalia itself before the Court of Milan against other oil companies participating to an alleged cartel agreement. The case was thus summed up by Alitalia before the Court of Milan. The proceedings is still pending before the First Degree Court. Eni accrued a risk provision against this proceeding. (ii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for the gas supplied in the 2012-2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. An arbitration award of June 23, 2016 dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considers that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra now claims an additional amount to be paid by Eni which corresponds to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, does not agree with GasTerra’s interpretation and regards GasTerra claim groundless. However, GasTerra, based on its own interpretation, commenced arbitration proceedings and obtained from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV, for the alleged trade receivable due by Eni (equal to €1.01 billion). This measure, which was granted after a summary review only and without Eni being heard, does not prejudice the outcome on the merits of the proceeding. In order to obtain the discharge of the seizure of Eni’s investment in Eni International BV, Eni proposed to GasTerra to replace the seizure with a bank guarantee of the same amount as the GasTerra claim, which would remain effective until the arbitration final award. GasTerra accepted Eni’s offer. With the filing of the Stetement of Defense and Counterclaim, Eni will request that the arbitration panel states the provisional price established in the Agreement Letter continues being applied until a new contractual price is defined with retroactive efficacy from 2012, based on trends recorded in the Italian market. Currently it not possible to estimate a time schedule of the arbitration procedure because the panel has yet to be appointed. Presumably, a decision about the first award interpretation or about the interpretation of the Agreement Letter will not occur before the end of 2017 or the beginning of 2018. Eni will further seek compensation for any damages it incurs, due to GasTerra’s legal actions. At the present, there are no evidence to suggest that an upward revision of the provisional price is likely. Furthermore, Eni is part to another arbitration proceeding relating to the price revision of a long-term gas supply contract. 3. Court inquiries on the matter of criminal/administrative corporate responsibility (i) EniPower SpA. In June 2004, the Milan Public Prosecutor commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately dismissed. The Court served EniPower (the commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of investigation in accordance with Legislative Decree No. 231/2001 that establishes that companies are liable for the crimes committed by their employees who acted on behalf of the employer. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the Preliminary Hearings requested all the parties that have not requested the plea-bargain to stand in trial, excluding certain defendants as a result of the statute of limitations. During the hearing on March 2, 2010, the Court confirmed the admission as plaintiffs of Eni SpA, EniPower SpA and Saipem SpA against the inquired parts under the provisions of Legislative Decree No. 231/2001. Further employees of the companies involved were identified as defendants to account for their civil responsibility. In September 2011, the Court of Milan found that nine persons were guilty for the above-mentioned crimes. In addition, they were sentenced jointly and severally to the payment of all damages to be assessed through a dedicated proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations while the trial ended with an acquittal of 15 individuals. In relation to the companies involved in the proceeding, the Court found that 7 companies are liable based on the provisions of Legislative Decree No. 231/2001, F-94 imposing a fine and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower and Saipem, which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies. The Court rejected the position as plaintiffs of the Eni Group companies, reversing a prior decision made by the Court. This decision may have been made based on a pronouncement made by a Supreme Court that stated the illegitimacy of the constitution as plaintiffs made against any legal entity, which is indicted under the provisions of Legislative Decree No. 231/2001. The Court in December 19, 2011. The condemned parties filed an appeal against the above-mentioned decision. The Appeal Court issued a ruling that substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. In 2015, the Supreme Court annulled the judgment of the Appeal Court of Milan ascribing the judgment to another section. filed the ground of the judgment (ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to its former controlled company Saipem in Algeria. On February 4, 2011, Eni received from the Public Prosecutor of Milan an information request pursuant to Article 248 of 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 and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem and Technip relating to the engineering of the ground section of a gas pipeline). For that reason, Eni forwarded the notification to Saipem. The crime of international corruption is among the offenses contemplated by Legislative Decree of June 8, 2001, No. 231, relating to corporate responsibility for crimes committed by employees, which provides fines and interdictions to the company and the disgorgement of profit. Saipem promptly began to collect documentation in response to the requests of the Public Prosecutor. The documents were produced on February 16, 2011. Eni also filed documentation relating to the MLE project (in which the Eni’s Exploration & Production Division participates) even if not required, with respect to which investigations in Algeria are ongoing. On November 22, 2012, the Public Prosecutor of Milan served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption in accordance to Article 25, second and third paragraph of Legislative Decree No. 231/2001. Furthermore, the Prosecutor requested the production of certain documents relating to certain activities in Algeria. The proceeding was unified with the Iraq-Kazakhstan proceeding, concerning a different line of investigation, as it related to the activities carried out by Eni in Iraq and Kazakhstan. Subsequently Saipem was served a notice of seizure, then a request for documentation and finally a search warrant was issued, in order to acquire 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, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, who was fired at the beginning of 2013. On February 7, 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced in accordance with Article 25, third and fourth paragraph of Legislative Decree No. 231/2001 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. 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 dedicated team to the Algerian matters. During 2013, the external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department have not found any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on a voluntary basis of the MLE project, the only project that Eni understands to be under the prosecutors’ investigation where the client is an Eni Group company has not found evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling). Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal and accounting and administrative issues. The findings of the review performed have confirmed the autonomy of Saipem from the parent company. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. On October 24, 2014, Eni SpA received a request of probationary evidence by the Prosecutor of Milan relating to for the examination of two defendants: the former Chief Operating Officer of the Business Unit F-95 Engineering & Construction of Saipem and the former President and General Manager of Saipem Contracting Algérie SpA. On January 14, 2015, the Public Prosecutor of Milan notified the conclusion of preliminary investigations towards Eni, Saipem and eight persons (including, the former CEO and CFO of Eni and the Chief Upstream Officer of Eni who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor of Milan has issued a notice for alleged international corruption against all defendants (including Eni and Saipem on the base of the provisions of Legislative Decree No. 231/2001) in connection with the entry into intermediary contracts by Saipem in Algeria. Furthermore, some of the defendants (including the former CEO and CFO of Eni and the Chief Upstream Officer of Eni) were accused of tax offense for fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. Having acquired the actions of the court filed in relation to the request of probationary evidence, the minutes of the hearing and the documents filed for the conclusion of the preliminary investigation, Eni requested its consultants to perform additional analysis and investigation. As a result, Eni’s consultants reaffirmed their conclusions previously reported to the Company. In February 2015, the Public Prosecutor indicted all the investigated persons for above-mentioned crimes. On October 2, 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni, former Chief Executive Officer and Chief Upstream Officer for all the alleged crimes. On February 24, 2016, the Court of Third Instance, upholding an appeal presented by the Public Prosecutor of Milan, reversed the dismissal, annulled the verdict, and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of the new preliminary hearing dated 27 July 2016, the judge ordered the trial for all defendants, including Eni. The judgment of first instance is pending. At the end of 2012, Eni contacted the U.S. Authorities — the DoJ and the U.S. SEC — in order to voluntary inform them about this matter and kept them informed about the developments in the Italian prosecutors’ investigations. Following Eni’s notification in 2012, both the U.S. SEC and the DoJ have started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests. (iii) Iraq — Kazakhstan. A criminal proceeding is pending before the Public Prosecutor of Milan in relation to alleged crimes of international corruption involving Eni’s activities in Kazakhstan regarding the management of the Karachaganak plant and the Kashagan project, as well as handling of assignment procedures of work contracts by Agip KCO. The Company has filed the documents collected and is fully collaborating with the Public Prosecutor. A number of managers and a former manager are involved in the investigation. The above-mentioned proceeding has been combined with another (the so-called “Iraq proceeding”) regarding a parallel proceeding related to Eni’s activities in Iraq, disclosed in the following paragraphs. On June 21, 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were searched by the Judicial Authorities. The search involved the offices of certain Group employees and of certain third parties in connection with alleged crimes of conspiracy and corruption as part of the “Jurassic” project in Kuwait. Particularly, the alleged crimes would have been committed in order to illicitly influence the award of a construction contract outside Italy where Eni was the commissioning entity. Considering the claims of the Public Prosecutor, Eni and Saipem believed that they were damaged by the crimes committed by their employees. Eni considered those employees to have breached the Company’s Code of Ethics. In spite of this, Eni SpA and Saipem SpA were notified of being under investigation pursuant to the Legislative Decree No. 231/2001, which establishes the liability of entities for the crimes committed by their employees. Eni SpA was notified by the Public Prosecutor of a request of extension of the preliminary investigations that has led up to the involvement of another employee, as well as other suppliers in the proceeding. The Public Prosecutor of Milan requested Eni SpA to be debarred for one year and six months from performing any industrial activities involving the production sharing contract of 1997 with the Republic of Kazakhstan and in the subsequent administrative or commercial arrangements, or the prosecution of the mentioned activities under the supervision of a commissioner pursuant to Article 15 of the Legislative Decree No. 231 of 2001. On July 16, 2013, the Judge for Preliminary Investigation rejected the request for precautionary measures requested by the Public Prosecutor of Milan, because it considered the request groundless. The Public Prosecutor promptly appealed the decision before a higher degree court. After the appeal hearing, on October 21, 2013 such court rejected the appeal filed by the Public Prosecutor. The Re-examination Court rejected the appeal with judgment upon the merits due to the lack of serious evidence against Eni, accepting the defense arguments for which Eni suffered severe damages because of poor performances of some suppliers involved in the Kashagan project. In addition, the Court declared the lack of precautionary requirements considering the reorganization of the activities in Kazakhstan and taking into account of the initiatives of internal audit and control promptly adopted by Eni. The Public Prosecutor’s office did not appeal against the sentence of the Re-examination Court. Also based on this F-96 decision, on March 13, 2014, the Eni legal team requested to the Public Prosecutor to dismiss the proceeding. The Prosecutor’s Office filed a request for dismissal of all the natural persons, and, on 5 January 2017, the judge for preliminary investigations who issued the relevant decree granted the above-mentioned filing request. A similar measure is expected for Eni that was involved at the same proceeding pursuant to Legislative Decree no. 231/01. (iv) Block OPL 245 — Nigeria. On July 2, 2014, the Italian Public Prosecutor of Milan served Eni with a notice of investigation relating to potential liability on the part of Eni arising from alleged international corruption, pursuant to Italian Legislative Decree No. 231/2001 whereby companies are liable for the crimes committed by their employees when performing their tasks. As part of the proceeding, Eni was also subpoenaed for documents and other evidence. According to the subpoena, the proceeding was commenced following a claim filed by ReCommon NGO relating to alleged corruptive practices that according to the Prosecutor would have allegedly involved the Resolution Agreement made on April 29, 2011 relating to the Oil Prospecting license of the offshore oilfield that was discovered in Block 245 in Nigeria. Eni is fully cooperating with the Prosecutor and has promptly filed the requested documentation. Furthermore, Eni has voluntarily reported the matter to the U.S. Department of Justice and the U.S. SEC. In July 2014, the Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage an independent, US-based law firm, expert in anticorruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. After reviewing the matter, the US lawyers concluded in summary that no evidence of wrongdoing on Eni side were detected in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. The outcome of this review was transmitted to the judicial authorities. On September 10, 2014, the Public Prosecutor of Milan notified Eni of a restraining order issued by a British judge who ruled the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the Italian Public Prosecutor. The order was also notified to certain individuals, including Eni’s CEO and the Chief Development, Operations and Technological Officer, as well as Eni’s former CEO. From the available documents, it was inferred that such Eni’s officers and former officers are under investigation by the Italian Public Prosecutor. During a hearing before a Court of London on September 15, 2014, Eni and its current executive officers stated their non-involvement in the matter regarding the seized bank account. Following the hearing, the Court reaffirmed the seizure. On December 22 2016, Eni was notified of the conclusion of the preliminary investigation by the Italian Judicial Authorities. Following the request of the Public Prosecutor of Milan that the Eni’s CEO and the Chief Development, Operations and Technological Officer and the Executive Vice President for international negotiations, as well as Eni’s former CEO would stand trial, as well as Eni based on Italian law 231/2001 on corporate entity responsibility, on February 14, 2017, Eni’s attorneys were notified of the schedule of the preliminary hearing due on April 20, 2017. Upon notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor of Milan, the independent US-based law firm was requested by Eni to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the law firm prior review. The US law firm was also provided with the documentation filed in the Nigeria proceeding mentioned below. The independent U.S. law firm concluded that the reappraisal of the matter in light of the new documentations available did not alter the outcome of the prior review. On January 27, 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court, sitting in Abuja, upon request from the Economic and Financial Crime Commission (EFCC), attaching temporarily the property known as Oil Prospecting License 245 (“OPL 245”) pending the proceeding for alleged corruption and money laundering started in Nigeria. NAE made an application to discharge the Order (along with the Shell affiliate co-holder of the license). On March 17, 2017, the Nigerian Court discharged the Order. Recently, Eni became aware of a formal filing of charges by the EFCC. Eni has provided a copy of charges filed by the EFCC, to the US-based law firm engaged to review the OPL 245 transaction, who upon review of such documents, did not modify their conclusion according to which no evidence of wrongdoing on Eni side was detected in relation to the acquisition of the OPL 245 license from the Nigerian government. (v) Eni SpA Refining & Marketing Division — Criminal proceedings on fuel excise tax (Criminal proceeding N. 6159/10 RGNR the Italian Public Prosecutor in Frosinone and criminal proceeding No. 7320/14 RGNR the Italian Public Prosecutor in Rome). Two criminal proceedings are currently pending, relating to alleged evasion of excise taxes in the context of the retail sales at the fuel market. In particular, the claim states that the quantity of oil products marketed by Eni was larger than the quantity subjected to the excise tax. The first proceeding, opened by the Public Prosecutor’s Office of Frosinone against a third company (Turrizziani Petroli) purchaser of Eni’s fuel, is still pending in the phase of the preliminary investigation. This investigation was subsequently extended to Eni. The Company has cooperated fully with the F-97 the Fiscal Police from Frosinone, along with the local Customs Agency, proceeding and provided all data and information concerning the performance of the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. Eni ensured the best possible collaboration, handing in all the required documentation. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. After the ending of the investigation, in November 2013 issued a claim related to the evasion of the payment of excise taxes in the 2007 2012 periods for €1.55 million. In May 2014, the Customs Agency of Rome issued a payment notice relating to the abovementioned claim that was filed by the Fiscal Police and Customs Agency of Frosinone. The Company immediately appealed to the Tributary Commission. The second proceeding, opened by the Public Prosecutor’s Office of Rome, regarded alleged evasion of excise tax payment on the surplus of the unloading products, as quantity of such products was larger than the quantity reported in the supporting fiscal documents. This proceeding represents a development of the first proceeding mentioned above, and substantially concerns similar facts, with however some differences with regard to both the nature of the alleged crimes and the responsibility subjected to verification. In fact, the Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at the habitual subtraction of oil products at all of the 22 storage sites which are operated by Eni over the national territory. Eni is cooperating with prosecutor in order to defend the correctness of its operation. On September 30, 2014, a search was conducted at the office of the former chief operating officer of Eni’s Refining & Marketing Division as ordered by the Rome’s Public Prosecutor. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also relates to a period of time when he was in charge of that Eni’s Division. On March 5, 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. The three criminal proceedings were united together at Public Prosecutor’s Office of Rome, which is still conducting preliminary investigations. Ultimately, the Customs Agency, in reply to a request of the national association of refiners solicited by Eni, published a dedicated Circular which provides the rules the operators in the sector should follow to determine the quantity of oil products subjected to the excise tax, so as to give clarification to regional customs agencies, the Revenue Agency and the Finance Police. According to this Circular, Eni and other oil companies followed the correct procedures in order to determine the quantity subjected to the excise tax. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer to the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. On this occasion, it became clear that the proceeding has been extended to a large number of employees and former employees of the company. The proceeding is at the preliminary investigations. (vi) Block Marine XII, Congo. On July 9, 2015, Eni received from the U.S. Department of Justice a subpoena ordering the Company to produce documents in view of the hearing of an Eni employee, relating to the assets “Marine XII” in Congo and relationships with certain persons and companies. According to preliminary informal contacts between Eni’s U.S. lawyers and the Authority, this hearing is part of a broader investigation, which is currently being carried out with regard to third parties. Within such investigation, Eni is considered a witness and — potentially — a damaged party. The documents required by the Authority are currently being collected and filed with the Authority. 4. Tax Proceedings Italy (i) Eni SpA — municipal tax related to certain oil platforms located in the Italian territorial waters. Several tax proceedings are pending in Italy, as certain municipalities claimed Eni SpA omitted payments of a tax on property relating oil platforms located in the territorial waters under the municipality administration. After completing all degrees of judgment before Italian tax courts, on February 24, 2016, the Third Instance Court sentenced that: i) property taxes on platforms are due by Eni; ii) the taxable basis the replacement cost; is to be defined by considering the platforms carrying amounts, iii) sanctions are not applicable. The proceeding continued with an indictment before a trial judge to determine the due amount. In a similar proceeding relating to another oil company, the Third Instance Court confirmed that these industrial installations might be subject to this local tax. Based on the outcomes instead of F-98 of these resolutions, Eni started an out of court procedure to reach a settlement on the matter with the local authorities who submitted claims against the Company based on the taxability of oil platforms. This settlement will be pursued on condition that the local authorities agree with Eni a fair tax base and renounce any claim of sanctions as established by the Third Instance Court which resolved the inapplicability of any sanction to the matter in the case involving a local municipality. Based on the expectation of management to successfully conclude these settlements, Eni accrued a tax provision. (ii) Eni SpA — Excise taxes. On May 31, 2016 the Customs Agency issued to Eni a payment notice for a total sum of €134 million (of which €114 million referring to excise taxes and €20 million referring to interests), in addition to fines amounting to €34 million. This followed a claim filed in 2011, referring to legal proceeding started by the Court of Milan in 2010 pertaining to alleged culpable omission to pay excise taxes (for the period 2003 – 2008) due on 9.8 billion cubic meters of natural gas marketed by Eni in Italy. With a sentence dated June 28, 2012 the Public Prosecutor of Milan the Tribunal resolved to dismiss the proceeding against all defendants because the fact did not constitute an offence. In addition, the appeal filed by the Public Prosecutor was rejected by a final-degree Court with sentence dated July 3, 2013 and filed on January 7, 2014. With regard to the administrative proceeding, considering the documentation filed by Eni in the aftermath, the volumes allegedly subtracted to tax payment were reduced to 650 million cubic meters. Thus, the corresponding amount of allegedly due excise taxes decreased from €1.7 billion, initially claimed by the Public Prosecutor, to €114 million. Like the initial claim, the residual claim appears to be groundless, taking into account the fact that the gas volumes input into the national grid by Eni and gas volumes off-taken at each delivery points for reselling to final customers have different calorific power. This was confirmed by the opinion of sector experts and acknowledged by the Customs Agency itself during the consultation process with the Italian association of gas resellers. Therefore, the Customs Agency issued a new administrative claim configuring erroneous compilation of the consumption declaration only. The Customs Agency reiterated the claim because — even if the incidence of the calorific value has been acknowledged from a technical and scientific point of view and shared by the Agency itself, — at the same time the matter has not been explicitly regulated by an administrative act. In order to safeguard the Company’s assets, Eni’s management commenced the following initiatives: (i) an administrative claim has been filed in order to suspend the tax collection, accepted by the Customs Agency; (ii) an appeal against the Agency’s claim before a Tax Judge has been filed whose discussion hearing is scheduled. Based on current information and taking into account the outcome of the criminal litigation, the objections presented are considered groundless and, therefore, the Company did not accrue any tax provision in the consolidated financial statements 2016. Outside Italy (iii) Eni Angola Production BV. The tax Authorities of Angola filed a notice of tax assessment in which it claimed the improper deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as partner of the Cabinda concession. The company paid the higher taxes under contestation for the years 2002 – 2006, requiring the recognition of its position for subsequent years and, accordingly, filed an appeal against this decision. The judgment is still pending before the Supreme Court. The tax authorities also contested to Eni Angola Production BV and to Eni Angola Exploration BV the recovery of certain costs (cost oil) for the tax years from 2003 to 2009, in relation to licenses regulated by oil contracts in Production Sharing Agreements, and that would result in a payment of further taxes on the higher profit oil resulting from the lack of the recognition of such costs. The companies contested the legitimacy of the claim formulated by the Ministry of Finance either as the power to approve the cost oil (recoverable costs) and the shares of profit oil contract lies solely to Sonangol (first party in the oil contract), or the tax deductibility of such costs. The companies have presented an appeal that is waiting to be discussed. Eni accrued a tax provision with respect to this proceeding. 5. Settled proceedings (i) Action commenced by the Municipality of Carrara for the remediation and reestablishment of previous In relation to the environmental conditions at the Avenza site and payment of environmental damage. proceeding brought by the Municipality of Carrara and the Ministry for the Environment against Syndial SpA for the compensation of alleged environmental damages at the Avenza site. The proceeding was closed without ascertaining any responsibility of the company. In particular the Minister indicated Syndial as F-99 responsible for environmental damages on the belief that: a) Syndial was liable for the environmental damage as the Eni subsidiary took over the site from the previous owners assuming all existing liabilities; b) it was responsible for managing the plant and inadequately remediating the site after the occurrence of an incident in 1984; c) it was responsible for omitted clean-up. Syndial established itself as defendant. The Third Instance Court sentenced that only the first motivation of the appeal filed by the Ministry is valid, which related to the statute of limitations for the crime of disaster applicable exclusively to the previous owners of the site. Therefore, the Court has definitely confirmed that Syndial is not liable, neither for activities directly conducted (including alleged delay/omission of the clean-up activities claimed by the Ministry) nor for strict liability (as it took over the site from the previous owners). Particular attention should be paid to this second profile in the light of the fact that the Avenza site was transferred to Eni due to a law provision. (ii) Eni SpA — Investigation for alleged violations of the Consumer Code in the matter of billing of gas In relation to the proceeding brought by the Italian Antitrust Authority and power consumptions. (AGCM) in regard of alleged unfair commercial practices under the Consumer Code in the billing of gas and power consumptions to retail customers, after the conclusion of the investigation, the AGCM notified Eni its final ruling by imposing to the company a sanction of €3.6 million. The sanction has been paid. Eni appealed the decision to the Regional Administrative Court. (iii) Fatal accident Truck Center Molfetta — Prosecuting body: Public Prosecutor of Trani. In relation to a fatal accident occurred in March 2008 that caused the death of four workers deputed to the cleaning of a tank car used for the transportation of liquid sulphur produced by Eni in the Refinery of Taranto, the Public Prosecutor of Trani accused Eni and eight employees of the company for alleged manslaughter, grievous bodily harm and illegal disposal of waste materials. The decision of a first instance court which ruled acquittal for all the defendants and for Eni SpA, as legal entity, with the wide formula “because the alleged fact does not exist” was upheld in the subsequent degrees of judgments and became final on July 27, 2016. (iv) Eni SpA — Reorganization procedure of the airlines companies Volare Group, Volare Airlines and In relation to the bankruptcy clawback as part Air Europe — Prosecuting body: Delegated Commissioner. of the reorganization procedure filed by the airlines companies Volare Group, Volare Airlines and Air Europe and the request of override of all the payments made by those entities to Eni in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, the Court of Appeal of Milan ruled Eni to return a total amount of €9 million. The plaintiffs requested that the sentence against Eni would be reassessed to an amount of about €18 million. The proceeding is pending before a third-degree court. Eni accrued a provision in respect to this proceeding. The proceeding is no longer significant. (v) Investigation by the Italian Antitrust about Eni’s determination of Italian market share of the Italian gas wholesale market. With Resolution No. 25064 of August 1, 2014, the Italian Antitrust commenced an investigation to verify whether Eni controlled a bigger share of the domestic wholesale gas market than it had declared. Following the Legislative Decree No. 130 of 2010, which envisages a 55% ceiling to the wholesale market share for each Italian gas operator who inputs gas into the Italian backbone network, Eni declared that its market share was equal to 54%, therefore slightly below the established threshold. Eni calculated its market share by excluding certain sales of gas volumes. On the other hand, the Antitrust rejected this calculation method and therefore concluded that Eni’s market share was actually 56%. Nonetheless, the Antitrust decided not to impose any fine on the Company as the violation was immaterial. The Antitrust considered the fact that in its declaration Eni explained clearly how its market share was calculated. Besides that, in the opinion of the Ministry of Economic Development, expressed during the investigation, Eni calculated its market share correctly. Eni filed an appeal against the Antitrust’s decision before the Regional Administrative Court of Lazio, asking for annulment. Management does not expect any liability in connection with this proceeding. 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, F-100 in some legal contexts, private owners. Pursuant to the assignment of mineral concession, 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 on the basis of quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration. Environmental regulations Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the “Financial Review”, paragraph “Risk factors and uncertainties”. In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree No. 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries. Emission trading From 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The new phase marked a significant change in the method of awarding emission allowance from a no-consideration scheme based on historical emissions to allocation through auctioning. For the period 2013 – 2020, the award of free emission allowances is performed based on European benchmarks specific to each industrial segment, except for the thermoelectric sector that is not eligible for allocations for no consideration. This regulatory scheme implies for Eni’s plants subjected to emission trading a lower assignment of emission permits respect to the emissions recorded in the relevant year and, consequently, the necessity of covering the amounts in excess by purchasing the relevant emission allowances on the open market. In 2016, the emissions of carbon dioxide from Eni’s plants were higher than the free allowances assigned to Eni. Against emissions of carbon dioxide amounting to approximately 20.22 million tonnes, Eni was awarded free emission allowances of 7.06 million tonnes, determining a deficit of 13.16 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market. 39 Revenues Net sales from operations (€ million) Revenues from sales and services .................................... Change in contract work in progress ............................... 2014 98,256 (38) 98,218 2015 72,290 (4) 72,286 2016 55,764 (2) 55,762 F-101 Revenues from sales were stated net of the following items: (€ million) Excise taxes ................................................................... Exchanges of oil sales (excluding excise taxes) ......................... Services recharged to joint venture partners ........................... Sales to service station managers for sales billed to holders of credit cards .................................................................... 2014 12,289 1,586 5,191 1,804 20,870 2015 11,889 1,154 5,609 1,643 20,295 2016 11,913 878 4,441 1,553 18,785 Net sales from operations by industry segment and geographical area of destination are disclosed in note 46 — Information by industry segment and by geographical area. Net sales from operations with related parties are disclosed in note 47 — Transactions with related parties. Other income and revenues (€ million) Gains on price adjustments under overlifting/underlifting transactions ................................................................... Compensation for damages ................................................ Lease and rental income .................................................... Contract penalties and other trade revenues ........................... Gains from sale of assets ................................................... Other proceeds(*) ............................................................ 2014 390 43 92 37 84 433 1,079 2015 253 36 85 36 457 385 1,252 2016 238 122 81 72 14 404 931 (*) Each individual amount included herein was lower than €50 million. Compensations of €122 million related to a loss in property value following an accident occurred at the EST conversion plant at the Sannazzaro refinery, which resulted in a write-off of the damaged units for €193 million and the recognition of a provision for removal and cleanup of €24 million. The portion of losses not covered by the insurance compensation (€95 million) corresponds to the risk retained by Eni. Other income and revenues with related parties are disclosed in note 47 — Transactions with related parties. 40 Operating expenses Purchase, services and other (€ million) 2014 2015 2016 Production costs - raw, ancillary and consumable materials and goods ........................................................................... Production costs - services ................................................. Operating leases and other ................................................. Net provisions for contingencies .......................................... Expenses for price variation on overliftling and underlifting operations ..................................................................... Other expenses ............................................................... less: - capitalized direct costs associated with self-constructed assets - tangible assets .............................................................. - capitalized direct costs associated with self-constructed assets - intangible assets ........................................................... 60,987 12,414 2,655 340 409 918 77,723 (238) (81) 77,404 39,812 13,197 2,205 644 278 1,135 57,271 (323) (100) 56,848 27,783 12,727 1,672 505 240 1,512 44,439 (297) (18) 44,124 F-102 Service costs include geological and geophysical expenses related to the exploration activities of the Exploration & Production segment amounting to €204 million (€368 million and €254 million in 2014 and 2015, respectively). Costs incurred in connection with research and development activity recognized in profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €161 million (€174 million and €176 million in 2014 and 2015, respectively). Operating leases and other comprised operating leases for €566 million (€559 million and €635 million in 2014 and 2015, respectively) and royalties on the extraction of hydrocarbons for €572 million (€1,278 million and €865 million in 2014 and 2015, respectively). Other expenses of €1,512 million (€918 million and €1,135 million in 2014 and 2015, respectively) included provisions to the reserve of allowance for doubtful accounts of trade receivables of the Gas & Power segment, primarily in the retail business, for €399 million (€549 million in 2015). Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below: (€ million) To be paid: - within 1 year .............................................................. - between 2 and 5 years ................................................. - beyond 5 years ........................................................... 2014 2015 2016 522 1,114 726 2,362 495 1,061 809 2,365 593 1,040 785 2,418 Operating leases primarily regarded drilling rigs, time charter and long-term rentals of vessels, land, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases that may limit the ability of Eni to pay dividends, use assets or take on new borrowing. Risk provisions net of reversal of unused provisions amounted to €505 million (€340 million and €644 million in 2014 and 2015, respectively) and mainly related to net provisions for environmental liabilities amounting to €198 million (net provisions of €177 million and €232 million in 2014 and 2015, respectively) and net provisions for litigations amounting to €55 million (net provisions of €35 million and €179 in 2014 and 2015, respectively). More information is provided in note 30 — Provisions for contingencies. Risk provisions net of reversal of unused provisions are disclosed in note 46 — Information by industry segment and by geographical area. Payroll and related costs (€ million) Wages and salaries ........................................................ Social security contributions .......................................... Cost related to employee benefit plans ............................ Other costs .................................................................. 2014 2,590 445 73 160 3,268 less: - capitalized direct costs associated with self-constructed assets - tangible assets ................................................. (278) - capitalized direct costs associated with self-constructed assets - intangible assets .............................................. (61) 2,929 2015 2,648 453 85 182 3,368 (203) (46) 3,119 2016 2,491 445 81 202 3,219 (215) (10) 2,994 Other costs of €202 million (€160 million and €182 million in 2014 and 2015, respectively) comprised provisions for redundancy incentives of €47 million (€5 million and €31 million in 2014 and 2015, respectively) and costs for defined contribution plans of €83 million (€85 million and €86 million in 2014 and 2015, respectively). F-103 Cost related to employee benefit plans are described in note 31 — Provisions for employee benefits. Average number of employees The Group average number and breakdown of employees by category is reported below: 2014 2015 2016 (number) Subsidiaries Joint operations Subsidiaries Joint operations Subsidiaries Joint operations Senior managers ......... Junior managers .......... Employees .................. Workers ..................... 1,049 8,912 18,143 6,358 34,462 25 121 595 559 1,300 1,044 9,091 17,685 5,895 33,715 17 108 379 303 807 1,018 9,160 17,180 5,703 33,061 18 109 384 294 805 The above Group average number do not include employees of discontinued operations (Saipem Group). The average number of employees was calculated as the average between the number of employees at the beginning and the end of the period. The average number of senior managers included managers employed and operating in foreign countries, whose position is comparable to a senior manager’s status. Compensation of key management personnel Compensation of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office during the year (including contributions and ancillary costs) amounted to €43 million, €42 million and €44 million for 2014, 2015 and 2016, respectively, and consisted of the following: (€ million) 2014 2015 2016 Wages and salaries ........................................................ Post-employment benefits .............................................. Other long-term benefits ............................................... Indemnities upon termination of employment .................. 25 2 10 6 43 26 2 12 2 42 26 2 12 4 44 Compensation of Directors and Statutory Auditors Compensation of Directors amounted to €10.1 million, €6.7 million and €7.1 million for 2014, 2015 and 2016, respectively. Compensation of Statutory Auditors amounted to €0.419 million, €0.551 million and €0.738 million in 2014, 2015 and 2016, respectively. Compensation included emoluments and social security benefits due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group, even if not subject to personal income tax. Other operating income (loss) The analysis of net income (loss) on commodity derivatives was as follows: (€ million) Net income (loss) on cash flow hedging derivatives ........... Net income (loss) on other derivatives ............................. 2014 (133) 278 145 2015 2 (487) (485) 2016 (1) 17 16 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. F-104 Net income (loss) on other derivatives included: (i) the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading amounting to a net income of €36 million (net income of €247 million in 2014 and net loss of €471 million in 2015); and (ii) the fair value valuation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts of the Exploration & Production segment amounting to a net loss of €19 million (net income of €31 million in 2014 and net loss of €16 million in 2015). Operating expenses with related parties are reported in note 47 — Transactions with related parties. Depreciation and amortization (€ million) 2014 2015 2016 Depreciation, depletion and amortization: - tangible assets ............................................................ - intangible assets ......................................................... less: - capitalized direct costs associated with self-constructed assets - tangible assets ................................................... 7,356 326 7,682 (6) 7,676 8,646 303 8,949 (9) 8,940 7,308 253 7,561 (2) 7,559 Depreciation and amortization by industry segment are disclosed in note 46 – Information by industry segment and by geographical area. Net impairment (reversal) (€ million) 2014 2015 2016 Impairments: - tangible assets ............................................................ - intangible assets ......................................................... less: - reversal of impairments - tangible assets ........................ - reversal of impairments - intangible assets ..................... 1,196 138 1,334 (64) 5,993 544 6,537 (3) 1,270 6,534 1,067 1,067 (1,153) (389) (475) Net impairment (reversal) by industry segment are disclosed in note 46 — Information by industry segment and by geographical area. Write-off (€ million) Write-off - tangible assets ............................................................ - intangible assets ......................................................... 2014 936 262 1,198 2015 678 10 688 2016 289 61 350 Write-off by industry segment are disclosed in note 46 — Information by industry segment and by geographical area. F-105 41 Finance income (expense) (€ million) 2014 2015 2016 Finance income (expense) Finance income ............................................................ Finance expense ........................................................... Net finance income (expense) from financial assets held for trading ........................................................................ Income (expense) from derivative financial instruments ..... 5,701 (7,057) 24 (1,332) 165 (1,167) 8,635 (10,104) 3 (1,466) 160 (1,306) 5,850 (6,232) (21) (403) (482) (885) The breakdown by lenders or type of net finance income or expense is provided below: (€ million) 2014 2015 2016 Finance income (expense) related to net borrowings Interest and other finance expense on ordinary bonds ....... Interest due to banks and other financial institutions ........ Interest and other income from financial receivables and securities held for non-operating purposes ....................... Interest from banks ...................................................... Net finance income (expense) from financial assets held for trading ........................................................................ Exchange differences Positive exchange differences .......................................... Negative exchange differences ........................................ Other finance income (expense) Capitalized finance expense ........................................... Interest and other income on financing receivables and securities held for operating purposes .............................. Finance expense due to the passage of time (accretion discount)(a) .................................................................. Other finance (expense) ................................................. (759) (112) 26 19 24 (802) 5,430 (5,845) (415) 163 74 (293) (59) (115) (1,332) (740) (98) 2 19 3 (814) 8,400 (8,754) (354) 166 120 (291) (293) (298) (1,466) (a) The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities. Finance income (loss) on derivative financial instruments consisted of the following: (€ million) Options ....................................................................... Derivatives on exchange rate .......................................... Derivatives on interest rate ............................................ 2014 68 51 46 165 2015 33 96 31 160 (639) (118) 37 15 (21) (726) 5,579 (4,903) 676 106 143 (312) (290) (353) (403) 2016 24 (494) (12) (482) Net loss from derivatives of €482 million (net income of €165 million and €160 million in 2014 and 2015, respectively) was recognized in connection with fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. The lack of formal requirements to qualify these derivatives as F-106 hedges under IFRS also entailed the recognition in profit or loss of currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments. Net income on options of €24 million (net income of €68 million and €33 million in 2014 and 2015, respectively) related to: (i) the reversal through profit and loss of the fair value reserve relating to the embedded options of the bond convertible into ordinary shares of Snam SpA amounting to an income of €26 million (income of €23 million and €33 million in 2014 and 2015, respectively); (ii) the fair value of the option embedded in non-dilutive equity-linked convertible bond for a net loss of €2 million. In 2014, the measurement at fair value of the options embedded in the bond convertible into ordinary shares of Galp Energia SGPS SA resulted in an income of €45 million. More information is provided in note 29 — Long-term debt and current portion of long-term debt. More information finance income (expense) is provided in note 47 — Transactions with related parties. 42 Income (expense) from investments Share of profit (loss) of equity-accounted investments (€ million) Share of profit from equity-accounted investments .................... Share of loss from equity-accounted investments ....................... Decreases (increases) in the provision for losses on investments from equity accounted investments .......................................... 2014 188 (77) (1) 110 2015 150 (615) (6) (471) 2016 77 (370) (33) (326) More information is provided in note 20 – Investments. Share of profit (loss) of equity accounted investments by industry segment is disclosed in note 46 — Information by industry segment and by geographical area. Other gain (loss) from investments (€ million) Dividends .................................................................... Net gain (loss) on disposals ............................................ Other net income (expense) ............................................ 2014 385 160 (179) 366 2015 402 164 10 576 2016 143 (14) (183) (54) In 2016, dividend income of €143 million essentially related to Nigeria LNG Ltd for €76 million and to Saudi European Petrochemical Co for €45 million. In 2015, dividend income of €402 million primarily related to Nigeria LNG Ltd for €222 million, Snam SpA for €72 million, Saudi European Petrochemical Co for €69 million and Galp Energia SGPS SA for €21 million. In 2014, dividend income of €385 million related to the Nigeria LNG Ltd for €247 million, Saudi European Petrochemical Co for €57 million, Snam SpA for €43 million and Galp Energia SGPS SA for €22 million. In 2016, net loss on disposals amounting to €14 million related to: (i) a loss of €32 million for the sale of 2.22% share capital (entire stake owned) of Snam SpA; (ii) a gain of €11 million related to the sale of 100% share capital of Eni Hungaria Zrt and Eni Slovenjia doo; and (iii) a gain of €6 million related to the F-107 sale of 30% share capital (entire stake owned) of Pokrovskoe Petroleum BV and the sale of the 60% share capital (entire stake owned) of Zagoryanska Petroleum BV. In 2015, net gains on disposals amounting to €164 million related to: (i) a gain of €98 million for the sale of an 8% stake in Galp Energia SGPS SA; (ii) a gain of €46 million for the sale of a 6.03% stake in Snam SpA; (iii) a gain of €32 million for the sale of 100% stake in Ceská Republika Sro; (iv) a gain of €31 million for the sale of a 100% stake of Eni Romania Srl; (v) a gain of €6 million for the sale of 32.445% stake (entire stake owned) in Ceská Rafinérská AS (CRC); (vi) a gain of €1 million of 100% stake in Eni Slovensko Spol Sro; and (vii) a loss of €47 million for the sale of a 76% stake in Inversora de Gas Cuyana SA (entire stake owned), a 6.84% stake in Distribudora de Gas Cuyana SA (entire stake owned), a 25% stake in Inversora de Gas del Centro SA (entire stake owned) and a 31.35% stake in Distribudora de Gas del Centro SA (entire stake owned). In 2014, net gains on disposals amounting to €160 million related to: (i) €96 million for the sale of a 8.15% of the share capital of Galp Energia SGPS SA, of which €77 million related to the reversal of the reserve for fair value measurement; (ii) €54 million for the sale of a 20% (entire stake owned) of the share capital of South Stream Transport BV to Gazprom; and (iii) €9 million for the sale of a 50% (entire stake owned) of the share capital of EnBW Eni Verwaltungsgesellschaft mbH to EnBW Energie Baden-Württemberg AG. In 2016, other net losses of €183 million included: (i) an impairment for €162 million relating to Unión Fenosa Gas SA (€84 million), PetroSucre (€65 million) and Genomatica Inc (€13 million). In 2015, other net income of €10 million included: (i) a gain on the remeasurement at market fair value of 77.7 million shares of Snam SpA for €49 million to which the fair value option was applied as provided for by IAS 39; (ii) a reversal of unutilized provision for losses on investments of €10 million relating to Caspian Pipeline Consortium R — Closed Joint Stock Co; and (iii) an impairment for €49 million relating to Unión Fenosa Gas SA. In 2014, other net expense of €179 million included the remeasurement at market fair value at the balance sheet date of 66.3 million shares of Galp Energia SGPS SA (loss for €231 million at the price of €8.43 per share) and of 288.7 million shares of Snam SpA (income for €10 million at the price of €4.1 per share). The valuation of the shares of these investments was based on the fair value option as underlying two convertible bonds. More information is provided in note 20 – Investments. 43 Income taxes (€ million) 2014 2015 2016 Current taxes: - Italian subsidiaries ...................................................... - subsidiaries of the Exploration & Production segment - outside Italy ............................................................... - other subsidiaries - outside Italy ................................... Net deferred taxes: - Italian subsidiaries ...................................................... - subsidiaries of the Exploration & Production segment - outside Italy ............................................................... - other subsidiaries - outside Italy ................................... (573) 6,512 116 6,055 369 79 (37) 411 6,466 155 4,015 218 4,388 881 (2,156) 9 (1,266) 3,122 195 2,671 133 2,999 (243) (813) (7) (1,063) 1,936 Current income taxes payable by Italian subsidiaries amounted to €195 million and were in respect of the Italian corporate taxation (IRES for €12 million and IRAP for €7 million) and foreign taxes on the share of profit earned outside Italy for €176 million. F-108 The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 27.5% (same amount in 2014 and in 2015) and the effective tax charge is the following: (€ million) Profit (loss) before taxation ............................................ Tax rate (IRES) (%) ...................................................... Statutory corporation tax charge (credit) on profit or loss .... Increase (decrease) resulting from: - higher tax charges related to subsidiaries outside Italy ..... - impact pursuant to the write-off of deferred tax assets 2014 8,274 27.5 2,275 4,065 and recalculation of tax rates ....................................... 1,002 - effect due to the tax regime provided for intercompany dividends ................................................................... - Italian regional income tax (IRAP) ............................... - effect due to non-taxable gains/losses on sales of investments .................................................................. - impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009 ....................... - effect due to discontinued operations ............................ - other adjustments ....................................................... Effective tax charge ....................................................... 51 5 25 (825) (97) (35) 4,191 6,466 2015 (4,277) 27.5 (1,176) 2,576 1,514 114 100 (39) (288) 321 4,298 3,122 2016 892 27.5 245 1,152 397 87 42 8 5 1,691 1,936 In 2016, the higher tax charges at non-Italian subsidiaries of €1,152 million related to the Exploration & Production segment for €1,211 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €397 million was incurred at Italian subsidiaries and essentially related to a write-off at deferred tax assets due to projections of lower future taxable profit. In 2015, the higher tax charges at non-Italian subsidiaries of €2,576 million related to the Exploration & Production segment for €2,410 million, including a write-off of deferred tax assets due to a reduced profitability outlook of €1,058 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,514 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit and to a reduction due to a change in the statutory tax rate from 27.5% to 24%, starting from January 1, 2017. The effect due to the Italian regional income tax (IRAP) of €100 million included a write-off at deferred tax assets due to projections of lower future taxable profit for €54 million. In 2014, the higher tax charges at non-Italian subsidiaries of €4,065 million essentially related to the Exploration & Production segment. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,002 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit for €526 million and to a lower prospective tax rate in relation to the windfall tax (the so-called Robin Tax) provided by Article 81 of the Legislative Decree No. 112/2008 which was assessed to be no more recoverable as, in February 2015, by the Third Instance Court for €476 million. This sentence stated the illegitimacy of a tax rule prospectively, denying any reimbursement rights. 44 Earnings per share Weighted average number of shares used for the calculation of the basic and diluted earnings per share .... Eni’s net profit .................................................... (€ million) Basic and diluted earning (loss) per share .................. (euro per share) Eni’s net profit - Continuing operations....................... (€ million) Basic and diluted earning (loss) per share .................. (euro per share) Eni’s net profit - Discontinued operations .................... (€ million) Basic and diluted earning (loss) per share .................. (euro per share) 2014 2015 2016 3,610,387,582 3,601,140,133 3,601,140,133 (1,464) (0.41) (1,051) (0.29) (413) (0.12) (8,778) (2.44) (7,952) (2.21) (826) (0.23) 1,303 0.36 1,720 0.48 (417) (0.12) Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares. F-109 The average number of ordinary shares used for the calculation of the basic earnings per share outstanding at December 31, 2014, 2015 and 2016 was 3,610,387,582, 3,601,140,133 and 3,601,140,133, respectively. There were no pending issues of new shares that could dilute earnings at the reporting date. 45 Exploration and evaluation of oil&gas resources (€ million) Revenues related to exploration activity and evaluation ....... Exploration activity and evaluation costs - write-off of exploration and evaluation costs ................. - other exploration costs ................................................ Exploration expense for the year ...................................... Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs .......................... Tangible assets: capitalized exploration and evaluation costs ........................................................................... Total tangible and intangible assets................................... Provision for decommissioning related to exploration activity and evaluation .............................................................. Exploration expenditure (net cash used in investing activities) ..................................................................... Geological and geophysical costs (cash flow from operating activities) ..................................................................... Total exploration effort .................................................. 2014 1 1,110 368 1,478 1,081 2,577 3,658 126 1,030 368 1,398 2015 68 617 254 871 735 2,637 3,372 131 566 254 820 2016 4 170 204 374 1,092 2,818 3,910 118 417 204 621 46 Segmental analysis Reportable segments Eni’s segmental reporting reflects the Group’s operating segments, whose results are regularly reviewed by the chief operating decision maker (the CEO) to make decisions about resources to be allocated to each segment and to assess segment performance. Segment performance is evaluated based on operating profit or loss. Other segment information presented to the CEO include segment revenues and directly attributable assets and liabilities. Due to cessation of classification of the Chemical business as held for sale and the requirements that financial statements must be amended retrospectively to the date of initial classification (December 31, 2015) as though this disposal group never qualified as held for sale, the Group segmental reporting has been restated accordingly. The results of the Chemical business were aggregated with Refining & Marketing in a single reportable segment because these two operating segments exhibit similar economic characteristics. Furthermore, results of the E&P segment were restated following adoption of the Successful Efforts Method (SEM) (see note 1 – Basis of preparation). As of December 31, 2016, Eni had the following reportable segments: • • Exploration & Production: is engaged in exploring for and recovering crude oil and natural gas, including participation to projects for the liquefaction of natural gas; Gas & Power: is engaged 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 engaged in supply and marketing of crude oil and oil products targeting the operational requirements of Eni’s refining business and in commodity trading (including crude oil, natural gas, oil products, power, emission allowances, etc.) targeting to both hedge and stabilize the Group industrial and commercial margins according to an integrated view and to optimize margins. F-110 • • Refining & Marketing and Chemical: is engaged in manufacturing, supply and distribution and marketing activities for oil products and chemical products. Corporate and other activities: represents the key support functions, comprising holdings and treasury, headquarters, central functions like IT, HR, real estate, captive insurance activities, as well as the Group environmental cleanup and remediation activities performed by the subsidiary Syndial. The Energy Solutions Department, which engages in developing the business of renewable energy, is an operating segment which is reported within Corporate and other activities because it does not meet the materiality threshold for separate segment reporting. The information by segmental reporting is the following: (€ million) 2014 Net sales from operations(a) . . . . . . . Less: intersegment sales . . . . . . . . . . . Net sales to customers . . . . . . . . . . . . . Operating profit . . . . . . . . . . . . . . . . . . . Net provisions for contingencies . . Depreciation and amortization . . . Net Impairments/reversal . . . . . . . . . Write-off . . . . . . . . . . . . . . . . . . . . . . . . . . . Share of profit (loss) of equity-accounted investments . . . . Identifiable assets(b) . . . . . . . . . . . . . . . Unallocated assets . . . . . . . . . . . . . . . . . Equity-accounted investments . . . . Identifiable liabilities(c) . . . . . . . . . . . . Unallocated liabilities . . . . . . . . . . . . . Capital expenditure . . . . . . . . . . . . . . . . 2015 Net sales from operations(a) . . . . . . . Less: intersegment sales . . . . . . . . . . . Net sales to customers . . . . . . . . . . . . . Operating profit . . . . . . . . . . . . . . . . . . . Net provisions for contingencies . . Depreciation and amortization . . . Net Impairments/reversal . . . . . . . . . Write-off . . . . . . . . . . . . . . . . . . . . . . . . . . . Share of profit (loss) of equity-accounted investments . . . . Identifiable assets(b) . . . . . . . . . . . . . . . Unallocated assets . . . . . . . . . . . . . . . . . Equity-accounted investments . . . . Identifiable liabilities(c) . . . . . . . . . . . . Unallocated liabilities . . . . . . . . . . . . . Capital expenditure . . . . . . . . . . . . . . . . 2016 Net sales from operations(a) . . . . . . . Less: intersegment sales . . . . . . . . . . . Net sales to customers . . . . . . . . . . . . . Operating profit . . . . . . . . . . . . . . . . . . . Net provisions for contingencies . . Depreciation and amortization . . . Net Impairments/reversal . . . . . . . . . Write-off . . . . . . . . . . . . . . . . . . . . . . . . . . . Share of profit (loss) of equity-accounted investments . . . . Identifiable assets(b) . . . . . . . . . . . . . . . Unallocated assets . . . . . . . . . . . . . . . . . Equity-accounted investments . . . . Identifiable liabilities(c) . . . . . . . . . . . . Unallocated liabilities . . . . . . . . . . . . . Capital expenditure . . . . . . . . . . . . . . . . Exploration & Production Gas & Power Refining & Marketing and Chemical Engineering & Construction Corporate and other activities Adjustments of intragroup profits Total Engineering & Construction Intragroup eliminations Continuing operations Discontinued operations 28,488 (16,618) 11,870 10,727 29 6,916 851 1,197 62 72,917 2,016 19,152 10,156 21,436 (12,115) 9,321 (959) 221 8,080 5,212 686 73,434 (14,251) 59,183 64 (26) 335 25 42 19,342 772 12,141 28,994 (2,042) 26,952 (2,811) 152 381 380 1 4 13,313 228 4,093 172 819 52,096 (9,917) 42,179 (1,258) 41 363 152 2 22,639 (2,007) 20,632 (1,567) 148 454 1,150 12,873 (1,244) 11,629 18 154 737 420 21 14,210 120 6,171 694 11,507 (1,243) 10,264 (694) 104 618 590 (446) 73,073 (2) 14,290 (20) 10,483 17 13,608 1,884 17,742 690 9,313 243 3,657 9,980 154 628 134 5,861 561 16,089 (9,711) 6,378 2,567 123 6,772 (700) 153 40,961 (8,898) 32,063 (391) 50 354 81 2 18,733 (1,605) 17,128 723 171 389 104 195 (198) 75,716 19 12,014 (3) 10,712 1,626 17,433 592 8,923 289 3,968 1,429 (1,270) 159 (518) 188 70 14 2 1,300 36 3,903 113 1,468 (1,314) 154 (497) 226 71 20 (3) 1,117 36 3,824 64 1,343 (1,150) 193 (681) 438 72 40 (144) 1,146 1,533 3,939 54 54 398 (3) (26) (486) (165) (82) (23) 8 (28) (543) (199) (85) (61) (277) (28) (520) (332) 8,254 120 664 55 87 109,847 7,878 494 8,413 1,690 1,198 131 120,596 29,770 3,172 45,295 39,430 11,872 82,550 (4,998) 748 9,558 7,124 688 (454) 112,028 26,973 2,987 40,198 41,394 11,302 55,762 2,157 505 7,559 (475) 350 (326) 99,068 25,477 4,040 33,931 37,528 9,180 1,105 1,228 (11,629) (18) (154) (737) (420) (21) (10,264) 694 (104) (618) (590) (17) (134) 98,218 8,965 340 7,676 1,270 1,198 110 72,286 (3,076) 644 8,940 6,534 688 (471) 2,853 55,762 2,157 505 7,559 (475) 350 (326) (a) (b) (c) Before elimination of intersegment sales. Includes assets directly associated with the generation of operating profit. Includes liabilities directly associated with the generation of operating profit. F-111 Financial information by geographical area Identifiable assets and investments by geographical area of origin (€ million) Other European Union Italy Rest of Europe Americas Asia Africa Other areas Total 2014 Identifiable assets(a) ....................................... 26,722 Capital expenditure in tangible and intangible assets ..................................................... 1,757 2015 Identifiable assets(a) ....................................... 21,360 Capital expenditure in tangible and intangible assets ..................................................... 1,320 2016 Identifiable assets(a) ....................................... 18,769 Capital expenditure in tangible and intangible assets ..................................................... 1,163 15,254 9,099 8,559 21,105 37,976 1,881 120,596 827 1,378 1,165 1,904 4,689 152 11,872 12,370 7,937 7,442 22,359 38,927 1,633 112,028 708 1,151 727 2,326 5,020 50 11,302 7,370 6,960 5,397 19,471 39,812 1,289 99,068 331 460 233 1,978 5,004 11 9,180 (a) Includes assets directly associated with the generation of operating profit. Sales from operations by geographical area of destination (€ million) Italy ............................................................................ Other European Union ................................................. Rest of Europe ............................................................. Americas ..................................................................... Asia ............................................................................ Africa ......................................................................... Other areas .................................................................. 2014 29,234 29,298 11,975 5,763 12,840 8,786 322 98,218 2015 24,405 20,730 7,125 4,217 9,086 6,482 241 72,286 2016 21,280 15,808 4,804 3,212 5,619 4,865 174 55,762 47 Transactions with related parties In the ordinary course of its business, Eni enters into transactions regarding: (a) exchange of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries; (b) exchange of goods and provision of services with entities controlled by the Italian Government; (c) relations with Vodafone Italia SpA related to Eni SpA through a member of the Board of Directors. These transactions mainly involve costs for mobile communication services for €7 million, awarded following a competitive procedure, and therefore exempted from the application of the internal procedure of Eni “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, or, if not exempted, positively evaluated in accordance with such procedure; and (d) contributions to entities with a non-company form referable to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as research and development; and (ii) Eni Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business. F-112 Trade and other transactions with related parties (€ million) December 31, 2014 2014 Name Continuing operations Joint ventures and associates Agiba Petroleum Co . . . . . . . . . . . . . . . . . . . . . . . . . . . CEPAV (Consorzio Eni per l’Alta Velocità) Due . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CEPAV (Consorzio Eni per l’Alta Velocità) Uno . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . EnBW Eni Verwaltungsgesellschaft mbH . . . . InAgip doo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Karachaganak Petroleum Operating BV . . . . . KWANDA - Suporte Logistico Lda . . . . . . . . . . Mellitah Oil & Gas BV . . . . . . . . . . . . . . . . . . . . . . . . Petrobel Belayim Petroleum Co . . . . . . . . . . . . . . . Petromar Lda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Stream Transport BV . . . . . . . . . . . . . . . . . . . Unión Fenosa Gas Comercializadora SA . . . . Unión Fenosa Gas SA . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unconsolidated entities controlled by Eni Agip Kazakhstan North Caspian Operating Co NV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eni BTC Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Entities controlled by the Government Enel Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Snam Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terna Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GSE - Gestore Servizi Energetici . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension funds and foundations . . . . . . . . . . . . . . . . . Discontinued operations Joint ventures and associates CEPAV (Consorzio Eni per l’Alta Velocità) Due . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CEPAV (Consorzio Eni per l’Alta Velocità) Uno . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . KWANDA - Suporte Logistico Lda . . . . . . . . . . Petrobel Belayim Petroleum Co . . . . . . . . . . . . . . . Petromar Lda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Stream Transport BV . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unconsolidated entities controlled by Eni Agip Kazakhstan North Caspian Operating Co NV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Entities controlled by the Government Snam Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension funds and foundations . . . . . . . . . . . . . . . . . . Receivables and other assets Payables and other liabilities Guarantees Costs Revenues Goods Services Other Goods Services Other Other operating (expense) income 2 120 23 52 43 68 98 32 93 15 122 668 61 13 74 742 156 147 33 88 44 468 1,210 60 152 12 11 233 15 58 375 4 1 67 988 1 52 53 1,041 122 585 65 124 93 989 2 2,032 1,246 10 6,122 21 57 6,200 17 1,273 167 10 1 178 6,378 7 7 1,273 155 89 580 8 832 6,385 2,105 169 44 320 235 603 134 1 22 1 132 1,504 1 18 41 157 95 387 2 7 20 7 2 61 99 1 15 16 342 7 32 2 4 6 22 1 44 2 47 69 183 13 12 208 208 11 353 1,857 933 1,867 154 2 98 3,054 4 4,915 4 4 391 181 235 120 172 45 753 1,144 7 48 5 7 60 3 75 60 183 1 1 159 3 10 1 50 223 2 2 13 13 3 2 37 136 133 33 35 14 2 217 353 216 14 9 83 61 495 31 909 155 155 39 4 43 1,210 2,032 6,385 2,105 238 5,153 1 2 185 1,144 1,107 1,460 69 208 (*) Each individual amount included herein was lower than €50 million. F-113 (€ million) Name Continuing operations Joint ventures and associates Agiba Petroleum Co . . . . . . . . . . . . . . . . . . . . . . . . . . . CEPAV (Consorzio Eni per l’Alta Velocità) Due . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CEPAV (Consorzio Eni per l’Alta Velocità) Uno . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Karachaganak Petroleum Operating BV . . . . . Mellitah Oil & Gas BV . . . . . . . . . . . . . . . . . . . . . . . . Petrobel Belayim Petroleum Co . . . . . . . . . . . . . . . Petromar Lda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unión Fenosa Gas SA . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unconsolidated entities controlled by Eni Eni México S. de RL de CV . . . . . . . . . . . . . . . . . . . Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Entities controlled by the Government Enel Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Snam Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terna Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GSE - Gestore Servizi Energetici . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension funds and foundations . . . . . . . . . . . . . . . . . Groupement Sonatrach - Agip and Organe Conjoint des Opérations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations Joint ventures and associates CEPAV (Consorzio Eni per l’Alta Velocità) Due . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CEPAV (Consorzio Eni per l’Alta Velocità) Uno . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . KWANDA - Suporte Logistico Lda . . . . . . . . . . Mellitah Oil & Gas BV . . . . . . . . . . . . . . . . . . . . . . . . Petrobel Belayim Petroleum Co . . . . . . . . . . . . . . . Petromar Lda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unconsolidated entities controlled by Eni Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Entities controlled by the Government Snam Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension funds and foundations . . . . . . . . . . . . . . . . . December 31, 2015 2015 Receivables and other assets Payables and other liabilities Guarantees Costs Revenues Goods Services Other Goods Services Other Other operating (expense) income 6 48 8 16 2 1 118 199 65 17 82 281 138 144 18 44 22 366 1 185 833 60 9 69 9 19 97 14 277 1 1 25 25 60 1 171 16 183 42 473 1 19 20 493 203 522 42 63 38 868 2 6,122 6 57 6,185 101 9 3 113 6,298 3 3 300 1,663 6,301 1,488 68 68 10 10 99 3 10 16 27 155 1 1 46 5 51 8 1 9 9 5 14 35 6 60 50 60 60 4 4 64 196 249 77 307 29 858 12 131 35 957 5 5 1 1 187 403 339 543 748 46 27 821 124 1,596 2 2 823 137 109 419 665 2 2 1,598 1,063 2,014 125 5 56 3,263 4 453 5,318 101 3 7 16 54 181 2 2 3 3 303 1,136 207 1,870 68 6,369 10 1,498 186 5,504 1 6 137 1 958 10 19 70 99 3 2 5 104 134 24 19 43 1 221 60 385 145 1 8 86 45 21 306 36 36 342 727 37 37 2 2 39 1 29 (4) (2) (6) (6) 90 12 30 102 69 96 1 1 1 70 96 (*) Each individual amount included herein was lower than €50 million. F-114 (€ million) Name December 31, 2016 2016 Receivables and other assets Payables and other liabilities Guarantees Costs Revenues Goods Services Other Goods Services Other Other operating (expense) income Joint ventures and associates Agiba Petroleum Co . . . . . . . . . . . . . . . . . . . . . . . . . . . Saipem Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Karachaganak Petroleum Operating BV . . . . . Mellitah Oil & Gas BV . . . . . . . . . . . . . . . . . . . . . . . . Petrobel Belayim Petroleum Co . . . . . . . . . . . . . . . Unión Fenosa Gas SA . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unconsolidated entities controlled by Eni Eni BTC Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Entities controlled by the Government Enel Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Snam Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terna Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GSE - Gestore Servizi Energetici . . . . . . . . . . . . . . Italgas Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other(*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension funds and foundations . . . . . . . . . . . . . . . . . Groupement Sonatrach - Agip and Organe Conjoint des Opérations . . . . . . . . . . . . . . . . . . . . . . . . 1 64 47 7 225 114 458 69 9 78 536 151 44 33 58 54 43 383 50 224 187 134 532 25 1,152 1 16 17 1,169 254 541 46 32 1 24 898 2 8,094 57 1 8,152 192 3 51 246 8,398 1 1 156 775 333 472 1,940 573 5 32 610 113 3,789 4 4 614 28 125 60 206 419 4 4 3,793 780 1,902 165 5 4 37 2,893 4 176 1,095 331 2,400 8,399 5 1,038 413 7,103 6 12 18 18 5 7 32 44 28 5 95 9 7 93 86 195 6 6 201 88 99 61 344 62 654 855 37 1 44 82 2 2 4 86 95 14 56 68 6 239 58 383 5 19 2 1 13 40 2 2 42 18 2 20 12 74 47 47 47 182 13 5 200 247 (*) 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 oil products by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs; engineering, construction and drilling services by the Saipem Group mainly for the Exploration & Production segment and guarantees issued by Eni SpA relating to bid bonds and performance bonds; performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and sales of LNG; a guarantee issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd; and services for environmental restoration to Industria Siciliana Acido Fosforico – ISAF SpA (in liquidation). • • • • The most significant transactions with entities controlled by the Italian Government concerned: • sale of diesel fuel and fuel through payment cards, sale and purchase of gas, environmental certificates, transmission services and fair value of derivative financial instruments with Enel Group; acquisition of natural gas transportation, distribution and storage services with the Snam Group and the Italgas Group on the basis of tariffs set by Italian Regulatory Authority for Electricity, Gas and Water and purchase and sale of natural gas for granting the balancing of the system on the basis of prices referred to the quotations of the main energy commodities; sale and purchase of electricity, the acquisition of domestic electricity transmission service on the basis of prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with the Terna Group; • • F-115 • sale and purchase of electricity and sale of oil products with GSE – Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/2012. Transactions with pension funds and foundation concerned: • • provisions to pension funds of €24 million; and contributions and service provisions to Eni Foundation of €4 million and to Eni Enrico Mattei Foundation for €4 million. Financing transactions with related parties (€ million) Name Continuing operations Joint ventures and associates CARDÓN IV SA ............................................... CEPAV (Consorzio Eni per l’Alta Velocità) Due ........ Matrìca SpA ..................................................... Shatskmorneftegaz Sàrl ....................................... Société Centrale Electrique du Congo SA ................. Unión Fenosa Gas SA ......................................... Other(*) ........................................................... Unconsolidated entities controlled by Eni Other(*) ........................................................... Entities controlled by the Government Other(*) ........................................................... December 31, 2014 2014 Receivables Payables Guarantees Charges Gains 621 200 56 84 48 1,009 68 68 1,077 90 13 103 73 73 5 5 181 150 2 19 171 2 2 13 28 41 173 41 29 6 5 4 44 1 1 1 1 46 (*) Each individual amount included herein was lower than €50 million. (€ million) Name Continuing operations Joint ventures and associates CARDÓN IV SA ............................................... Matrìca SpA ..................................................... Shatskmorneftegaz Sàrl ....................................... Société Centrale Electrique du Congo SA ................. Unión Fenosa Gas SA ......................................... Other(*) ........................................................... Unconsolidated entities controlled by Eni Other(*) ........................................................... Entities controlled by the Government Other(*) ........................................................... Discontinued operations Joint ventures and associates CEPAV (Consorzio Eni per l’Alta Velocità) Due ........ Other(*) ........................................................... December 31, 2015 2015 Receivables Payables Guarantees Charges Gains 1,112 209 63 94 52 1,530 51 51 27 27 1,608 5 5 1,613 90 7 97 111 111 208 208 12 12 12 150 150 162 10 21 19 50 50 65 11 5 81 1 1 1 1 83 50 83 (*) Each individual amount included herein was lower than €50 million. F-116 (€ million) December 31, 2016 2016 Name Receivables Payables Guarantees Charges Gains Continuing operations Joint ventures and associates CARDÓN IV SA ................................ Matrìca SpA ...................................... Shatskmorneftegaz Sarl ........................ Société Centrale Electrique du Congo SA .. Unión Fenosa Gas SA .......................... Saipem Group .................................... Other(*) ............................................ Unconsolidated entities controlled by Eni Eni BTC Ltd ...................................... Other(*) ............................................ Entities controlled by the Government Other(*) ............................................ 1,054 125 69 78 52 1,378 46 46 82 2 84 85 85 54 52 106 1,424 191 84 93 13 18 17 141 1 1 3 3 145 Income from equity instruments 27 27 96 9 4 43 4 156 1 1 157 27 (*) Each individual amount included herein was lower than €50 million. The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned: • financing loans granted to CARDÓN IV SA for the exploration and development activities of a gas field in Venezuela; financing loans granted to Matrìca SpA in relation to the “Green Chemistry” project at the Porto Torres plant; financing loans granted to Shatskmorneftegaz Sàrl for the exploration activity of in the Black Sea and to Société Centrale Electrique du Congo SA for the construction of an electric plant in Congo; a cash deposit at Eni’s financial companies on behalf of Unión Fenosa Gas SA and Eni BTC Ltd; derivative financial instruments relating to the settlement of derivatives on exchange rate entered into by the Saipem Group with Eni in previous years. • • • • On January 22, 2016, Eni closed the sale transaction of 12.503% of the share capital of Saipem to CDP Equity SpA (former Fondo Strategico Italiano SpA) for a total consideration of €463 million. More information is reported in note 35 — Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale. F-117 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 consisted of the following: (€ million) December 31, 2014 December 31, 2015 December 31, 2016 Total Related parties Impact % Total Related parties Impact % Total Related parties Impact % 4,385 1,042 2,773 Trade and other receivables ........ 28,601 1,973 43 Other current assets ................... 259 Other non-current financial assets Other non-current assets ............ 12 Discontinued operations and assets held for sale ...................... Current financial liabilities ......... 181 Trade and other payables ........... 23,703 1,954 58 Other current liabilities .............. Other non-current liabilities ....... 20 Discontinued operations and liabilities directly associated to assets held for sale ..................... 4,489 2,285 456 2,716 165 6.90 0.98 24.86 0.43 21,640 1,985 50 3,642 396 1,026 10 1,758 15,533 5,720 308 208 14,942 1,544 96 4,712 23 1,852 6.66 8.24 1.29 0.88 9.17 1.37 38.60 0.57 1.98 3.64 10.33 2.04 1.24 17,593 1,100 2,591 57 1,860 1,349 13 1,348 6.25 2.20 72.53 0.96 14 3,396 191 16,703 2,289 88 2,599 23 1,768 5.62 13.70 3.39 1.30 6,485 207 3.19 The impact of transactions with related parties on the profit and loss accounts consisted of the following: (€ million) 2014 Related parties Total Impact % Total 2015 Related parties Impact % Total 2016 Related parties Impact % 1,079 Continuing operations Net sales from operations .......... 98,218 1,497 Other income and revenues ....... 69 Purchases, services and other ..... 77,404 7,143 Payroll and related costs ........... 60 Other operating (expense) income .................................... Financial income ..................... Financial expense ..................... Derivative financial instruments . Discontinued operations Total revenues .......................... 11,644 1,107 240 Operating costs ........................ 12,731 145 5,701 (7,057) 165 2,929 208 46 (41) 1.52 6.39 9.23 2.05 — 0.81 0.58 72,286 1,342 1,252 69 56,848 6,882 55 3,119 1.86 5.51 12.11 1.76 931 55,762 1,238 74 44,124 8,212 24 2,994 (485) 8,635 (10,104) 160 96 83 (50) — 0.96 0.49 16 5,850 (6,232) (482) 247 157 (145) 27 2.22 7.95 18.61 0.80 — 2.69 2.33 — 9.51 1.89 10,277 12,199 344 202 3.35 1.66 Main cash flows with related parties are provided below: (€ million) Revenues and other income ....................................................... Costs and other expenses ......................................................... Other operating income (loss) .................................................... Net change in trade and other receivables and liabilities ................... Net interests ......................................................................... Net cash provided from operating activities — Continuing operations ..... Net cash provided from operating activities — Discontinued operations .. Net cash provided from operating activities ..................................... Capital expenditure in tangible and intangible assets ....................... Disposal of investments ........................................................... Net change in accounts payable and receivable in relation to investments ........................................................................... Change in financial receivables .................................................. Net cash used in investing activities .............................................. Change in financial liabilities ..................................................... Net cash used in financing activities ............................................. Total financial flows to related parties ........................................... 2014 1,566 (6,022) 208 164 46 (4,038) 835 (3,203) (1,181) (114) (163) (1,458) (99) (99) (4,760) 2015 1,411 (5,786) 96 105 82 (4,092) 126 (3,966) (1,151) (238) (194) (1,583) 13 13 (5,536) 2016 1,312 (5,623) 247 182 133 (3,749) (3,749) (2,613) 463 252 5,650 3,752 (192) (192) (189) F-118 The impact of cash flows with related parties consisted of the following: (€ million) 2014 Related parties Total Impact % Total 2015 Related parties Impact % Total 2016 Related parties Impact % Cash provided from operating activities ................................. 14,742 (3,203) Cash used in investing activities . Cash used in financing activities (8,575) (1,458) 17.00 1.96 (5,062) (99) — 11,649 (3,966) (10,923) (1,583) 14.49 (1,351) 13 — 7,673 (3,749) — — 5.26 (4,443) 3,752 (192) — (3,651) 48 Other information about investments Information on Eni’s investments as of December 31, 2016 The following section provides the information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2016. 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 0.91 68.99 Subsidiaries Exploration & Production In Italy Company name Eni Angola SpA Eni Mediterranea Idrocarburi SpA Eni Mozambico SpA Eni Timor Leste SpA Eni West Africa SpA Eni Zubair SpA (in liquidation) Floaters SpA Ieoc SpA Società Petrolifera Italiana SpA Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) San Donato Milanese (MI) Angola EUR 20,200,000 Eni SpA 100.00 100.00 Gela (CL) Italy EUR 5,200,000 Eni SpA 100.00 100.00 San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) Venezia Marghera (VE) Mozambique EUR 200,000 Eni SpA 100.00 100.00 Timor Leste EUR 6,841,517 Eni SpA 100.00 100.00 Angola EUR 10,000,000 Eni SpA 100.00 100.00 Italy Italy Egypt Italy Italy EUR 120,000 Eni SpA 100.00 EUR 200,120,000 Eni SpA 100.00 100.00 EUR EUR EUR 18,331,000 Eni SpA 100.00 100.00 24,103,200 Eni SpA Third parties 2,064,000 Eni SpA 99.96 0.04 100.00 99.96 100.00 F.C. F.C. F.C. F.C. F.C. Co. F.C. F.C. F.C. F.C. (*) (#) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Company with shares quoted in the regulated market of Italy or of other EU countries F-119 Outside Italy Company name Agip Caspian Sea BV Agip Energy and Natural Resources (Nigeria) Ltd Agip Karachaganak BV Amsterdam Amsterdam (Netherlands) Abuja (Nigeria) (Netherlands) Agip Oil Ecuador BV Agip Oleoducto de Crudos Pesados BV Burren (Cyprus) Holdings Ltd (in liquidation) Burren Energy (Bermuda) Ltd Burren Energy Congo Ltd Burren Energy (Egypt) Ltd Amsterdam (Netherlands) Amsterdam (Netherlands) Nicosia (Cyprus) Hamilton (Bermuda) Tortola (British Virgin Islands) London (United Kingdom) Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Kazakhstan EUR 20,005 Eni International BV 100.00 100.00 Nigeria NGN 5,000,000 Eni International BV Eni Oil Holdings BV 95.00 5.00 100.00 Kazakhstan EUR 20,005 Eni International BV 100.00 100.00 Ecuador EUR 20,000 Eni International BV 100.00 100.00 Ecuador EUR 20,000 Eni International BV 100.00 Cyprus EUR 1,710 Burren En.(Berm)Ltd 100.00 United Kingdom Republic of the Congo USD USD 12,002 Burren Energy Plc 100.00 100.00 50,000 Burren En.(Berm)Ltd 100.00 100.00 Egypt GBP 2 Burren Energy Plc 100.00 F.C. F.C. F.C. F.C. Eq. Co. F.C. F.C. Eq. Burren Energy India Ltd London (United Kingdom) United Kingdom GBP 2 Burren Energy Plc 100.00 100.00 F.C. Burren Energy Ltd (in liquidation) Burren Energy Plc Burren Energy (Services) Ltd (in liquidation) Burren Energy Ship Management Ltd (in liquidation) Burren Energy Shipping and Transportation Ltd (in liquidation) Burren Shakti Ltd Eni Abu Dhabi BV Eni AEP Ltd Eni Algeria Exploration BV Eni Algeria Ltd Sàrl Nicosia (Cyprus) London (United Kingdom) London (United Kingdom) Nicosia (Cyprus) Nicosia (Cyprus) Hamilton (Bermuda) Amsterdam (Netherlands) London (United Kingdom) Amsterdam (Netherlands) Luxembourg (Luxembourg) Eni Algeria Production BV Amsterdam (Netherlands) Eni Ambalat Ltd Eni America Ltd Eni Angola Exploration BV London (United Kingdom) Dover, Delaware (USA) Amsterdam (Netherlands) Cyprus EUR 3,420 Burren En.(Berm)Ltd 100.00 100.00 United Kingdom GBP 28,819,023 Eni UK Holding Plc Eni UK Ltd 99.99 (—) 100.00 F.C. F.C. United Kingdom GBP 2 Burren Energy Plc 100.00 100.00 F.C. Cyprus EUR 3,420 Burren(Cyp)Hold.Ltd Cyprus EUR (L) Burren En.(Berm)Ltd 3,420 Burren(Cyp)Hold.Ltd (L) Burren En.(Berm)Ltd 50.00 50.00 50.00 50.00 United Kingdom USD 65,300,000 Burren En. India Ltd 100.00 100.00 Netherlands EUR 20,000 Eni International BV 100.00 Pakistan GBP 73,471,000 Eni UK Ltd 100.00 100.00 Algeria EUR 20,000 Eni International BV 100.00 100.00 Algeria USD 20,000 Eni Oil Holdings BV 100.00 100.00 Algeria EUR 20,000 Eni International BV 100.00 100.00 Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 USA USD 72,000 Eni UHL Ltd 100.00 100.00 Angola EUR 20,000 Eni International BV 100.00 100.00 Co. Co. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-120 Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Angola EUR 20,000 Eni International BV 100.00 100.00 F.C. Argentina ARS 24,136,336 Eni International BV Eni Oil Holdings BV 95.00 5.00 Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 Australia EUR 20,000 Eni International BV 100.00 100.00 Australia GBP 20,000,000 Eni International BV 100.00 100.00 USA USD 1,000 Eni Petroleum Co Inc 100.00 100.00 London (United Kingdom) United Kingdom GBP 34,000,000 Eni International BV 100.00 London (United Kingdom) Amsterdam (Netherlands) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 Indonesia EUR 20,000 Eni International BV 100.00 100.00 Eni Canada Holding Ltd Calgary (Canada) Canada USD 1,453,200,001 Eni International BV 100.00 100.00 Indonesia USD 2,210,728 Eni Lasmo Plc 100.00 100.00 China Republic of the Congo EUR USD 20,000 Eni International BV 100.00 100.00 17,000,000 Eni E&P Holding BV Eni Int. NA NV Sàrl Eni International BV 100.00 99.99 (—) (—) 100.00 Ivory Coast GBP 1 Eni UK Ltd 100.00 F.C. Croatia EUR 20,000 Eni International BV 100.00 100.00 Cyprus EUR 2,004 Eni International BV 100.00 100.00 Netherlands EUR 90,000 Eni Oil Holdings BV 100.00 100.00 Greenland EUR 20,000 Eni International BV 100.00 100.00 Brazil BRL 1,593,415,000 Eni International BV Eni Oil Holdings BV 99.99 (—) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 London (United Kingdom) United Kingdom GBP 100 Eni UK Ltd 100.00 100.00 Amsterdam (Netherlands) London (United Kingdom) Amsterdam (Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 United Kingdom GBP 40,000,001 Eni UK Ltd 100.00 100.00 Netherlands EUR 29,832,777.12 Eni International BV 100.00 100.00 Libreville (Gabon) Gabon London (United Kingdom) Indonesia XAF GBP 13,132,000,000 Eni International BV 2 Eni Indonesia Ltd 100.00 100.00 100.00 100.00 Amsterdam (Netherlands) Buenos Aires (Argentina) London (United Kingdom) Amsterdam (Netherlands) London (United Kingdom) Dover, Delaware (USA) London (United Kingdom) Amsterdam (Netherlands) Pointe - Noire (Republic of the Congo) London (United Kingdom) Amsterdam (Netherlands) Nicosia (Cyprus) Amsterdam (Netherlands) Amsterdam (Netherlands) Rio De Janeiro (Brazil) London (United Kingdom) Company name Eni Angola Production BV Eni Argentina Exploración y Explotación SA Eni Arguni I Ltd Eni Australia BV Eni Australia Ltd Eni BB Petroleum Inc Eni BTC Ltd Eni Bukat Ltd Eni Bulungan BV Eni CBM Ltd Eni China BV Eni Congo SA Eni Côte d’Ivoire Ltd (former Eni Ivory Coast Ltd) Eni Croatia BV Eni Cyprus Ltd Eni Dación BV Eni Denmark BV Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda Eni East Sepinggan Ltd Eni Elgin/Franklin Ltd Eni Energy Russia BV Eni Engineering E&P Ltd Eni Exploration & Production Holding BV Eni Gabon SA Eni Ganal Ltd Eq. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. 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 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 Eni Hewett Ltd Eni Hydrocarbons Venezuela Ltd Eni India Ltd Eni Indonesia Ltd Accra (Ghana) Ghana Aberdeen (United Kingdom) United Kingdom GHS GBP 21,412,500 Eni International BV 3,036,000 Eni UK Ltd 100.00 100.00 100.00 100.00 London (United Kingdom) London (United Kingdom) London (United Kingdom) Venezuela GBP 8,050,500 Eni Lasmo Plc 100.00 100.00 India GBP 44,000,000 Eni UK Ltd 100.00 100.00 Indonesia GBP 100 Eni ULX Ltd 100.00 100.00 Eni Indonesia Ots 1 Ltd Grand Cayman (Cayman Islands) Indonesia USD 1.01 Eni Indonesia Ltd 100.00 100.00 Eni International NA NV Sàrl Luxembourg (Luxembourg) United Kingdom Eni Investments Plc London (United Kingdom) United Kingdom USD GBP EUR EUR 25,000 Eni International BV 100.00 100.00 750,050,000 Eni SpA Eni UK Ltd 99.99 (—) 100.00 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Iran Iraq Eni Iran BV Eni Iraq BV Eni Ireland BV Eni Isatay BV Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) Eni JPDA 03-13 Ltd London (United Kingdom) Eni JPDA 06-105 Pty Ltd Eni JPDA 11-106 BV Eni Kenya BV Perth (Australia) Amsterdam (Netherlands) Amsterdam (Netherlands) Eni Krueng Mane Ltd London (United Kingdom) Eni Lasmo Plc Eni Liberia BV Eni Liverpool Bay Operating Co Ltd Eni LNS Ltd Eni Marketing Inc Eni Maroc BV Amsterdam (Netherlands) London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom Dover, Delaware (USA) USA Ireland EUR 20,000 Eni International BV 100.00 100.00 Kazakhstan EUR 20,000 Eni International BV 100.00 100.00 Australia GBP 250,000 Eni International BV 100.00 100.00 Australia AUD 80,830,576 Eni International BV 100.00 100.00 Australia EUR 50,000 Eni International BV 100.00 100.00 Kenya EUR 20,000 Eni International BV 100.00 100.00 Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 London (United Kingdom) United Kingdom GBP 337,638,724.25 Eni Investments Plc Eni UK Ltd 99.99 (—) 100.00 Liberia EUR 20,000 Eni International BV 100.00 100.00 GBP GBP USD 5,001,000 Eni UK Ltd 100.00 100.00 80,400,000 Eni UK Ltd 100.00 100.00 1,000 Eni Petroleum Co Inc 100.00 100.00 Amsterdam (Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 100.00 F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. 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 Company name Eni México S. de RL de CV Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Lomas De Chapultepec, Mexico City (Mexico) Mexico MXN 3,000 Eni International BV Eni Oil Holdings BV 99.90 0.10 100.00 F.C. Eni Middle East BV Amsterdam (Netherlands) Netherlands EUR 20,000 Eni International BV 100.00 Eni Middle East Ltd Eni MOG Ltd (in liquidation) Eni Montenegro BV Amsterdam London (United Kingdom) London (United Kingdom) (Netherlands) United Kingdom United Kingdom GBP GBP 1 Eni ULT Ltd 100.00 100.00 Montenegro EUR 20,000 Eni International BV 220,711,147.50 Eni Lasmo Plc Eni LNS Ltd 100.00 99.99 (—) 100.00 London (United Kingdom) United Kingdom GBP 1 Eni UK Ltd 100.00 100.00 Eni Mozambique Engineering Ltd Eni Mozambique LNG Holding BV Eni Muara Bakau BV Eni Myanmar BV Eni Norge AS Eni North Africa BV Eni North Ganal Ltd Eni Oil & Gas Inc Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) Forus (Norway) Amsterdam (Netherlands) London (United Kingdom) Dover, Delaware (USA) Eni Oil Algeria Ltd London (United Kingdom) Eni Oil Holdings BV Eni Pakistan Ltd Eni Pakistan (M) Ltd Sàrl Eni Petroleum Co Inc Eni Petroleum US Llc Eni Portugal BV Amsterdam (Netherlands) London (United Kingdom) Luxembourg (Luxembourg) Dover, Delaware (USA) Dover, Delaware (USA) Amsterdam (Netherlands) Eni Rapak Ltd London (United Kingdom) Eni RD Congo SA Eni South Africa BV Eni South China Sea Ltd Sàrl Kinshasa (Democratic Republic of Congo) Amsterdam (Netherlands) Luxembourg (Luxembourg) Netherlands EUR 20,000 Eni International BV 100.00 100.00 Indonesia EUR 20,000 Eni International BV 100.00 100.00 Myanmar EUR 20,000 Eni International BV 100.00 100.00 Norway NOK 278,000,000 Eni International BV 100.00 100.00 Libya EUR 20,000 Eni International BV 100.00 100.00 Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 USA USD 100,800 Eni America Ltd 100.00 100.00 Algeria GBP 1,000 Eni Lasmo Plc 100.00 100.00 Netherlands EUR 450,000 Eni ULX Ltd 100.00 100.00 Pakistan GBP 90,087 Eni ULX Ltd 100.00 100.00 Pakistan USD 20,000 Eni Oil Holdings BV 100.00 100.00 USA USA USD USD 156,600,000 Eni SpA Eni International BV 63.86 36.14 100.00 1,000 Eni BB Petroleum Inc 100.00 100.00 Portugal EUR 20,000 Eni International BV 100.00 100.00 Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 Democratic Republic of Congo CDF Republic of South Africa China EUR USD 750,000,000 Eni International BV Eni Oil Holdings BV 99.99 (—) 100.00 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 Eq. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-123 Consolidation or valutation method(*) F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Co. F.C. F.C. Eq. Eq. Company name Eni TNS Ltd Eni Togo BV Eni Trinidad and Tobago Ltd Eni Tunisia BV Eni Turkmenistan Ltd Eni UHL Ltd Eni UKCS Ltd Eni UK Ltd Eni Ukraine Holdings BV Eni Ukraine Llc Eni ULT Ltd Eni ULX Ltd Eni USA Gas Marketing Llc Eni USA Inc Eni US Operating Co Inc Eni Venezuela BV Eni Venezuela E&P Holding SA Eni Ventures Plc (in liquidation) Eni Vietnam BV Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Aberdeen (United Kingdom) United Kingdom GBP 1,000 Eni UK Ltd 100.00 100.00 Amsterdam (Netherlands) Port Of Spain (Trinidad and Tobago) Amsterdam (Netherlands) Hamilton (Bermuda) Netherlands EUR 20,000 Eni International BV 100.00 Trinidad and Tobago TTD 1,181,880 Eni International BV 100.00 100.00 Tunisia EUR 20,000 Eni International BV 100.00 100.00 Turkmenistan USD 20,000 Burren En.(Berm)Ltd 100.00 100.00 London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom Eni UK Holding Plc London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom GBP GBP GBP GBP 1 Eni ULT Ltd 100.00 100.00 100 Eni UK Ltd 100.00 100.00 424,050,000 Eni Lasmo Plc Eni UK Ltd 99.99 (—) 100.00 250,000,000 Eni International BV 100.00 100.00 Amsterdam (Netherlands) Kiev (Ukraine) Netherlands EUR 20,000 Eni International BV 100.00 100.00 Ukraine UAH 42,004,757.64 Eni Ukraine Hold.BV Eni International BV Ukraine EUR 20,000 Eni Ukraine Hold.BV 100.00 99.99 0.01 100.00 Eni Ukraine Shallow Waters BV Amsterdam (Netherlands) GBP GBP USD USD USD 93,215,492.25 Eni Lasmo Plc 100.00 100.00 200,010,000 Eni ULT Ltd 100.00 100.00 10,000 Eni Marketing Inc 100.00 100.00 1,000 Eni Oil & Gas Inc 100.00 100.00 1,000 Eni Petroleum Co Inc 100.00 100.00 London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom USA USA USA Dover, Delaware (USA) Dover, Delaware (USA) Dover, Delaware (USA) Amsterdam (Netherlands) Bruxelles (Belgium) Venezuela EUR 20,000 Eni Venezuela E&P H 100.00 100.00 Belgium USD London (United Kingdom) United Kingdom GBP 963,800,000 Eni International BV Eni Oil Holdings BV 278,050,000 Eni International BV Eni Oil Holdings BV 100.00 99.99 (—) 99.99 (—) Amsterdam (Netherlands) Vietnam EUR 20,000 Eni International BV 100.00 100.00 Eni West Timor Ltd London (United Kingdom) Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 Eni Yemen Ltd Eurl Eni Algérie London (United Kingdom) United Kingdom GBP 1,000 Burren Energy Plc 100.00 Algiers (Algeria) Algeria DZD 1,000,000 Eni Algeria Ltd Sàrl 100.00 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-124 Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) F.C. F.C. F.C. F.C. F.C. F.C. Co. F.C. F.C. F.C. Eq. Co. Co. Company name First Calgary Petroleums LP First Calgary Petroleums Partner Co ULC Ieoc Exploration BV Ieoc Production BV Wilmington (USA) Calgary (Canada) Amsterdam (Netherlands) Amsterdam (Netherlands) Algeria USD 1 Eni Canada Hold. Ltd FCP Partner Co ULC 99.99 0.01 100.00 Canada CAD 10 Eni Canada Hold. Ltd 100.00 100.00 Egypt Egypt EUR EUR 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Lasmo Sanga Sanga Ltd Hamilton (Bermuda) Indonesia USD 12,000 Eni Lasmo Plc 100.00 100.00 Liverpool Bay Ltd London (United Kingdom) United Kingdom USD 29,075,343 Eni ULX Ltd 100.00 100.00 Nigerian Agip CPFA Ltd Lagos (Nigeria) Nigerian Agip Exploration Ltd Nigerian Agip Oil Co Ltd OOO ‘Eni Energhia’ Tecnomare Egypt Ltd Zetah Congo Ltd Zetah Kouilou Ltd Abuja (Nigeria) Abuja (Nigeria) Moscow (Russia) Cairo (Egypt) Nassau (Bahamas) Nassau (Bahamas) Nigeria NGN 1,262,500 NAOC Ltd Nigeria NGN Nigeria NGN Agip En Nat Res.Ltd Nigerian Agip E. Ltd 5,000,000 Eni International BV Eni Oil Holdings BV 1,800,000 Eni International BV Eni Oil Holdings BV Russia RUB 2,000,000 Eni Energy Russia BV Egypt Republic of the Congo Republic of the Congo EGP USD USD Eni Oil Holdings BV 50,000 Tecnomare SpA Eni SpA 300 Eni Congo SA Burren En.Congo Ltd 2,000 Eni Congo SA Burren En.Congo Ltd Third parties 100.00 100.00 100.00 98.02 0.99 0.99 99.99 0.01 99.89 0.11 99.90 0.10 99.00 1.00 66.67 33.33 54.50 37.00 8.50 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-125 Gas & Power Company name In Italy Eni Gas e Luce SpA (former Eni Medio Oriente SpA) Eni Gas Transport Services Srl Eni Trading & Shipping SpA EniPower Mantova SpA San Donato San Donato Milanese (MI) Rome Milanese (MI) EniPower SpA LNG Shipping SpA Servizi Fondo Bombole Metano SpA Trans Tunisian Pipeline Co SpA San Donato Milanese (MI) San Donato Milanese (MI) Rome San Donato Milanese (MI) Outside Italy Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana Ljubljana (Slovenia) Distrigas LNG Shipping SA Eni G&P France BV Eni G&P Trading BV Eni Gas & Power France SA Eni Gas & Power NV Bruxelles (Belgium) Amsterdam (Netherlands) Amsterdam (Netherlands) Levallois Perret (France) Vilvoorde (Belgium) Eni Wind Belgium NV Société de Service du Gazoduc Transtunisien SA - Sergaz SA Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA Tigáz Gepa Kft (in liquidation) Tigáz-Dso Földgázelosztó kft Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság Vilvoorde (Belgium) Tunisi (Tunisia) Tunisi (Tunisia) Hajdúszoboszló (Hungary) Hajdúszoboszló (Hungary) Hajdúszoboszló (Hungary) Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) San Donato Milanese (MI) Italy EUR 6,655,992 Eni SpA 120,000 Eni SpA 60,036,650 Eni SpA Eni Gas & Power NV 144,000,000 EniPower SpA Third parties 944,947,849 Eni SpA 100.00 100.00 94.73 5.27 86.50 13.50 100.00 86.50 100.00 100.00 240,900,000 Eni SpA 100.00 100.00 EUR 13,580,000.20 Eni SpA 100.00 Tunisia EUR 1,098,000 Eni SpA 100.00 100.00 EUR EUR EUR EUR EUR Italy Italy Italy Italy Italy Italy Eni Trading & Shipping Inc Dover, Delaware (USA) USA USD 36,000,000 Ets SpA 100.00 100.00 51.00 F.C. Slovenia EUR 12,956,935 Eni SpA Third parties Belgium EUR 788,579.55 LNG Shipping SpA Eni Gas & Power NV 51.00 49.00 99.99 (—) 100.00 France EUR 20,000 Eni International BV 100.00 100.00 Turkey EUR 70,000 Eni International BV 100.00 100.00 France EUR 29,937,600 Eni G&P France BV Belgium EUR Third parties 31,925,264 Eni SpA Eni International BV 99.87 0.13 99.99 (—) 99.87 100.00 Belgium EUR Tunisia TND 5,494,500 Eni Gas & Power NV Eni International BV 99,000 Eni International BV Third parties Tunisia TND 200,000 Eni International BV Eni SpA Eni Gas & Power NV Trans Tunis.P.Co SpA Hungary HUF 52,780,000 Tigáz Zrt 99.77 0.23 66.67 33.33 99.85 0.05 0.05 0.05 100.00 100.00 66.67 Hungary HUF 62,066,000 Tigáz Zrt 100.00 98.99 Hungary HUF 8,486,070,500 Eni SpA Third parties 98.99 1.01 98.99 100.00 F.C. Co. Co. F.C. F.C. F.C. F.C. Co. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-126 Refining & Marketing and Chemical Refining & Marketing Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Cittaducale (RI) Italy EUR 5,160 Eni Fuel SpA 100.00 San Donato Milanese (MI) Rome Italy Italy EUR EUR 52,000,000 Eni SpA 100.00 100.00 58,944,310 Eni SpA 100.00 100.00 Consolidation or valutation method(*) Co. F.C. F.C. Company name In Italy Consorzio AgipGas Sabina (in liquidation) Ecofuel SpA Eni Fuel SpA (former Eni Rete oil&nonoil SpA) Raffineria di Gela SpA Gela (CL) Italy EUR 15,000,000 Eni SpA 100.00 100.00 F.C. Outside Italy Eni Austria GmbH Eni Benelux BV Eni Deutschland GmbH Eni Ecuador SA Eni France Sàrl Eni Iberia SLU Wien (Austria) Rotterdam (Netherlands) Munich (Germany) Quito (Ecuador) Lyon (France) Alcobendas (Spain) Eni Lubricants Trading (Shanghai) Co Ltd Shanghai (China) Eni Marketing Austria GmbH Eni Mineralölhandel GmbH Eni Schmiertechnik GmbH Eni Suisse SA Wien (Austria) Wien (Austria) Wurzburg (Germany) Lausanne (Switzerland) Eni USA R&M Co Inc Wilmington (USA) Esacontrol SA Esain SA Oléoduc du Rhône SA OOO ‘‘Eni-Nefto’’ Tecnoesa SA Quito (Ecuador) Quito (Ecuador) Valais (Switzerland) Moscow (Russia) Quito (Ecuador) Austria EUR 78,500,000 Eni International BV Eni Deutsch.GmbH 75.00 25.00 100.00 Netherlands EUR 1,934,040 Eni International BV 100.00 100.00 Germany EUR Ecuador USD 90,000,000 Eni International BV Eni Oil Holdings BV 103,142.08 Eni International BV Esain SA 89.00 11.00 99.93 0.07 100.00 100.00 France EUR 56,800,000 Eni International BV 100.00 100.00 Spain China EUR EUR Austria EUR 17,299,100 Eni International BV 100.00 100.00 5,000,000 Eni International BV 100.00 19,621,665.23 Eni Mineralölh.GmbH Eni International BV 99.99 (—) 100.00 Austria EUR 34,156,232.06 Eni Austria GmbH 100.00 100.00 Germany EUR 2,000,000 Eni Deutsch.GmbH 100.00 100.00 Switzerland CHF 102,500,000 Eni International BV Third parties 99.99 (—) 100.00 USA USD 11,000,000 Eni International BV 100.00 100.00 Ecuador USD Ecuador USD 60,000 Eni Ecuador SA Third parties 30,000 Eni Ecuador SA Tecnoesa SA Switzerland CHF 7,000,000 Eni International BV Russia RUB Ecuador USD 1,010,000 Eni International BV Eni Oil Holdings BV 36,000 Eni Ecuador SA Esain SA 87.00 13.00 99.99 (—) 100.00 99.01 0.99 99.99 (—) 100.00 F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. Eq. F.C. Eq. Eq. Eq. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-127 Chemical Company name Versalis SpA In Italy Consorzio Industriale Gas Naturale (in liquidation) Outside Italy Dunastyr Polisztirolgyártó Zártkoruen Mukodo Részvénytársaság Eni Chemicals Trading (Shanghai) Co Ltd (in liquidation) Versalis Americas Inc Versalis Congo Sarlu Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) San Donato Milanese (MI) San Donato Milanese (MI) Budapest (Hungary) Shanghai (China) Italy EUR 1,364,790,000 Eni SpA 100.00 100.00 F.C. Italy EUR 124,000 Versalis SpA Raff. di Gela SpA Eni SpA Syndial SpA Raff. Milazzo ScpA Hungary HUF 8,092,160,000 Versalis SpA Versalis Deutsc.GmbH Versalis Int.SA Eq. 100.00 F.C. 53.55 18.74 15.37 0.76 11.58 96.34 1.83 1.83 China USD 5,000,000 Versalis SpA 100.00 Eq. F.C. Eq. F.C. F.C. F.C. Eq. Eq. Dover, Delaware (USA) Pointe-Noire (Republic of Congo) USA Republic of Congo USD CDF 100,000 Versalis International 100.00 100.00 SA 1,000,000 Versalis International 100.00 SA Versalis Deutschland GmbH Eschborn (Germany) Versalis France SAS Versalis International SA Mardyck (France) Bruxelles (Belgium) Versalis Kimya Ticaret Limited Sirketi Istanbul (Turkey) Versalis Pacific (India) Private Ltd Mumbai (India) Germany EUR 100,000 Versalis SpA 100.00 100.00 France EUR 126,115,582.90 Versalis SpA 100.00 100.00 Belgium EUR Turkey TRY 15,449,173.88 Versalis SpA Versalis Deutsc.GmbH Dunastyr Zrt Versalis France 20,000 Versalis Int.SA India INR 238,700 Versalis Pacific Trading Third parties 100.00 59.00 23.71 14.43 2.86 100.00 99.99 (—) Versalis Pacific Trading (Shanghai) Co Ltd Versalis UK Ltd Shanghai (China) China CNY 1,000,000 Versalis SpA 100.00 100.00 F.C. Lyndhurst, Hampshire (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 F-128 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 Eni Adfin SpA Rome Rome Eni Corporate University SpA EniServizi SpA Serfactoring SpA Servizi Aerei SpA Outside Italy Banque Eni SA San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) Bruxelles (Belgium) Eni Finance International SA Eni Finance USA Inc Dover, Delaware Bruxelles (Belgium) (USA) Dublin (Ireland) Eni Insurance Designated Activity Company (former Eni Insurance Ltd) Eni International BV Amsterdam (Netherlands) Italy Italy Italy Italy Italy Italy EUR EUR EUR 2,000,000 Eni SpA 100.00 100.00 85,537,498.80 Eni SpA Third parties 3,360,000 Eni SpA 99.65 0.35 99.65 100.00 100.00 EUR 13,427,419.08 Eni SpA 100.00 100.00 EUR EUR 5,160,000 Eni Adfin SpA Third parties 79,817,238 Eni SpA 49.00 51.00 48.83 100.00 100.00 Belgium EUR 50,000,000 Eni International BV Eni Oil Holdings BV Belgium USD 2,474,225,632 Eni International BV Eni SpA 99.90 0.10 66.39 33.61 100.00 100.00 USA USD 15,000,000 Eni Petroleum Co Inc 100.00 100.00 Ireland EUR 500,000,000 Eni SpA 100.00 100.00 Netherlands EUR 641,683,425 Eni SpA 100.00 100.00 Eni International Resources Ltd London (United Kingdom) United Kingdom GBP 50,000 Eni SpA Eni UK Ltd 99.99 (—) 100.00 F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Other Activities Company name In Italy Anic Partecipazioni SpA (in liquidation) Eni New Energy SpA Gela (CL) Italy San Donato Milanese (MI) Gela (CL) Italy Italy Italy Italy Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) Ing. Luigi Conti Vecchi SpA Assemini (CA) Syndial Servizi Ambientali SpA (former Syndial SpA – Attività Diversificate) San Donato Milanese (MI) Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) EUR EUR EUR EUR EUR 23,519,847.16 Syndial SpA Third parties 5,000,000.00 Eni SpA 1,300,000 Syndial SpA Third parties 5,518,620.64 Syndial SpA 422,269,480.70 Eni SpA Third parties 99.96 0.04 100.00 52.00 48.00 100.00 99.99 (—) 100.00 100.00 Eq. Co. Eq. F.C. F.C. Outside Italy Oleodotto del Reno SA Coira (Switzerland) Switzerland CHF 1,550,000 Syndial SpA 100.00 Eq. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value F-129 Joint arrangements and associates Exploration & Production Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Company name In Italy Eni East Africa SpA(†) Società Oleodotti Meridionali - SOM SpA(†) Outside Italy Agiba Petroleum Co(†) Angola LNG Ltd Ashrafi Island Petroleum Co Barentsmorneftegaz Sàrl(†) Cabo Delgado Gas Development Limitada(†) CARDÓN IV SA(†) Compañia Agua Plana SA East Delta Gas Co East Kanayis Petroleum Co(†) East Obaiyed Petroleum Company(†) El-Fayrouz Petroleum Co(†) (in liquidation) San Donato Milanese (MI) San Donato Milanese (MI) Cairo (Egypt) Hamilton (Bermuda) Cairo (Egypt) Luxembourg (Luxembourg) Maputo (Mozambique) Caracas (Venezuela) Caracas (Venezuela) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) El Temsah Petroleum Co Enstar Petroleum Ltd Fedynskmorneftegaz Sàrl(†) InAgip doo(†) Karachaganak Petroleum Operating BV Karachaganak Project Development Ltd (KPD) Khaleej Petroleum Co Wll Liberty National Development Co Llc Llc ‘Westgasinvest’(†) Cairo (Egypt) Calgary (Canada) Luxembourg (Luxembourg) Zagreb (Croatia) Amsterdam (Netherlands) Reading, Berkshire (United Kingdom) Safat (Kuwait) Wilmington (USA) Lviv (Ukraine) 71.43 70.00 Mozambique EUR 20,000,000 Eni SpA Italy EUR Third parties 3,085,000 Eni SpA Third parties Egypt EGP Angola USD Egypt Russia EGP USD Mozambique MZN Venezuela VEF Venezuela VEF Egypt Egypt Egypt EGP EGP EGP Egypt EGP Egypt EGP 20,000 Ieoc Production BV Third parties 11,277,000,000 Eni Angola Prod.BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Eni Energy Russia BV Third parties 2,500,000 Eni Mozam.LNG H. BV Third parties 17,210,000 Eni Venezuela BV Third parties 100 Eni Venezuela BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc SpA Third parties 20,000 Ieoc Exploration BV Third parties 20,000 Ieoc Production BV Third parties Canada CAD 0.10 Unimar Llc Russia USD Croatia HRK Kazakhstan EUR 20,000 Eni Energy Russia BV Third parties 54,000 Eni Croatia BV Third parties 20,000 Agip Karachag.BV Third parties United Kingdom GBP 100 Agip Karachag.BV Third parties Kuwait KWD 250,000 Eni Middle E. Ltd USA USD Third parties 0(a) Eni Oil & Gas Inc Third parties Ukraine UAH 2,000,000 Eni Ukraine Hold.BV Third parties 71.43 28.57 70.00 30.00 50.00 50.00 13.60 86.40 25.00 75.00 33.33 66.67 50.00 50.00 50.00 50.00 26.00 74.00 37.50 62.50 50.00 50.00 50.00 50.00 50.00 50.00 25.00 75.00 100.00 33.33 66.67 50.00 50.00 29.25 70.75 38.00 62.00 49.00 51.00 32.50 67.50 50.01 49.99 J.O. J.O. Co. Eq. Co. Eq. Co. Eq. Co. Co. Co. Co. Co. Co. Eq. Co. Co. Eq. Eq. Eq. Eq. (*) (†) (a) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Jointly controlled entity. Shares without nominal value. F-130 Company name Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Mediterranean Gas Co Cairo (Egypt) Mellitah Oil & Gas BV(†) Nile Delta Oil Co Nidoco North Bardawil Petroleum Co North El Burg Petroleum Company Petrobel Belayim Petroleum Co(†) PetroBicentenario SA(†) PetroJunín SA(†) PetroSucre SA Pharaonic Petroleum Co Port Said Petroleum Co(†) Raml Petroleum Co Ras Qattara Petroleum Co Rovuma Basin LNG Land Limitada(†) Shatskmorneftegaz Sàrl(†) Shorouk Petroleum Company(†) Société Centrale Electrique du Congo SA Société Italo Tunisienne d’Exploitation Pétrolière SA(†) Sodeps - Société de Developpement et d’Exploitation du Permis du Sud SA(†) Tapco Petrol Boru Hatti Sanayi ve Ticaret AS(†) Tecninco Engineering Contractors Llp(†) Thekah Petroleum Co Unimar Llc(†) United Gas Derivatives Co VIC CBM Ltd(†) Virginia Indonesia Co CBM Ltd(†) Virginia Indonesia Co Llc Virginia International Co Llc West Ashrafi Petroleum Co(†) (in liquidation) Zetah Noumbi Ltd Egypt Libya Egypt Egypt Egypt Egypt EGP EUR EGP EGP EGP EGP 20,000 Ieoc Production BV Third parties 20,000 Eni North Africa BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc Exploration BV Third parties 20,000 Ieoc SpA Third parties 20,000 Ieoc Production BV Third parties Venezuela VEF 410,500,000 Eni Lasmo Plc Third parties Venezuela VEF 2,591,100,000 Eni Lasmo Plc Third parties Venezuela VEF 220,300,000 Eni Venezuela BV Egypt Egypt Egypt Egypt EGP EGP EGP EGP Mozambique MZN Russia Egypt Republic of the Congo USD EGP XAF Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc Production BV Third parties 140,000 Eni East Africa SpA Third parties 20,000 Eni Energy Russia BV Third parties 20,000 Ieoc Production BV Third parties 44,732,000,000 Eni Congo SA Third parties Tunisia TND 5,000,000 Eni Tunisia BV Third parties Tunisia TND 100,000 Eni Tunisia BV Third parties Turkey TRY 7,850,000 Eni International BV Third parties Amsterdam (Netherlands) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Caracas (Venezuela) Caracas (Venezuela) Caracas (Venezuela) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Maputo (Mozambique) Luxembourg (Luxembourg) Cairo (Egypt) Pointe-Noire (Republic of the Congo) Tunisi (Tunisia) Tunisi (Tunisia) Istanbul (Turkey) Aksai (Kazakhstan) Kazakhstan KZT 29,478,455 Tecnomare SpA Third parties Cairo (Egypt) Houston (USA) Cairo (Egypt) London (United Kingdom) London (United Kingdom) Wilmington (USA) Wilmington (USA) Cairo (Egypt) Egypt USA Egypt EGP USD USD 20,000 Ieoc Exploration BV Third parties 0(a) Eni America Ltd Third parties 285,000,000 Eni International BV Third parties Indonesia USD 1,315,912 Eni Lasmo Plc Third parties Indonesia USD 631,640 Eni Lasmo Plc Third parties Indonesia USD 10 Unimar Llc Indonesia USD 10 Unimar Llc Egypt EGP 20,000 Ieoc Exploration BV Third parties Nassau (Bahamas) Republic of the Congo USD 100 Burren En.Congo Ltd Third parties 25.00 75.00 50.00 50.00 37.50 62.50 30.00 70.00 25.00 75.00 50.00 50.00 40.00 60.00 40.00 60.00 26.00 74.00 25.00 75.00 50.00 50.00 22.50 77.50 37.50 62.50 33.33 66.67 33.33 66.67 50.00 50.00 20.00 80.00 50.00 50.00 50.00 50.00 50.00 50.00 49.00 51.00 25.00 75.00 50.00 50.00 33.33 66.67 50.00 50.00 50.00 50.00 100.00 100.00 50.00 50.00 37.00 63.00 Co. Co. Co. Co. Co. Co. Eq. Eq. Eq. Co. Co. Co. Co. Co. Eq. Co. Eq. Eq. Co. Eq. Eq. Co. Eq. Eq. Eq. Eq. Co. Co. (*) (†) (a) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Jointly controlled entity. Shares without nominal value. F-131 Gas & Power Company name In Italy Mariconsult SpA(†) Società EniPower Ferrara Srl(†) Transmed SpA(†) Outside Italy Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Milan San Donato Milanese (MI) Italy Italy EUR 120,000 Eni SpA Third parties EUR 170,000,000 EniPower SpA Third parties Milan Italy EUR 240,000 Eni SpA Third parties Blue Stream Pipeline Co BV(†) Amsterdam (Netherlands) Russia USD 22,000 Eni International BV Third parties Egyptian International Gas Technology Co Cairo (Egypt) Egypt EGP 100,000,000 Eni International BV Third parties Gas Distribution Company of Thessaloniki - Thessaly SA(†) (former Eteria Parohis Aeriou Thessalonikis AE) GreenStream BV(†) Premium Multiservices SA SAMCO Sagl Ampelokipi- Menemeni (Greece) Amsterdam (Netherlands) Tunisi (Tunisia) Lugano (Switzerland) Greece EUR 266,309,200 Eni SpA Third parties Libya EUR 200,000,000 Eni North Africa BV Third parties Tunisia TND 200,000 Sergaz SA Switzerland CHF Third parties 20,000 Eni International BV Transmed.Pip.Co Ltd Third parties Transmediterranean Pipeline Co Ltd(†) St. Helier (Jersey) Jersey USD 10,310,000 Eni SpA Third parties Turul Gázvezeték Építõ es Vagyonkezelõ Részvénytársaság(†) Unión Fenosa Gas SA(†) Tatabànya (Hungary) Madrid (Spain) Hungary HUF 404,000,000 Tigáz Zrt Third parties Spain EUR 32,772,000 Eni SpA Third parties 51.00 50.00 50.00 50.00 50.00 50.00 51.00 49.00 50.00 50.00 50.00 50.00 40.00 60.00 49.00 51.00 50.00 50.00 49.99 50.01 5.00 90.00 5.00 50.00 50.00 58.42 41.58 50.00 50.00 Eq. J.O. Eq. J.O. Co. Eq. J.O. Eq. Eq. J.O. Eq. Eq. (*) (†) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Jointly controlled entity. F-132 Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Refining & Marketing and Chemical Refining & Marketing Company name In Italy Arezzo Gas SpA(†) CePIM Centro Padano Interscambio Merci SpA Consorzio Operatori GPL di Napoli Costiero Gas Livorno SpA(†) Petrolig Srl(†) Petroven Srl(†) Porto Petroli di Genova SpA Raffineria di Milazzo ScpA(†) SeaPad SpA(†) Arezzo Italy Fontevivo (PR) Italy Napoli Livorno Italy Italy Genova Genova Genova Italy Italy Italy Italy Disma SpA Segrate (MI) Italy PETRA SpA(†) Ravenna EUR EUR EUR EUR EUR EUR EUR EUR EUR 394,000 Eni Fuel SpA Third parties 6,642,928.32 Ecofuel SpA Third parties 102,000 Eni Fuel SpA Third parties 26,000,000 Eni Fuel SpA Third parties 2,600,000 Eni Fuel SpA Third parties 723,100 Ecofuel SpA Third parties 104,000 Ecofuel SpA Third parties 156,000 Ecofuel SpA Third parties 2,068,000 Ecofuel SpA Third parties Third parties 12,400,000 Ecofuel SpA Third parties 852,000 Eni SpA Third parties 50.00 50.00 34.93 65.07 25.00 75.00 65.00 35.00 25.00 75.00 50.00 50.00 70.00 30.00 68.00 32.00 40.50 59.50 50.00 50.00 80.00 20.00 25.00 75.00 65.00 70.00 68.00 50.00 Eq. Eq. Co. J.O. Eq. Eq. J.O. J.O. Eq. J.O. Eq. Co. J.O. Eq. J.O. Milazzo (ME) Italy EUR 171,143,000 Eni SpA Genova Italy Seram SpA Fiumicino (RM) Italy Servizi Milazzo Srl(†) Milazzo (ME) Genova Italy Italy Sigea Sistema Integrato Genova Arquata SpA Termica Milazzo Srl(†) Milazzo (ME) Italy EUR EUR EUR EUR EUR 100,000 Raff. Milazzo ScpA 100.00 50.00 3,326,900 Ecofuel SpA Third parties 35.00 65.00 100,000 Raff. Milazzo ScpA 100.00 50.00 (*) (†) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Jointly controlled entity. F-133 Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Refining & Marketing Company name Outside Italy AET - Raffineriebeteiligungs gesellschaft mbH Bayernoil Raffineriegesellschaft mbH(†) City Carburoil SA(†) ENEOS Italsing Pte Ltd FSH Flughafen Schwechat Hydranten-Gesellschaft OG Fuelling Aviation Services GIE Schwedt (Germany) Vohburg (Germany) Rivera (Switzerland) Singapore (Singapore) Wien (Austria) Tremblay en France (France) Germany EUR 27,000 Eni Deutsch.GmbH Third parties Germany EUR 10,226,000 Eni Deutsch.GmbH Third parties Switzerland CHF 6,000,000 Eni Suisse SA Third parties Singapore SGD 12,000,000 Eni International BV Third parties Austria EUR 7,098,752.57 Eni Market.A.GmbH France EUR Eni Mineralölh.GmbH Eni Austria GmbH Third parties 1 Eni France Sàrl Third parties Mediterranée Bitumes SA Tunisi (Tunisia) Routex BV Saraco SA Supermetanol CA(†) TBG Tanklager Betriebsgesellschaft GmbH(†) Weat Electronic Datenservice GmbH Amsterdam (Netherlands) Meyrin (Switzerland) Jose Puerto La Cruz (Venezuela) Salzburg (Austria) Düsseldorf (Germany) Tunisia TND 1,000,000 Eni International BV Netherlands EUR Switzerland CHF Third parties 67,500 Eni International BV Third parties 420,000 Eni Suisse SA Third parties Venezuela VEF 12,086,744.84 Ecofuel SpA Supermetanol CA Third parties Austria EUR 43,603.70 Eni Market.A.GmbH Third parties Germany EUR 409,034 Eni Deutsch.GmbH Third parties 20.00 50.00 33.33 66.67 20.00 80.00 49.91 50.09 22.50 77.50 14.29 14.29 14.28 57.14 25.00 75.00 34.00 66.00 20.00 80.00 20.00 80.00 34.51(a) 30.07 35.42 50.00 50.00 20.00 80.00 Eq. J.O. Eq. Eq. Co. Co. Eq. Eq. Co. J.O. Eq. Eq. (*) (†) (a) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Jointly controlled entity. Controlling interest: Ecofuel SpA Third parties 50.00 50.00 F-134 Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Chemical Company name In Italy Brindisi Servizi Generali Scarl Brindisi Italy EUR IFM Ferrara ScpA Ferrara Italy EUR Matrìca SpA(†) Porto Torres (SS) Italy Newco Tech SpA(†) Novara Novamont SpA Novara Priolo Servizi ScpA Melilli (SR) Italy Italy Italy EUR EUR EUR EUR Ravenna Servizi Industriali ScpA Ravenna Italy EUR Servizi Porto Marghera Scarl Porto Marghera (VE) Italy EUR 1,549,060 Versalis SpA Syndial SpA EniPower SpA Third parties 5,270,466 Versalis SpA Syndial SpA S.E.F. Srl Third parties 37,500,000 Versalis SpA Third parties 500,000 Versalis SpA Genomatica Inc. 13,333,500 Versalis SpA Third parties 28,100,000 Versalis SpA Syndial SpA Third parties 5,597,400 Versalis SpA EniPower SpA Ecofuel SpA Third parties 8,695,718 Versalis SpA Syndial SpA Third parties 49.00 20.20 8.90 21.90 19.74 11.58 10.70 57.98 50.00 50.00 80.00 20.00 25.00 75.00 33.16 4.38 62.46 42.13 30.37 1.85 25.65 48.44 38.39 13.17 50.00 50.00 Eq. Eq. Eq. Eq. Eq. Eq. Eq. Eq. Eq. Outside Italy Lotte Versalis Elastomers Co Ltd(†) Yeosu (South Korea) South Korea KRW 192,000,010,000 Versalis SpA Third parties (*) (†) 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 Corporate and other activities Other activities Company name In Italy Filatura Tessile Nazionale Italiana - FILTENI SpA (in liquidation) Ottana Sviluppo ScpA (in liquidation) Saipem SpA(#)(†) Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Ferrandina (MT) Italy EUR 4,644,000 Syndial SpA Third parties Nuoro San Donato Milanese (MI) Italy Italy EUR 516,000 Syndial SpA Third parties EUR 2,191,384,693 Eni SpA Saipem SpA Third parties 59.56(a) 40.44 30.00 70.00 30.54(b) 0.70 68.76 Consolidation or valutation method(*) Co. Eq. Eq. (*) (#) (†) (a) 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. Controlling interest: Syndial SpA Third parties 48.00 52.00 (b) Controlling interest: Eni SpA Third parties 30.76 69.24 F-136 Other significant investments Exploration & Production Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Company name In Italy Consorzio Universitario in Ingegneria per la Qualità e l’Innovazione Outside Italy Administradora del Golfo de Paria Este SA Brass LNG Ltd Darwin LNG Pty Ltd New Liberty Residential Co Llc Pisa Italy EUR 135,000 Eni SpA Third parties Caracas (Venezuela) Lagos (Nigeria) West Perth (Australia) West Trenton (USA) Venezuela VEF 100 Eni Venezuela BV Third parties Nigeria USD 1,000,000 Eni Int. NA NV Sàrl Third parties Australia AUD 845,104,523.19 Eni G&P LNG Aus. BV USA USD Third parties 0(a) Eni Oil & Gas Inc Third parties Nigeria LNG Ltd Port Harcourt (Nigeria) Nigeria USD 1,138,207,000 Eni Int. NA NV Sàrl Third parties Norsea Pipeline Ltd Woking Surrey (United Kingdom) United Kingdom GBP 7,614,062 Eni SpA Third parties North Caspian Operating Co NV Amsterdam (Netherlands) Kazakhstan EUR Angola AOA 128,520 Agip Caspian Sea BV Third parties 7,400,000 Eni Angola Prod.BV Third parties Luanda (Angola) Caracas (Venezuela) Port Of Spain (Trinidad and Tobago) Luanda (Angola) OPCO - Sociedade Operacional Angola LNG SA Petrolera Güiria SA Point Fortin LNG Exports Ltd SOMG - Sociedade de Operações e Manutenção de Gasodutos SA Torsina Oil Co Venezuela VEF 1,000,000 Eni Venezuela BV Trinidad and Tobago USD Third parties 10,000 Eni T&T Ltd Third parties Angola AOA 7,400,000 Eni Angola Prod.BV Third parties Cairo (Egypt) Egypt EGP 20,000 Ieoc Production BV Third parties 16.67 83.33 19.50 80.50 20.48 79.52 10.99 89.01 17.50 82.50 10.40 89.60 10.32 89.68 16.81 83.19 13.60 86.40 19.50 80.50 17.31 82.69 13.60 86.40 12.50 87.50 Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. (*) (a) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Shares without nominal value. F-137 Gas & Power Company name Outside Italy Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Angola LNG Supply Services Llc Norsea Gas GmbH Wilmington (USA) Emden (Germany) USA USD 19,278,782 Eni USA Gas M. Llc Third parties Germany EUR 1,533,875.64 Eni International BV Third parties 13.60 86.40 13.04 86.96 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Consolidation or valutation method(*) Co. Co. Refining & Marketing and Chemical Refining & Marketing Company name In Italy Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Consolidation or valutation method(*) Consorzio Obbligatorio degli Oli Usati Società Italiana Oleodotti di Gaeta SpA(1) Rome Rome Italy Italy EUR ITL 36,149 Eni SpA Third parties 360,000,000 Eni SpA Third parties Outside Italy BFS Berlin Fuelling Services GbR Compania de Economia Mixta ‘Austrogas’ Dépot Pétrolier de Fos SA Dépôt Pétrolier de la Côte dAzur SAS Joint Inspection Group Ltd S.I.P.G. Socété Immobilier Pétrolier de Gestion Snc Hamburg (Germany) Cuenca (Ecuador) Fos-Sur-Mer (France) Nanterre (France) London (United Kingdom) Tremblay-En- France (France) Sistema Integrado de Gestion de Aceites Usados Madrid (Spain) Germany EUR 145,758 Eni Deutsch.GmbH Third parties Ecuador USD 3,028,749 Eni Ecuador SA France EUR Third parties 3,954,196.40 Eni France Sàrl Third parties France EUR 207,500 Eni France Sàrl United Kingdom GBP France EUR Third parties 0(a) Eni SpA Third parties 40,000 Eni France Sàrl Third parties Spain EUR 175,713 Eni Iberia SLU Tanklager - Gesellschaft Tegel (TGT) GbR TAR - Tankanlage Ruemlang AG Tema Lube Oil Co Ltd Hamburg (Germany) Ruemlang (Switzerland) Accra (Ghana) Germany EUR Switzerland CHF Ghana GHS Third parties 23 Eni Deutsch.GmbH Third parties 3,259,500 Eni Suisse SA Third parties 258,309 Eni International BV Third parties 13.27 86.73 72.48 27.52 12.50 87.50 13.31 86.69 16.81 83.19 18.00 82.00 12.50 87.50 12.50 87.50 15.44 84.56 12.50 87.50 16.27 83.73 12.00 88.00 Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. Co. (*) (a) (1) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Shares without nominal value. Company under extraordinary administration procedure pursuant to Law no. 95 of April 3, 1979. F-138 Corporate and other activities Corporate and financial companies Registered office Country of operation Currency Share Capital Shareholders % Ownership % Equity ratio Company name In Italy Emittenti Titoli SpA Mip Politecnico di Milano - Graduate School of Business ScpA Milan Italy EUR Milan Italy EUR 4,264,000 Eni SpA Emittenti Titoli SpA Third parties 150,000 Eni Corporate U.SpA Third parties 10.00(a) 0.78 89.22 10.67 89.33 Consolidation or valutation method(*) Co. Co. (*) (a) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value Controlling interest: Eni SpA Third parties 10.08 89.92 Information on Eni’s consolidated subsidiaries with significant non-controlling interest In 2016, Eni did not own any consolidated subsidiaries with a significant non-controlling interest. In 2015, Eni did not own any consolidated subsidiaries with significant non-controlling interests as consequence of the classification of the Saipem Group as discontinued operations. Total shareholders’ equity attributable to non-controlling interests amounted to €49 million (€1,916 million at December 31, 2015, of which €1,872 million pertaining to the Saipem Group). Changes in the ownership interest without loss of control In 2015 and 2016, Eni did not report any changes in ownership interest without loss or acquisition of control. Principal joint ventures, joint operations and associates as of December 31, 2016 Company name Joint venture CARDÓN IV SA ......................... Gas Distribution Company of Thessaloniki - Thessaly SA .......... PetroJunín SA ............................. Saipem SpA ................................ Unión Fenosa Gas SA ................... Joint Operation Blue Stream Pipeline Co BV ................................... Eni East Africa SpA ..................... Raffineria di Milazzo ScpA ..................................... Registered office Operating office Business segment % ownership interest % voting rights Venezuela Exploration & Production 50.00 50.00 Caracas (Venezuela) Ampelokipi- Menemeni (Greece) Caracas (Venezuela) San Donato Milanese (MI) (Italy) Madrid (Spain) Greece Venezuela Gas & Power Exploration & Production 49.00 40.00 Italia Spain Other Activities 30.54 Gas & Power 50.00 Amsterdam (Netherlands) San Donato Milanese (MI) (Italy) Milazzo (ME) (Italy) Russia Mozambique Italy Gas & Power Exploration & Production Refining & Marketing 49.00 40.00 30.76 50.00 50.00 71.43 50.00 13.60 33.33 50.00 71.43 50.00 13.60 33.33 Associates Angola LNG Ltd ......................... United Gas Derivatives Co ............. Hamilton (Bermuda) Cairo (Egypt) Angola Egypt Exploration & Production Exploration & Production F-139 The 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: 1,125 27 2,951 4,076 3,356 2,223 298 3,654 422 50.00 211 (€ million) Current assets . . . . . . . . . . . . . - of which cash and cash equivalent . . . . . . . . . . . . . . . Non-current assets . . . . . . . . Total assets . . . . . . . . . . . . . . . . . Current liabilities . . . . . . . . . - current financial liabilities . . . . . . . . . . . . . . . . Non-current liabilities . . . . - non-current financial liabilities . . . . . . . . . . . . . . . . Total liabilities . . . . . . . . . . . . . Net equity . . . . . . . . . . . . . . . . . . Eni’s ownership interest (%) . . . . . . . . . . . . . Book value of the investment . . . . . . . . . . . . . . Revenues and other operating income . . . . . . Operating expense . . . . . . . . Other operating profit (loss) . . . . . . . . . . . . . Depreciation, amortization and impairments . . . . . . . . . . . Operating profit. . . . . . . . . . . . Finance (expense) income. Income (expense) from investments . . . . . . . . . . . . . Profit before income taxes . Income taxes . . . . . . . . . . . . . . Net profit . . . . . . . . . . . . . . . . . . Other comprehensive income . . . . . . . . . . . . . . . . . . Total other comprehensive income . . . . . . . . . . . . . . . . . . Net profit attributable to Eni . . . . . . . . . . . . . . . . . . . Dividends received by the joint venture . . . . . . . . . . . . 2015 Gas Distribution Company of Thessaloniki -Thessaly SA Petro Junín SA Unión Fenosa Gas SA CARDÓN IV SA Other joint ventures Saipem SpA CARDÓN IV SA 2016 Gas Distribution Company of Thessaloniki -Thessaly SA 61 34 204 265 19 197 5 623 820 361 23 25 42 223 386 434 695 326 7,783 451 55 1,156 1,851 294 113 1,086 1,412 705 1,892 6,500 14,283 5,668 55 697 590 991 860 496 167 76 872 540 206 3,730 3,194 9,398 4,885 31 3,628 4,079 455 3,230 2,108 3,685 394 34 8 285 319 13 13 306 Petro Junín SA Unión Fenosa Gas SA Other joint ventures 336 651 209 2 25 703 1,037 1,039 1,688 232 480 61 650 547 882 806 32 512 527 56 886 1,095 469 299 339 281 808 287 49.00 40.00 50.00 30.76 50.00 49.00 40.00 50.00 109 174 503 264 1,497 197 150 211 434 146 189 (73) 137 (92) 84 1,770 (67) (1,739) 447 (297) 10,009 (9,100) 738 (233) 152 (98) 105 (60) 905 (921) 275 (280) (29) 87 (84) 3 (11) (8) 44 36 (4) (14) 31 31 (9) 22 22 11 8 (33) (16) 107 91 (18) 73 (137) (106) (53) 29 (130) 31 (99) (178) (28) (5) (2,408) (1,499) (154) (7) (40) 1 (39) 18 (1,635) (445) (2,080) (87) 418 (206) 212 (252) (40) 30 25 26 48 12 103 (74) (13) (2,032) (28) 29 (74) (14) (144) (20) 13 8 (5) (169) (179) (19) (198) (20) (218) (131) (147) 31 13 (103) 23 (80) 29 (2) (51) (220) (40) 5 94 99 (24) 75 18 93 30 (82) (125) 35 (22) 32 32 (12) 20 20 10 10 F-140 The 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: (€ million) Current assets .......................... - of which cash and cash equivalent ................................ Non-current assets ................... Total assets .............................. Current liabilities ..................... - current financial liabilities ........ Non-current liabilities ............... - non-current financial liabilities ... Total liabilities ......................... Net equity ................................ Eni’s ownership interest (%) ....... Book value of the investment ....... Revenues and other operating income .................................... Operating expense .................... Other operating profit (loss) ...... Depreciation, depletion, amortization and impairments ... Operating profit ........................ Finance (expense) income .......... Income (expense) from investments .............................. Profit before income taxes .......... Income taxes ............................ Net profit ................................. Other comprehensive income ..... Total other comprehensive income .................................... 2015 2016 Angola LNG Ltd PetroSucre SA United Gas Derivatives Co Other associates Angola LNG Ltd PetroSucre SA United Gas Derivatives Co Other associates 111 950 329 215 507 1,119 253 219 11 8,092 8,203 498 2 618 1,568 1,013 215 81 234 126 455 101 14 713 7,490 13.60 1,019 1,094 474 26.00 123 115 340 33.33 113 29 417 632 165 50 130 69 295 337 150 339 8,376 8,883 284 1,863 1,699 2,147 6,736 13.60 916 3 1,119 1,049 70 1,119 26.00 146 140 393 41 1 42 351 33.33 117 (255) 466 (452) 142 (59) 487 (415) 84 (281) 315 (224) 102 (61) (3,180) (3,435) (10) (3,445) (3,445) 992 (197) (183) (11) (194) (60) (254) 71 (2,453) (183) (28) 55 18 73 (12) 61 35 96 20 21 (36) 36 (4) 1 33 (7) 26 9 35 3 1 (188) (385) (70) (455) (455) 200 (568) (477) 228 (249) (103) (352) (8) (255) (360) (62) (92) 30 (13) 28 11 39 5 44 11 55 14 14 29 569 788 183 25 200 78 383 405 167 924 (827) (2) (57) 38 (4) 34 (5) 29 1 30 4 9 Net profit attributable to Eni ...... (469) (66) Dividends received by the associate .................................. F-141 49 Significant non-recurring events and operations In 2014, in 2015 and 2016, Eni did not report any non-recurring events and operations. 50 Positions or transactions deriving from atypical and/or unusual operations In 2014, 2015 and 2016 no transactions deriving from atypical and/or unusual operations were reported. 51 Subsequent events No significant events were reported after December 31, 2016. F-142 Supplemental oil and gas information (unaudited) The following information pursuant to “International Financial Reporting Standards” (IFRS) is presented in accordance with FASB Extractive Activities — Oil & Gas (Topic 932). Amounts related to minority interests are not significant. Capitalized costs Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following: (€ million) 2015 Consolidated subsidiaries Proved property . . . . . . . . . . . . . . . . . . . . Unproved property . . . . . . . . . . . . . . . . Support equipment and facilities . Incomplete wells and other . . . . . . . Gross Capitalized Costs . . . . . . . . . . . . . . . Accumulated depreciation, depletion and amortization . . . . . . . . Net Capitalized Costs consolidated subsidiaries(a) . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-accounted entities Proved property . . . . . . . . . . . . . . . . . . . . Unproved property . . . . . . . . . . . . . . . . Support equipment and facilities . Incomplete wells and other . . . . . . . Gross Capitalized Costs . . . . . . . . . . . . . . . Accumulated depreciation, depletion and amortization . . . . . . . . Net Capitalized Costs equity-accounted entities(a) . . . . . . . . . . . . 2016 Consolidated subsidiaries Proved property . . . . . . . . . . . . . . . . . . . . Unproved property . . . . . . . . . . . . . . . . Support equipment and facilities . Incomplete wells and other . . . . . . . Gross Capitalized Costs . . . . . . . . . . . . . . . Accumulated depreciation, depletion and amortization . . . . . . . . Net Capitalized Costs consolidated subsidiaries(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-accounted entities Proved property . . . . . . . . . . . . . . . . . . . . Unproved property . . . . . . . . . . . . . . . . Support equipment and facilities . Incomplete wells and other . . . . . . . Gross Capitalized Costs . . . . . . . . . . . . . . . Accumulated depreciation, depletion and amortization . . . . . . . . Net Capitalized Costs equity-accounted entities(a) . . . . . . . . . . . . Italy Rest of Europe North Africa* *Egypt (of which) Sub - Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 15,280 18 355 1,114 16,767 15,110 297 42 3,501 18,950 26,904 444 1,758 2,280 31,386 35,241 2,443 1,318 4,932 43,934 3,364 1 112 8,900 12,377 10,424 1,229 34 1,665 13,352 16,156 874 74 729 17,833 2,037 203 15 123 2,378 124,516 5,509 3,708 23,244 156,977 (12,184) (11,431) (20,268) (25,235) (1,422) (9,691) (13,344) (1,122) (94,697) 4,583 7,519 11,118 18,699 10,955 3,661 4,489 1,256 62,280 3 17 10 30 89 8 5 102 (23) (77) 7 25 23 1,508 1,531 (441) 1,090 624 93 23 740 2,010 6 112 2,128 (628) (338) 112 1,790 2,749 110 14 1,658 4,531 (1,507) 3,024 15,951 18 357 724 17,050 18,678 301 42 242 19,263 28,754 471 1,830 4,175 35,230 15,262 55 203 1,828 17,348 38,539 2,461 1,375 5,117 47,492 10,790 1 111 2,565 13,467 11,680 1,155 37 2,248 15,120 17,127 903 77 317 18,424 2,085 210 15 134 2,444 143,604 5,520 3,844 15,522 168,490 (13,022) (12,113) (22,396) (11,022) (27,264) (1,608) (11,000) (14,301) (1,227) (102,931) 4,028 7,150 12,834 6,326 20,228 11,859 4,120 4,123 1,217 65,559 2 15 9 26 82 8 5 95 (20) (72) 6 23 14 1,596 1,610 (482) 1,128 657 96 24 777 2,037 7 253 2,297 (682) (602) 95 1,695 2,792 111 15 1,887 4,805 (1,858) 2,947 (a) The amounts include net capitalized financial charges totalling €1.029 million in 2015 and €1.090 million in 2016 for the consolidates subsidiaries and €92 million in 2015 and €95 million in 2016 for equity-accounted entities. F-143 Costs incurred Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following: (€ million) 2014 Consolidated subsidiaries Italy Rest of Europe North Africa* *Egypt (of which) Sub - Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total Proved property acquisitions . . . . . . . . . . . . . . . Unproved property acquisitions . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development(a) 188 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,382 2,395 Total costs incurred consolidated subsidiaries . . 1,411 2,583 Equity-accounted entities 29 227 955 1,182 635 3,479 4,114 160 1,118 1,278 139 1,169 1,308 20 122 142 1,398 11,192 12,590 572 572 Proved property acquisitions . . . . . . . . . . . . . . . Unproved property acquisitions . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total costs incurred equity-accounted entities . . 2015 Consolidated subsidiaries Proved property acquisitions . . . . . . . . . . . . . . . Unproved property acquisitions . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total costs incurred consolidated subsidiaries . . Equity-accounted entities Proved property acquisitions . . . . . . . . . . . . . . . Unproved property acquisitions . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total costs incurred equity-accounted entities . . 2016 Consolidated subsidiaries Proved property acquisitions . . . . . . . . . . . . . . . Unproved property acquisitions . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total costs incurred consolidated subsidiaries . . Equity-accounted entities Proved property acquisitions . . . . . . . . . . . . . . . Unproved property acquisitions . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Development(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total costs incurred equity-accounted entities . 2 2 1 1 22 22 33 38 71 1 375 376 36 436 472 28 176 207 1,006 235 1,182 289 1,574 1,863 196 2,957 3,153 71 1,332 1,403 819 819 1 1 2 1 1 112 112 14 35 49 27 387 414 51 437 488 2 364 2,446 2,812 2 306 1,752 2,060 70 2,019 2,089 80 1,232 1,312 651 651 1 1 1 1 28 28 13 12 25 54 745 799 1 554 555 26 (5) 21 95 95 6 18 24 820 8,658 9,478 16 703 719 2 621 7,168 7,791 3 1 4 14 136 150 (a) (b) Includes the abandonment costs of the assets for €2,062 million in 2014, negative for €817 million in 2015 and negative for €665 million in 2016. Includes the abandonment costs of the assets negative for €47 million in 2014, costs for €54 million in 2015 and negative for €15 million in 2016. Results of operations from oil and gas producing activities Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to meet Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. F-144 Results of operations from oil and gas producing activities by geographical area consist of the following: 2014 (€ million) Italy Rest of Europe North Africa Sub - Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total (245) 2,721 596 3,317 (687) 4,716 1,369 6,085 (935) (648) (681) 2,010 7,415 9,425 (694) (291) (72) Consolidated subsidiaries Revenues: - sales to consolidated entities .............. 3,028 - sales to third parties ......................... Total revenues .................................. 3,028 (423) Operations costs ............................... (293) Production taxes ............................... Exploration expenses ......................... (36) D.D. & A. and Provision for abandonment(a) ................................ (819) (1,082) (1,330) (1,985) (358) Other income (expenses) ..................... (184) (773) (96) Pretax income from producing activities ... 1,273 1,478 6,265 1,207 Income taxes ................................... (785) (3,992) (1,155) (503) Results of operations from E&P activities of consolidated subsidiaries .................. Equity-accounted entities Revenues: - sales to consolidated entities .............. - sales to third parties ......................... Total revenues .................................. Operations costs ............................... Production taxes ............................... Exploration expenses ......................... D.D. & A. and Provision for abandonment .................................. Other income (expenses) ..................... Pretax income from producing activities ... Income taxes ................................... Results of operations from E&P activities of equity-accounted entities .................. 19 19 (11) (3) (2) (2) 1 2 (2) (1) (1) (3) (32) (32) 2,273 (32) 770 422 323 (3) (1) 346 976 1,322 (208) 589 774 1,363 (223) (33) (204) 1,691 129 1,820 (357) (171) (90) (251) 773 (291) (860) (124) (81) (102) (1,295) (78) (81) 29 67 299 366 (124) (15) (69) (175) (30) (47) 43 15,168 11,558 26,726 (3,651) (1,280) (1,478) (7,636) (1,894) 10,787 (6,756) 482 (183) (52) (4) 4,031 87 87 (11) (31) (40) (3) 2 (23) (21) 232 232 (27) (94) (1) (60) (41) 9 (18) (9) 338 338 (49) (97) (35) (103) (76) (22) (43) (65) (a) Includes asset impairments amounting to €851 million F-145 2015 (€ million) Rest of Europe North Africa Italy Sub - Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 537 (182) Consolidated subsidiaries Revenues: - sales to consolidated entities ............. 2,124 - sales to third parties ........................ Total revenues ................................. 2,124 (403) Operations costs .............................. (184) Production taxes .............................. Exploration expenses ........................ (35) D.D. & A. and Provision for abandonment(a) ............................... Other income (expenses) .................... Pretax income from producing activities......................................... Income taxes .................................. Results of operations from E&P activities of consolidated subsidiaries ................. Equity-accounted entities Revenues: - sales to consolidated entities ............. - sales to third parties ........................ Total revenues ................................. Operations costs .............................. Production taxes .............................. Exploration expenses ........................ D.D. & A. and Provision for abandonment ................................. Other income (expenses) .................... Pretax income from producing activities......................................... Income taxes .................................. Results of operations from E&P activities of equity-accounted entities ................. 355 1,828 501 2,329 (642) (205) 3,514 1,403 914 5,681 4,428 7,084 (948) (1,099) (405) (240) (216) (164) (750) (2,022) (2,938) (3,835) (290) (215) (564) (142) (682) 2,230 (1,417) 272 589 (2,148) 231 659 890 (239) (109) (156) 386 (142) 628 854 1,482 (235) (30) (210) 1,118 131 1,249 (453) (35) 29 226 255 (108) (9) (6) 10,875 8,966 19,841 (4,127) (868) (871) (1,491) (1,775) (9) (282) (111) (23) (13,031) (1,681) (766) (1,023) 406 90 (2) (25) (737) (1,140) (93) 82 (1,145) 244 (676) (617) (27) (1,877) 19 19 (9) (3) (3) (1) 3 (3) (432) (35) (467) (467) (1) (3) (4) (4) 68 68 (13) (16) (77) (6) (44) 8 248 248 (49) (82) (78) (48) (9) (29) (36) (38) 335 335 (71) (85) (16) (591) (93) (521) (24) (545) (a) Includes asset impairments amounting to €5,051 million F-146 2016 (€ million) Rest of Europe North Africa* *Egypt (of which) Italy Sub - Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 291 (40) (490) 159 (923) (342) (311) (96) (35) Consolidated subsidiaries Revenues: - sales to consolidated entities . 1,217 1,673 - sales to third parties ........... 432 Total revenues ..................... 1,217 2,105 Operations costs ................. (599) Production taxes ................. Exploration expenses ........... D.D. & A. and Provision for abandonment(a) .................. Other income (expenses) ....... Pretax income from producing activities ........................... Income taxes ...................... Results of operations from E&P activities of consolidated subsidiaries ........................ Equity-accounted entities Revenues: - sales to consolidated entities . - sales to third parties ........... Total revenues ..................... Operations costs ................. Production taxes ................. Exploration expenses ........... D.D. & A. and Provision for abandonment ..................... Other income (expenses) ....... Pretax income from producing activities ........................... Income taxes ...................... Results of operations from E&P activities of equity-accounted entities .............................. (331) 290 (3) (3) (3) 941 4,312 5,253 (807) (176) (87) 9 1,471 1,480 (356) (42) 3,178 485 3,663 (968) (282) (142) (943) (1,366) (466) (232) 2,351 (1) (1,707) (691) (265) (1,093) (917) 126 (89) 261 97 252 606 858 (269) (129) (57) 403 (139) 1,027 114 1,141 (215) (17) (39) 833 102 935 (325) (28) (952) (130) (480) (120) 4 165 169 (49) (5) (3) (67) (8) 9,125 6,216 15,341 (3,543) (576) (374) (5,953) (2,272) (212) 32 (18) (9) 37 (9) 2,623 (1,577) 644 37 358 264 (180) (27) 28 1,046 15 15 (9) (3) (1) (1) 1 (2) (1) 36 36 (10) (13) (32) (16) (35) (6) 493 493 (54) (121) (240) (25) 53 (162) 544 544 (73) (124) (13) (299) (71) (36) (170) (26) (26) (52) (52) (41) (109) (206) (a) Includes asset net (reversal) amounting to €700 million Oil and natural gas reserves Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities — Oil & Gas (Topic 932). Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geo-scientific 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 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. an unweighted arithmetic report, determined as average of the In 2016, the average price for the marker Brent crude oil was $42.8 per barrel. F-147 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. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation20 of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserves audit is included in the third party audit report21. In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided. In 2016, Ryder Scott Company and DeGolyer and MacNaughton and Gaffney, Cline & Associates21 provided an independent evaluation of about 41% of Eni’s total proved reserves as of December 31, 201622, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three-year period from 2014 to 2016, 94% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2016, the principal properties not subjected to independent evaluation in the last three years are Zubair (Iraq), Bu Attifel (Libya), and Cafc-Mle (Algeria). Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 50%, 52% and 59% of total proved reserves as of December 31, 2014, 2015 and 2016, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and “buy-back” contracts; proved reserves associated with such contracts represented 3%, 5% and 5% of total proved reserves on an oil-equivalent basis as of December 31, 2014, 2015 and 2016, respectively. Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 0,6%, 0,6% and 1,8% of total proved reserves as of December 31, 2014, 2015 and 2016, 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. 20 21 22 From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott, from 2015 also Gaffney, Cline & Associates. The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2016. Including reserves of equity-accounted entities. F-148 The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2014, 2015 and 2016. Crude oil (Including Condensate and Natural Gas Liquids) (million barrels) 2014 Rest of Europe North Africa Italy Sub - Saharan Africa Kazakhstan Rest of Australia and Asia America Oceania Total Consolidated subsidiaries Reserves at December 31, 2013 ................... 220 of which: developed ............................... 177 undeveloped ..................................... 43 Purchase of Minerals in Place ..................... Revisions of Previous Estimates .................. Improved Recovery .................................. Extensions and Discoveries ........................ Production ............................................ Sales of Minerals in Place .......................... Reserves at December 31, 2014 ................... 243 49 1 (27) Equity-accounted entities Reserves at December 31, 2013 ................... of which: developed ............................... undeveloped ..................................... Purchase of Minerals in Place ..................... Revisions of Previous Estimates .................. Improved Recovery .................................. Extensions and Discoveries ........................ Production ............................................ Sales of Minerals in Place .......................... Reserves at December 31, 2014 ................... Reserves at December 31, 2014 ....................... 243 Developed ................................................. 184 consolidated subsidiaries ........................... 184 equity-accounted entities ........................... Undeveloped .............................................. consolidated subsidiaries ........................... equity-accounted entities ........................... 59 59 330 179 151 1 35 (34) (1) 331 830 561 269 32 3 2 (91) 776 16 16 (1) 723 465 258 70 1 36 (84) (7) 739 15 15 3 (1) (1) 14 790 534 521 13 256 255 1 17 756 477 470 7 279 269 10 331 174 174 157 157 679 295 384 35 2 128 38 90 16 (19) (13) 697 131 1 1 1 132 64 64 68 67 1 697 306 306 391 391 147 96 51 22 5 (27) 147 116 19 97 5 (4) 117 264 142 116 26 122 31 91 22 20 2 (7) (2) 13 13 12 12 1 1 3,079 1,831 1,248 1 252 6 44 (297) (8) 3,077 148 35 113 7 (6) 149 3,226 1,893 1,847 46 1,333 1,230 103 2015 Consolidated subsidiaries Rest of Europe North Africa Italy Sub - Saharan Africa Kazakhstan Rest of Australia and Asia America Oceania Total Reserves at December 31, 2014 ................... 243 of which: developed ............................... 184 undeveloped ..................................... 59 Purchase of Minerals in Place ..................... Revisions of Previous Estimates .................. Improved Recovery .................................. Extensions and Discoveries ........................ Production ............................................ Sales of Minerals in Place .......................... Reserves at December 31, 2015 ................... 228 10 (25) Equity-accounted entities Reserves at December 31, 2014 ................... of which: developed ............................... undeveloped ..................................... Purchase of Minerals in Place ..................... Revisions of Previous Estimates .................. Improved Recovery .................................. Extensions and Discoveries ........................ Production ............................................ Sales of Minerals in Place .......................... Reserves at December 31, 2015 ................... Reserves at December 31, 2015 ....................... 228 Developed.................................................. 171 consolidated subsidiaries ........................... 171 equity-accounted entities ........................... Undeveloped............................................... consolidated subsidiaries ........................... equity-accounted entities ........................... 57 57 697 306 391 94 131 64 67 159 (20) (28) 771 262 1 1 147 116 31 64 6 (28) 189 117 26 91 45 (1) (4) 771 355 355 416 416 262 126 126 136 136 158 347 178 149 29 169 40 129 13 12 1 (2) (2) 9 9 9 9 3,077 1,847 1,230 612 2 22 (325) (16) 3,372 149 46 103 44 (6) 187 3,559 2,148 2,100 48 1,411 1,272 139 739 470 269 143 14 (93) (16) 787 17 7 10 (1) 16 803 517 511 6 286 276 10 331 174 157 5 (31) 776 521 255 139 2 2 (98) 305 821 14 13 1 (1) 13 834 555 542 13 279 279 305 237 237 68 68 F-149 Crude oil (Including Condensate and Natural Gas Liquids) continued (million barrels) 2016 Rest of Europe North Africa* *Egypt (of which) Italy Sub - Saharan Africa Kazakhstan Rest of Australia and Asia America Oceania Total Consolidated subsidiaries Reserves at December 31, 2015 . . . . . . . . . . . 228 of which: developed . . . . . . . . . . . . . . . . . . . . . 171 57 undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . Purchase of Minerals in Place . . . . . . . . . . . . Revisions of Previous Estimates . . . . . . . . . Improved Recovery . . . . . . . . . . . . . . . . . . . . . . . Extensions and Discoveries . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales of Minerals in Place . . . . . . . . . . . . . . . . Reserves at December 31, 2016 . . . . . . . . . . . 176 (17) (35) Equity-accounted entities Reserves at December 31, 2015 . . . . . . . . . . . of which: developed . . . . . . . . . . . . . . . . . . . . . undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . Purchase of Minerals in Place . . . . . . . . . . . . Revisions of Previous Estimates . . . . . . . . . Improved Recovery . . . . . . . . . . . . . . . . . . . . . . . Extensions and Discoveries . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales of Minerals in Place . . . . . . . . . . . . . . . . Reserves at December 31, 2016 . . . . . . . . . . . Reserves at December 31, 2016 . . . . . . . . . . . . . . . 176 Developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 consolidated subsidiaries . . . . . . . . . . . . . . . . . 132 equity-accounted entities . . . . . . . . . . . . . . . . . Undeveloped . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . consolidated subsidiaries . . . . . . . . . . . . . . . . . equity-accounted entities . . . . . . . . . . . . . . . . . 44 44 305 237 68 (4) 1 2 (40) 821 542 279 (7) 1 9 (89) 327 230 97 (26) 8 (28) 264 735 281 13 13 1 (1) 13 748 505 492 13 243 243 264 228 228 36 36 281 205 205 76 76 787 511 276 113 (91) 809 16 6 10 (1) 15 824 515 507 8 309 302 7 771 355 416 20 (24) 767 767 556 556 211 211 262 126 136 73 189 149 40 (1) (28) (25) 307 307 124 124 183 183 163 158 29 129 (13) (5) 140 303 165 143 22 138 20 118 9 9 1 (1) 9 9 8 8 1 1 3,372 2,100 1,272 160 2 11 (315) 3,230 187 48 139 (13) (6) 168 3,398 2,233 2,190 43 1,165 1,040 125 Natural Gas(a) (billion cubic feet) 2014 Rest of Europe North Africa Italy Sub - Saharan Africa Kazakhstan Rest of Australia and Asia America Oceania Total Consolidated subsidiaries of which: developed ............................ 1,266 266 Reserves at December 31, 2013 ................ 1,532 1,247 5,231 2,374 904 2,432 1,295 343 2,799 1,079 21 99 undeveloped .................................. Purchase of Minerals in Place .................. Revisions of Previous Estimates ............... Improved Recovery ............................... Extensions and Discoveries ..................... Production ......................................... Sales of Minerals in Place ....................... Reserves at December 31, 2014 ................ 1,432 1,171 5,291 2,744 (195) (1) 19 (627) (213) 113 668 214 341 (185) Equity-accounted entities Reserves at December 31, 2013 ................ of which: developed ............................ undeveloped .................................. Purchase of Minerals in Place .................. Revisions of Previous Estimates ............... Improved Recovery ............................... Extensions and Discoveries ..................... Production ......................................... Sales of Minerals in Place ....................... Reserves at December 31, 2014 ................ 15 15 2 330 330 25 (2) (4) 351 Reserves at December 31, 2014 .................... 1,432 1,171 5,306 3,095 Developed .............................................. 1,192 887 2,125 1,360 887 2,110 1,271 consolidated subsidiaries ........................ 1,192 89 15 equity-accounted entities ........................ Undeveloped ........................................... 284 3,181 1,735 284 3,181 1,473 consolidated subsidiaries ........................ 262 equity-accounted entities ........................ 240 240 15 1,957 1,488 469 165 744 286 458 156 509 310 199 23 (73) 59 (113) 16 (80) 848 561 287 (1) (40) 2,049 846 468 807 28 14 14 (2) (8) 18 864 271 261 10 593 585 8 3,353 5 3,348 3,353 3,821 399 393 6 3,422 75 3,347 807 675 675 132 132 2,049 1,553 1,553 496 496 14,442 8,542 5,900 21 1,437 435 (1,526) (1) 14,808 3,726 34 3,692 25 (14) 3,737 18,545 8,462 8,342 120 10,083 6,466 3,617 F-150 Natural Gas(a) continued (billion cubic feet) 2015 Rest of Europe North Africa Italy Sub - Saharan Africa Kazakhstan Rest of Australia and Asia America Oceania Total Consolidated subsidiaries Reserves at December 31, 2014 ................ 1,432 1,171 5,291 2,744 887 2,110 1,271 284 3,181 1,473 of which: developed ............................ 1,192 240 undeveloped .................................. Purchase of Minerals in Place .................. Revisions of Previous Estimates ............... Improved Recovery ............................... Extensions and Discoveries ..................... (171) Production ......................................... Sales of Minerals in Place ....................... (4) Reserves at December 31, 2015 ................ 1,304 1,044 4,798 2,714 124 (780) 4 (200) (201) 145 163 68 74 Equity-accounted entities Reserves at December 31, 2014 ................ of which: developed ............................ undeveloped .................................. Purchase of Minerals in Place .................. Revisions of Previous Estimates ............... Improved Recovery ............................... Extensions and Discoveries ..................... Production ......................................... Sales of Minerals in Place ....................... Reserves at December 31, 2015 ................ 351 89 262 36 15 15 (2) 387 Reserves at December 31, 2015 .................... 1,304 1,044 4,811 3,101 Developed .............................................. 1,051 919 2,579 1,475 919 2,566 1,390 consolidated subsidiaries ........................ 1,051 85 13 equity-accounted entities ........................ Undeveloped ........................................... 125 2,232 1,626 125 2,232 1,324 consolidated subsidiaries ........................ 302 equity-accounted entities ........................ 253 253 13 2,049 1,553 496 385 846 261 585 24 468 393 75 69 807 675 132 5 (80) 114 (106) 2,354 878 (94) (4) 439 (41) 771 18 10 8 3 3,353 6 3,347 253 14,808 8,342 6,466 933 242 (1,673) (8) 14,302 3,737 120 3,617 292 (9) (25) (36) 12 890 194 185 9 696 693 3 3,581 4,020 1,668 373 1,295 2,352 66 2,286 771 585 585 186 186 3,993 18,295 10,301 8,899 1,402 7,994 5,403 2,591 2,354 1,830 1,830 524 524 2016 Rest of Europe North Africa* *Egypt (of which) Italy Sub - Saharan Africa Kazakhstan Rest of Australia and Asia America Oceania Total Consolidated subsidiaries Reserves at December 31, 2015 .. 1,304 1,044 4,798 919 2,566 125 2,232 of which: developed .............. 1,051 253 undeveloped .................... Purchase of Minerals in Place .... Revisions of Previous Estimates . Improved Recovery ................. Extensions and Discoveries ....... Production ........................... Sales of Minerals in Place ......... Reserves at December 31, 2016 .. Equity-accounted entities Reserves at December 31, 2015 .. of which: developed .............. undeveloped .................... Purchase of Minerals in Place .... Revisions of Previous Estimates . Improved Recovery ................. Extensions and Discoveries ....... Production ........................... Sales of Minerals in Place ......... Reserves at December 31, 2016 .. Reserves at December 31, 2016 ...... Developed ................................ consolidated subsidiaries .......... equity-accounted entities .......... Undeveloped ............................. consolidated subsidiaries .......... equity-accounted entities .......... 947 822 125 25 2,714 1,390 1,324 2,354 1,830 524 223 224 (155) 18 496 (172) (184) 4,767 (803) 4,767 (219) (170) (93) 878 185 693 200 15 (90) 439 373 66 771 585 186 14,302 8,899 5,403 8 12 1,026 (94) (42) 4,782 (1,648) 977 878 9,258 5,520 2,767 2,485 1,003 353 741 18,462 13 13 4 (2) 15 878 9,273 801 2,546 801 2,531 15 77 6,727 77 6,727 977 845 845 132 132 5,520 799 799 4,721 4,721 387 85 302 (8) (11) 368 3,135 1,755 1,651 104 1,380 1,116 264 12 9 3 3,581 1,295 2,286 (1) (4) 3,993 1,402 2,591 (9) (7) (93) (113) 4 1,007 284 280 4 723 723 3,484 3,837 2,120 338 1,782 1,717 15 1,702 741 559 559 182 182 3,871 22,333 11,149 9,244 1,905 11,184 9,218 1,966 2,485 2,239 2,239 246 246 (a) Values lower than 1 BCF are not disclosed in this table. F-151 Standardized measure of discounted future net cash flows Estimated future cash inflows represent the revenues that would be received from production and are determined by applying the year-end average prices during the years ended. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities — Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity. F-152 The standardized measure of discounted future net cash flows by geographical area consists of the following: (€ million) Italy Rest of Europe North Africa* *Egypt (of which) Sub - Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 121 (5,292) 4,933 17,404 4,933 17,525 485 (165) (18) 302 (23) 279 (158) December 31, 2014 Consolidated subsidiaries Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24,951 29,140 96,372 Future production costs . . . . . . . . . . . . . . . . . . . . . . . (6,374) (6,856) (19,906) Future development and abandonment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,698) (9,673) Future net inflow before income tax . . . . . . . . . . . . 13,879 16,992 66,793 Future income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,583) (10,595) (35,484) Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,296 6,397 31,309 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,064) (1,464) (13,905) Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,232 Equity-accounted entities . . . . . . . . . . . . . . . . . . . . . . Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future production costs . . . . . . . . . . . . . . . . . . . . . . . Future development and abandonment costs Future net inflow before income tax . . . . . . . . . . . . Future income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total consolidated subsidiaries and equity-accounted entities . . . . . . . . . . . . . . . . . . . . . . . 6,232 December 31, 2015 Consolidated subsidiaries Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,760 18,692 58,390 (5,554) (13,481) Future production costs . . . . . . . . . . . . . . . . . . . . . . . (4,995) (4,379) Future development and abandonment costs (9,457) (4,299) Future net inflow before income tax . . . . . . . . . . . . 7,466 8,759 35,452 (4,349) (17,195) Future income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,657) Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,809 4,410 18,257 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,077) (7,844) (817) Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,732 Equity-accounted entities Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future production costs . . . . . . . . . . . . . . . . . . . . . . . Future development and abandonment costs Future net inflow before income tax . . . . . . . . . . . . Future income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total consolidated subsidiaries and equity-accounted entities . . . . . . . . . . . . . . . . . . . . . . . 3,732 December 31, 2016 Consolidated subsidiaries Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,627 12,898 64,371 (5,240) (15,408) Future production costs . . . . . . . . . . . . . . . . . . . . . . . (4,136) (3,575) (12,885) Future development and abandonment costs (3,641) Future net inflow before income tax . . . . . . . . . . . . 1,850 4,083 36,078 (1,308) (15,194) Future income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (237) Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,613 2,775 20,884 (365) (12,115) (241) 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,372 Equity-accounted entities Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future production costs . . . . . . . . . . . . . . . . . . . . . . . Future development and abandonment costs Future net inflow before income tax . . . . . . . . . . . . Future income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 10% discount factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total consolidated subsidiaries and equity-accounted entities . . . . . . . . . . . . . . . . . . . . . . . 1,372 313 (177) (5) 131 (8) 123 (70) 259 (143) (1) 115 (21) 94 (46) 3,593 10,466 3,593 10,413 2,410 8,769 2,410 8,817 53 48 65,853 (18,236) 55,740 (9,878) 13,664 10,955 (4,158) (2,680) 4,849 301,524 (69,180) (1,092) (9,139) 38,478 (20,514) 17,964 (7,164) (4,576) 41,286 (10,400) 30,886 (19,699) (4,600) (1,892) 4,906 6,383 (1,462) (2,401) 3,444 3,982 (1,900) (1,353) (356) (40,226) 3,401 192,118 (85,428) (989) 2,412 106,690 (50,655) (1,106) 10,800 11,187 1,544 2,629 1,306 56,035 3,861 (692) (104) 3,065 (426) 2,639 (1,442) 1,197 200 18,871 (33) (5,724) (51) (2,032) 116 11,115 (45) (4,608) 71 6,507 (11) (4,327) 60 2,180 23,417 (6,614) (2,205) 14,598 (5,102) 9,496 (5,938) 3,558 11,997 11,187 1,604 4,809 1,306 59,593 44,114 (14,645) (9,359) 20,110 (8,222) 11,888 (4,976) 34,589 (8,846) (4,108) 21,635 (4,682) 16,953 (10,561) 13,027 8,101 (4,585) (3,091) (4,964) (1,644) 3,366 3,478 (933) (1,230) 2,433 2,248 (970) (1,276) 3,519 197,192 (56,001) (804) (218) (38,428) 2,497 102,763 (38,872) (604) 63,891 1,893 (29,422) (901) 6,912 6,392 972 1,463 992 34,469 3,047 (1,021) (95) 1,931 (251) 1,680 (1,016) 664 85 18,519 (32) (5,370) (22) (2,118) 31 11,031 (10) (4,088) 21 6,943 (2) (4,358) 19 2,585 21,964 (6,600) (2,240) 13,124 (4,357) 8,767 (5,446) 3,321 7,576 6,392 991 4,048 992 37,790 38,271 33,524 (7,927) (13,913) (9,392) (6,981) 14,966 18,616 (4,525) (5,941) 10,441 12,675 (4,594) (8,055) 26,903 (9,247) (3,268) 14,388 (2,596) 11,792 (6,536) 5,789 12,263 (3,498) (2,935) (5,047) (1,313) 1,541 3,718 (298) (953) 1,243 2,765 (501) (1,266) 2,815 172,937 (55,035) (658) (39,391) (270) 78,511 1,887 (25,452) (341) 53,059 1,546 (26,342) (724) 4,620 5,847 5,256 1,499 742 822 26,717 2,429 (974) (64) 1,391 (115) 1,276 (734) 542 33 16,430 (20) (4,614) (1,186) 13 10,630 (4) (3,667) 6,963 9 (4,441) 9 2,522 19,151 (5,751) (1,251) 12,149 (3,807) 8,342 (5,221) 3,121 4,620 6,389 5,256 1,508 3,264 822 29,838 F-153 Changes in standardized measure of discounted future net cash flows Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2014, 2015 and 2016, are as follows: (€ million) Standardized measure of discounted future net cash flows at December 31, 2013 ............................................................ Increase (Decrease): - sales, net of production costs ............................................. - net changes in sales and transfer prices, net of production costs .. - extensions, discoveries and improved recovery, net of future production and development costs ........................................ - changes in estimated future development and abandonment costs - development costs incurred during the period that reduced future development costs ............................................................ - revisions of quantity estimates ........................................... - accretion of discount ....................................................... - net change in income taxes ................................................ - purchase of reserves in-place ............................................. - sale of reserves in-place .................................................... - changes in production rates (timing) and other ....................... Net increase (decrease) ....................................................... Standardized measure of discounted future net cash flows at December 31, 2014 ............................................................ Increase (Decrease): - sales, net of production costs ............................................. - net changes in sales and transfer prices, net of production costs .. - extensions, discoveries and improved recovery, net of future production and development costs ........................................ - changes in estimated future development and abandonment costs - development costs incurred during the period that reduced future development costs ............................................................ - revisions of quantity estimates ........................................... - accretion of discount ....................................................... - net change in income taxes ................................................ - purchase of reserves in-place ............................................. - sale of reserves in-place .................................................... - changes in production rates (timing) and other ....................... Net increase (decrease) ....................................................... Standardized measure of discounted future net cash flows at December 31, 2015 ............................................................ Increase (Decrease): - sales, net of production costs ............................................. - net changes in sales and transfer prices, net of production costs .. - extensions, discoveries and improved recovery, net of future production and development costs ........................................ - changes in estimated future development and abandonment costs - development costs incurred during the period that reduced future development costs ............................................................ - revisions of quantity estimates ........................................... - accretion of discount ....................................................... - net change in income taxes ................................................ - purchase of reserves in-place ............................................. - sale of reserves in-place .................................................... - changes in production rates (timing) and other ....................... Net increase (decrease) ....................................................... Standardized measure of discounted future net cash flows at December 31, 2016 ............................................................ Consolidated subsidiaries Equity- accounted entities Total 56,177 2,327 58,504 (21,795) (12,053) 1,667 (6,047) 8,745 8,085 11,064 7,049 67 (271) 3,347 (142) 56,035 (14,846) (70,909) 524 (1,711) 8,960 12,322 11,288 29,530 (114) 3,390 (21,566) 34,469 (11,222) (24,727) 4,563 (2,357) 7,578 2,840 5,705 9,200 668 (7,752) 26,717 (192) (500) 223 451 (325) 512 704 358 1,231 3,558 (179) (2,858) (241) 604 915 629 530 363 (237) 3,321 (347) (1,586) 650 151 (131) 514 386 163 (200) 3,121 (21,987) (12,553) 1,667 (5,824) 9,196 7,760 11,576 7,753 67 (271) 3,705 1,089 59,593 (15,025) (73,767) 524 (1,952) 9,564 13,237 11,917 30,060 (114) 3,753 (21,803) 37,790 (11,569) (26,313) 4,563 (1,707) 7,729 2,709 6,219 9,586 831 (7,952) 29,838 F-154 SIGNATURES The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. Date: March 22, 2017 Eni SpA /s/ ANDREA SIMONI Andrea Simoni Title: Executive Vice President Accounting and Financial Statements Department F-155 EXHIBIT 1 By-laws of Eni SpA1 November 2014 Part I – Formation – Name – Registered Office and Duration of the Company ARTICLE 1 1.1 1.2 2.2 ARTICLE 2 2.1 Eni SpA, formed as a result of the transformation of Ente Nazionale Idrocarburi, a public agency, pursuant to Law No. 136 of February 10, 1953, is governed by these By-laws. The first letter of the Company’s name may be written in either upper or lower case. The Company’s registered office is located in Rome, and it has two branch offices in San Donato Milanese (Milan). The Company may establish and/or close offices, representative offices, affiliates and branch offices either in Italy or abroad, in the manner provided for by law. ARTICLE 3 3.1 The duration of the Company shall expire on December 31, 2100. Its duration may be extended one or more times by resolution of the Shareholders’ Meeting. Part II – Corporate Purpose ARTICLE 4 4.1 The corporate purpose is the direct and/or indirect exercise, through equity holdings in companies or other entities of activities in the field of hydrocarbons and natural gases, such as exploration and development of hydrocarbon fields, the construction and operation of pipelines for transporting the same, the processing, transformation, storage, use and sale of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law. The corporate purpose also includes the direct and/or indirect exercise, through equity holdings in companies or other enterprises, of activities in the fields of chemicals, nuclear fuels, geothermal energy, other renewable energy sources and energy in general, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the afore mentioned activities. The corporate purpose also comprises performing and managing the technical and financial coordination of subsidiaries and associated companies and providing financial assistance to them. The Company may undertake any transactions necessary or useful for the achievement of the corporate purpose; by way of example, it may undertake transactions involving real estate or moveable assets, commercial and industrial transactions, financial and banking transactions of any sort, and any other act that is in any way connected with the corporate purpose with the exception of investment services as defined by Legislative Decree No. 58 of February 24, 1998. The Company may, finally, acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties. fundraising on a public basis and the performance of Part III – Share capital – Shares – Bonds ARTICLE 5 5.1 The Company’s share capital is equal to euro 4,005,358,876.00 (four billion five million three hundred and fifty-eight thousand eight hundred and seventy-six), represented by 3,634,185,330 (three billion six hundred and thirty four million one hundred and eighty-five thousand three hundred and thirty) ordinary shares without indication of par value. Shares may not be split and each share gives entitlement to one vote. The status of shareholder in itself constitutes approval of these By-laws. 5.2 5.3 ARTICLE 6 6.1 Pursuant to Article 3 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994, no shareholder may hold, in any capacity, more than 3% of the Company’s share capital. (1) The English text is a translation of the Italian official “By-laws of Eni SpA”. For any conflict or discrepancies between the two texts the Italian text shall prevail. E-1 The calculation of such maximum shareholding limit also takes account of the aggregate shareholding held by the controlling party, whether a natural or legal person or company; subsidiaries under direct or indirect control, as well as entities controlled by the same controlling party; linked entities and persons related to the second degree by blood or marriage, with the exception of legally separated spouses. A relationship of control, including with reference to entities other than companies, exists in the cases envisaged by Article 2359, paragraphs 1 and 2 of the Italian Civil Code. A link exists in the case set forth in Article 2359, paragraph 3, of the Italian Civil Code, as well as between entities that directly or indirectly, by way of subsidiaries other than those managing investment funds, participate, even with third parties, in agreements regarding the exercise of voting rights or the transfer of shares or other equity holdings in third-party companies or, in any event, in agreements as referred to in Article 122 of Legislative Decree No. 58 of February 24, 1998 regarding third-party companies if said agreements involve least 10% of voting share capital if they are listed companies or 20% if they are unlisted companies. The calculation of the afore mentioned shareholding limit (3%) also takes account of shares held by any fiduciary and/or nominee. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved. If the voting rights of shares exceeding this limit are exercised, any Shareholders’ resolution adopted pursuant to such a vote may be challenged pursuant to Article 2377 of the Italian Civil Code if the required majority would not have been reached without the votes exceeding the afore mentioned maximum limit. Shares for which voting rights may not be exercised shall nevertheless be included in the determination of the quorum at Shareholders’ Meetings. ARTICLE 7 7.1 When shares are fully paid up, and if the law so allows, they may be issued to bearer. Bearer shares may be converted into registered shares and vice-versa. Conversion operations shall be carried out at the shareholder’s expense. ARTICLE 8 8.1 If for whatever reason a share should belong to more than one person, the rights attaching to said share may be exercised by only one person or by a proxy acting for all co-holders. ARTICLE 9 9.1 9.2 The Shareholders’ Meeting may resolve to increase the Company share capital and set the terms, conditions and means thereof. The Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration pursuant to Article 2349 of the Italian Civil Code. ARTICLE 10 10.1 10.2 Payments in respect of shares may be called by the Board of Directors in one or more installments. Shareholders who are late in payment shall be charged interest calculated at the official discount rate established by the Bank of Italy, without prejudice to the provisions of Article 2344 of the Italian Civil Code. ARTICLE 11 11.1 The Company may issue bonds, including convertible bonds and warrants, in compliance with the provisions of law. Part IV – Shareholders’ Meetings ARTICLE 12 12.1 Ordinary and extraordinary Shareholders’ Meetings shall normally be held at the Company’s registered office unless otherwise decided by the Board of Directors, provided however they are held in Italy. 12.2 The ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year, to approve the financial statements, since the Company is required to draw up consolidated financial statements. 12.3 The directors shall call a Shareholders’ Meeting without delay when shareholders representing at least one twentieth of the share capital so request. Shareholders’ Meetings may not be called upon the request of the shareholders for matters upon which, according to law, the Shareholders’ Meeting must resolve upon a proposal of the directors or on the basis of a project or report of the directors themselves. The shareholders who request a meeting to be convened shall prepare a report on the E-2 proposals relating to the matters to be discussed. The Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the Company’s registered office, on the Company’s website and in any other manner established in Consob regulations at the time the notice calling the meeting is published. 12.4 The Board of Directors shall make a report on each of the items on the agenda available to the public as provided for in the previous paragraph by the deadlines for publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda. ARTICLE 13 13.1 The Shareholders’ Meeting shall be called by way of a notice published on the Company’s website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. Shareholders who severally or jointly represent at least one fortieth of the Company’s share capital may ask for items to be added to the agenda by submitting a request within ten days of publication of the notice calling the meeting, unless a different term is provided for by law, specifying the additional proposed items in their request or presenting proposed resolutions on items already on the agenda. Requests, together with the certificate attesting ownership of the shares, are submitted in writing, by mail or electronically in the manners provided for in the notice calling the meeting. These proposed resolutions may be presented individually at the Shareholders’ Meeting by persons entitled to vote. Matters upon which, according to law, the Shareholders’ Meeting must resolve upon a proposal of the Board of Directors or on the basis of a project or report of the directors other than the report on the items in the agenda, may not be added to the agenda. The Board of Directors shall give notice of the additions to the agenda or the proposed resolutions approved in the same manner prescribed for the publication of the notice calling the meeting at least fifteen days before the date set for the Shareholders’ Meeting, unless a different term is required by law. The proposed resolutions on items already on the agenda are made available to the public as prescribed by Article 12.3 of these By-laws, simultaneous with publication of the announcement of their presentation. The requesting or proposing shareholders shall send, by the final deadline for the submission of requests for additions to the agenda or of proposed resolutions, a report to the Board of Directors, explaining the reasons for the addition or the proposed resolution. The Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the same time as the publication of the notice of the additions to the agenda or of the presentation of proposed resolutions in the manner set out in Article 12.3 of these By-laws. 13.2 Entitlement to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit or debit records entered on the accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement issued by the authorized intermediary must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of this Article, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the meeting; otherwise, the date of each call is deemed the reference date. ARTICLE 14 14.1 Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current laws. Electronic notification of the proxy may be made through a special section of the Company’s website as indicated in the notice calling the meeting. In order to simplify proxy voting by shareholders who are employees of its subsidiaries and belong to shareholders associations that meet applicable statutory requirements, locations for communications and collecting proxies shall be made available to said associations in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations. the Company or of 14.2 The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the meeting. 14.3 The right to vote may also be exercised by correspondence in accordance with the applicable provisions of law and regulations. If envisaged in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of law, applicable regulations and the Shareholders’ Meeting Rules. 14.4 The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved with a resolution of the ordinary Shareholders’ Meeting. 14.5 The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided E-3 for by law and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided. ARTICLE 15 15.1 The Shareholders’ Meeting is chaired by the Chairman of the Board of Directors, or in the event of in their absence, the the Chairman’s absence or impediment, by the Chief Executive Officer; Shareholders’ Meeting shall elect its own Chairman. 15.2 The Chairman of the meeting is assisted by a Secretary, who need not be a shareholder, to be designated by the participants in the meeting, and may appoint one or more scrutineers. ARTICLE 16 16.1 The ordinary Shareholders’ Meeting decides on all matters for which it is legally responsible and authorizes the transfer of the business. 16.2 The ordinary and extraordinary Shareholders’ Meetings, are normally held on single call; in such case the majorities required by law shall apply. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after more than one call; their resolutions in first, second or third call must be passed with the majorities required by law in each case. 16.3 The resolutions of the Shareholders’ Meeting, approved in accordance with the law and these By-laws, shall be binding on all shareholders, including those dissenting or not present. 16.4 The minutes of ordinary meetings shall be signed by the Chairman and the Secretary. 16.5 The minutes of extraordinary meetings shall be drawn up by a notary public. Part V – The Board of Directors ARTICLE 17 17.1 The Company is governed by a Board of Directors consisting of no fewer than three and no more than nine members. The Shareholders’ Meeting shall determine the number within these limits. 17.2 The directors shall be appointed for a period of up to three financial years; this term shall lapse on the date of the Shareholders’ Meeting convened to approve the financial statements for their last year in office. They may be re-elected. 17.3 The Board of Directors shall be elected by the Shareholders’ Meeting on the basis of slates presented by shareholders and by the Board of Directors. The candidates shall be listed on the slates in numerical order. The slates shall be filed with the Company’s registered office, including remotely in the manner indicated in the notice calling the meeting, by the twenty-fifth day before the date of the Shareholders’ Meeting at first or single call convened to appoint the members of the Board of Directors. They shall be made available to the public as provided for by law and Consob regulations at least twenty-one days before the date set for the Shareholders’ Meeting at first or single call. Each shareholder may, severally or jointly, submit and vote on a single slate only. Controlling persons, subsidiaries and companies under common control may not submit or participate in the submission of other slates, nor can they vote on them, either directly or through nominees or trustees. As used herein, subsidiaries are those companies referred to in Article 93 of Legislative Decree No. 58 of February 24, 1998. Each candidate may stand on a single slate, on penalty of disqualification. Only those shareholders who, severally or jointly, represent at least 1% of share capital or any other threshold established by Consob regulations shall be entitled to submit a slate. Ownership of the minimum holding needed to submit slates shall be determined with regard to the shares registered to the shareholder on the day on which the slates are filed with the Company. Related certification may be submitted after the filing, provided that submission takes place by the deadline set for the publication of the slates by the Company. At least one director, if there are no more than five directors, or at least three directors, if there are more than five, shall satisfy the independence requirements established for the members of the board of statutory auditors of listed companies. The candidates meeting such independence requirements shall be expressly identified in each slate. All candidates shall also satisfy the integrity requirements established by applicable law. Slates that contain three or more candidates shall include candidates of both genders, as specified in the notice calling the meeting, in order to comply with the applicable gender-balance legislation. When the number of members of the less-represented gender must, by law, be at least three, the slates competing to appoint the majority of the members of the Board of Directors must include at least two candidates of the less-represented gender. Together with the filing of each slate, on penalty of inadmissibility, the following shall also be filed: the curriculum vitae of each candidate, statements of each candidate accepting his/her nomination and affirming, under his/her personal responsibility, the absence of any grounds making him/her ineligible or incompatible for such position and that he/she satisfies the afore mentioned requirements of integrity and independence (where applicable). The appointed directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise. The Board of Directors shall periodically evaluate the independence and integrity of its members and whether cause for ineligibility or incompatibility has arisen. If the integrity or independence E-4 requirements established by applicable legislation should no longer be met by a director or if cause for ineligibility or incompatibility should have arisen, the Board of Directors shall declare the director disqualified and replace him/her or shall invite him/her to rectify the situation of incompatibility by a deadline set by the Board itself, on penalty of disqualification. Directors shall be elected in the following manner: a) b) c) c-bis) d) these candidates; seven-tenths of the directors to be elected shall be drawn from the slate that receives the most votes of the shareholders in the order in which they appear on the slate, rounded off in the event of a decimal number to the next lowest whole number; the remaining directors shall be drawn from the other slates. Said slates shall not be connected in any way, directly or indirectly, to the shareholders who have submitted or voted the slate that receives the largest number of votes. For this purpose, the votes received by each slate shall be divided by one or two or three depending upon the number of directors to be elected. The quotients, or points, thus obtained shall be assigned progressively to candidates of each slate in the order given in the slates themselves. The candidates of all the slates shall be ranked by the points assigned in single list in descending order. Those who receive the most points shall be elected. In the event that more than one candidate receives the same number of points, the candidate elected shall be the person from the slate that has not hitherto had a director elected or that has elected the least number of directors. In the event that none of the slates has yet had a director elected or that all of them have had the same number of directors elected, the candidate among all such slates who has received the highest number of votes shall be elected. In the event of equal slate votes and equal points, the entire Shareholders’ Meeting shall vote again and the candidate elected shall be the person who receives a simple majority of the votes; if the minimum number of independent directors required under these By-laws has not been elected following the above procedure, the points to be assigned to the candidates draw from the slates shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of the requirements of independence with the fewest points from among the candidates drawn from all of the slates shall be replaced, starting from the last, by the independent candidates, from the same slate as the replaced candidate (following the order in which they are listed), otherwise by persons meeting the independence requirements appointed in accordance with the procedure set out in letter d). In cases where candidates from different lists have received the same number of points, the candidate from the slate from which the largest number of directors has been drawn or, subordinately, the candidate drawn from the slate receiving the lowest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders’ Meeting in a run-off election, shall be replaced; if the application of the procedure set out in letters a) and b) does not permit compliance with the gender-balance rules, the points to attribute to each candidate drawn from the slate shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidate of the over-represented gender with the fewest points from among the candidates drawn from all of the slates shall be replaced, without prejudice to the compliance with the required minimum number of independent directors, by the member of the less-represented gender who may be listed (with the next highest ordinal number) on the same slate as the candidate to be replaced, otherwise by a person to be appointed following the procedure set out in letter d). In cases where candidates from different lists have received the same minimum number of points, the candidate from the slate from which the largest number of directors has been drawn or, subordinately, the candidate drawn from the slate receiving the fewest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders’ Meeting in a run-off election, shall be replaced; and to appoint directors who for any reason were not appointed pursuant to the above procedures, the Shareholders’ Meeting shall resolve, with the majorities required by law, to ensure that the composition of the Board of Directors complies with applicable law and the By-laws. the candidates who do not meet The slate voting procedure shall apply only to the election of the entire Board of Directors. 17.5 17.4 The Shareholders’ Meeting may, during the Board’s term of office, change the number of members of the Board of Directors, within the limits established in the first paragraph of this Article, and make the related appointments. The terms of directors so elected shall expire at the same time as those of the directors already in office. If, during the year, the office of one or more directors should be vacated, he/she shall be replaced in accordance with Article 2386 of the Italian Civil Code. In any case, compliance with the required minimum number of independent directors and the applicable rules concerning gender-balance shall not be affected. If a majority of the directors should vacate their offices, the entire Board shall be considered to have resigned, and the Board shall promptly call a Shareholders’ Meeting to elect a new Board. 17.6 The Board may establish internal committees to provide advice and proposals on specific issues. ARTICLE 18 18.1 If the Shareholders’ Meeting has not appointed a Chairman, the Board shall elect one from among its members. E-5 18.2 The Board, acting upon a proposal of the Chairman, shall appoint a Secretary, who need not be affiliated with the Company. ARTICLE 19 19.1 The Board shall meet in the place indicated in the meeting notice whenever the Chairman or, in the event of his absence or impediment, the Chief Executive Officer deems necessary, or when a written request has been made by the majority of its members. The Board of Directors may also be convened pursuant to Article 28.4 of these By-laws. The meetings of the Board of Directors may be held by video or teleconference on the condition that all of the participants in the meeting can be identified and that all can follow and participate in real time in the discussion of the matters being addressed. The meeting shall be considered duly held in the place where the Chairman and the Secretary are present. 19.2 Notice shall normally be given at least five days in advance of the meeting. In urgent circumstances, the period of notice may be shorter. The Board of Directors shall decide how its meetings are to be convened. 19.3 The Board of Directors shall also be convened when so requested by at least two directors or by one director if the Board consists of three directors, to decide on a specific matter deemed to be of particular importance regarding the management of the Company. Said matter shall be specified in the request. ARTICLE 20 20.1 The Chairman of the Board or, in his absence, the eldest director in attendance shall chair the meeting. ARTICLE 21 21.1 For a Board meeting to be valid, a majority of serving directors must be present. 21.2 Resolutions shall be approved by a majority of the votes of the directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote. ARTICLE 22 22.1 The resolutions of the Board of Directors shall be registered in the minutes, which shall be recorded in a book kept for that purpose pursuant to the provisions of law, and said minutes shall signed by the Chairman of the meeting and by the Secretary. 22.2 Copies of the minutes shall be considered bona fide if they are signed by the Chairman or the person acting in place of the Chairman and countersigned by the Secretary. ARTICLE 23 23.1 The Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or these By-laws reserve to the Shareholders’ Meeting. 23.2 The Board of Directors shall decide the following matters: - - - the merger and proportional demerger of companies in which the Company owns shares or other equity holdings representing at least 90% of the share capital; the establishment and closing of branches; and the amendment of the By-laws to comply with the provisions of law. 23.3 The Board of Directors and the Chief Executive Officer shall promptly report to the Board of Statutory Auditors at least every three months and in any event at the time of the meetings of the Board of Directors, on the activity carried out and on the transactions with the most significant impact on performance and the financial position carried out by the Company and its subsidiaries. In particular, they shall report to the Board of Statutory Auditors those transactions in which they have an interest, either on their own behalf or on behalf of third parties. ARTICLE 24 24.1 The Board of Directors may delegate its powers to one of its members, within the limits set forth in Article 2381 of the Italian Civil Code. The Board may, in addition, delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may revoke delegated powers at any time, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors. The Chairman and the Chief Executive Officer, within the limits of the authority attributed to them, may delegate and empower Company employees or third parties to represent the Company for individual acts or specific categories of acts. Further, acting upon proposal of the Chief Executive Officer and in agreement with the Chairman, the Board of Directors may also appoint one or more General Managers (Chief Operating Officers) and determine the powers to be conferred on them, once it has been ascertained that they fulfill the E-6 integrity requirements set by law. The Board of Directors shall periodically check the continuing compliance with integrity requirements of the General Managers (Chief Operating Officers). Failure to satisfy these requirements shall result in disqualification from the position. Acting upon a proposal of the Chief Executive Officer, in agreement with the Chairman and with the approval of the Board of Statutory Auditors, the Board of Directors shall appoint the Officer responsible for preparing financial reporting documents. The Officer responsible for preparing financial reporting documents shall be selected from among those persons who, for at least three years, have performed: a) administration, control or management activities in companies listed on regulated Stock Exchanges in Italy or other European Union countries or other OECD countries with a share capital of no less than euro 2 million; or b) statutory audit activities in companies indicated in letter a) above; or c) professional activities or university teaching activities in the financial or accounting sectors; or d) management functions in public or private entities with financial, accounting or control expertise. The Board of Directors shall ensure that the Officer responsible for preparing the financial reporting documents has adequate powers and means to perform the duties of the position and that administrative and accounting procedures are being followed. ARTICLE 25 25.1 The Chairman and the Chief Executive Officer are severally vested with powers of legal representation of the Company before any judicial or administrative authority and with respect to third parties and exercise signature powers on behalf of the Company. ARTICLE 26 26.1 The Chairman and the members of the Board of Directors shall be entitled to compensation to be determined by the ordinary Shareholders’ Meeting. Said resolution, once taken, shall remain valid for subsequent financial years until the Shareholders’ Meeting should decide otherwise. ARTICLE 27 27.1 The Chairman: a) represents the Company pursuant to Article 25.1; b) chairs the Shareholders’ Meeting pursuant to Article 15.1; c) calls and chairs meetings of the Board of Directors pursuant to Articles 19.1 and 20.1; d) verifies that Board resolutions are implemented; and e) exercises the powers delegated to him by the Board of Directors pursuant to Article 24.1. Part VI – The Board of Statutory Auditors ARTICLE 28 28.1 The Board of Statutory Auditors shall consist of five standing members and two alternate members, chosen from among persons who satisfy the professional and integrity requirements established by the Ministry of Justice Decree No. 162 of March 30, 2000. Pursuant to the afore mentioned decree, the fields closely connected with the business of the Company are: commercial law, business economics and corporate finance. Similarly, the sectors closely connected with the business of the Company are engineering and geology. The Statutory Auditors may be appointed as members of the administrative and control bodies of other companies within the limits set by Consob regulations. 28.2 The Board of Statutory Auditors shall be appointed by the Shareholders’ Meeting on the basis of slates presented by shareholders. The candidates shall be listed on the slates in numerical order in a number no greater than the number of members of the body to be appointed. The procedures set out in Article 17.3 and the provisions issued in Consob regulations shall apply to the submission, filing and publication of candidate slates. Slates shall be divided into two sections: the first containing candidates for appointment as standing Statutory Auditors and the second containing candidates for appointment as alternate Statutory Auditors. At least the first candidate in each section must be entered in the register of auditors and have carried out statutory audit activities for no less than three years. Slates that, considering both sections together, contain three or more candidates shall include, in the section for standing Statutory Auditors, candidates of both genders, as specified in the notice calling the Shareholders’ Meeting, in order to comply with the applicable gender-balance legislation. If the section for alternate Statutory Auditors on these slates contains two candidates, they must be of different genders. When the number of members of the less-represented gender must, by law, be at least one, such requirement shall apply only to slates competing to appoint the majority of the members of the Board of Statutory Auditors. Three standing Statutory Auditors and one alternate Statutory Auditor shall be drawn from the slate that receives the majority of votes. The other two standing Statutory Auditors and the other alternate Statutory Auditor shall be appointed using the procedures set out in Article 17.3, letter b) of the By-laws. Said procedures shall be applied separately to each section of the other slates. E-7 The Shareholders’ Meeting shall appoint the Chairman of the Board of Statutory Auditors from among the standing Statutory Auditors appointed in accordance with Article 17.3, letter b) of these By-laws. Where the application of the procedure set out above does not permit compliance with the gender-balance rules for standing Statutory Auditors, the points to attribute to each candidate drawn from the standing Statutory Auditor sections of the various slates shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidate of the over-represented gender with the fewest points from among the candidates drawn from all of the slates shall be replaced by the member of the less-represented gender who may be listed (with the next highest ordinal number) in the standing Statutory Auditor section on the same slate as the candidate to be replaced or, subordinately, in the alternate Statutory Auditor section of the same slate as the candidate to be replaced (in such case, the latter shall take the position of the alternate candidate that replaces him/her). If this does not permit compliance with the gender-balance rules, he/she shall be replaced by a person chosen by the Shareholders’ Meeting with the majority required by law, so as to ensure that the membership of the Board of Statutory Auditors complies with the law and the By-laws. In cases where candidates from different lists have received the same number of points, the candidate from the slate from which the largest number of Statutory Auditors has been drawn or, subordinately, the candidate drawn from the slate receiving the fewest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders’ Meeting in a run-off election, shall be replaced. For the appointment of Statutory Auditors who, for any reason, are not appointed using the above procedures, the Shareholders’ Meeting shall resolve, with the majorities required by law, in such a manner as to ensure that the membership of the Board of Statutory Auditors complies with the law and the By-laws. The slate voting procedure shall apply only in case of appointment of the entire Board of Statutory Auditors. Should a standing Statutory Auditor from the slate that received a majority of the votes be replaced, the replacement shall be the alternate Statutory Auditor from the same slate; should a standing Statutory Auditor from other slates be replaced, the replacement shall be the alternate Statutory Auditor from those other slates. If the replacement results in non-compliance with gender-balance rules, the Shareholders’ Meeting shall be called as soon as possible to approve the necessary resolutions to ensure compliance. Statutory Auditors may be re-elected. Subject to prior notification of the Chairman of the Board of Directors, the Board of Statutory Auditors may call Shareholders’ Meetings and meetings of the Board of Directors. The power to call a meeting of the Board of Directors may be exercised individually by each member of the Board of Statutory Auditors; at least two Statutory Auditors are required to call Shareholders’ Meetings. The meetings of the Board of Statutory Auditors may be held by video or teleconference on the condition that all of the participants in the meetings can be identified and that all can follow and participate in real time in the discussion of the matters being addressed. The meeting shall be considered duly held in the place where the Chairman and the Secretary are present. 28.3 28.4 Part VII – Financial Statements and Profits ARTICLE 29 29.1 The Company’s financial year ends on December 31 of each year. 29.2 At the end of each financial year, the Board of Directors shall prepare the Company financial statements in compliance with the provisions of law. 29.3 The Board of Directors may distribute interim dividends to the shareholders during the financial year. ARTICLE 30 30.1 Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves. Part VIII – Winding Up and Liquidation of the Company ARTICLE 31 31.1 In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. Part IX – General Provisions ARTICLE 32 32.1 For all matters not expressly governed by these By-laws, the Italian Civil Code and applicable special laws shall apply. E-8 32.2 Pursuant to Article 3, paragraph 2, of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994, Article 6.1, sixth paragraph, of these By-laws shall not apply to the shareholdings owned by the Ministry of the Economy and Finance, public entities or entities they control. ARTICLE 33 33.1 The Company retains all legal relationships in respect of assets and liabilities held by the public agency Ente Nazionale Idrocarburi before its transformation. ARTICLE 34 34.1 The provisions of Articles 17.3, 17.5 and 28.2 directed to ensure compliance with applicable gender-balance legislation shall apply to the first three elections of the Board of Directors and Board of Statutory Auditors after August 12, 2012. E-9 EXHIBIT 8 See “Item 18 – note 48 – Other information about investments – Information on Eni’s investments as of December 31, 2016 – of the Notes on Consolidated Financial Statements”. E-10 Approved by the Board of Directors of Eni spa on October 27, 2016 Code of Ethics INDEX Exhibit 11 Eni’s Code of Ethics INTRODUCTION I. GENERAL PRINCIPLES: SUSTAINABILITY AND CORPORATE RESPONSIBILITY II. BEHAVIOUR RULES AND RELATIONS WITH STAKEHOLDERS 1. Ethics, transparency, fairness, professionalism 2. Relations with shareholders and with the Market 2.1. Value for shareholders, efficiency, transparency 2.2. Self-Regulatory Code 2.3. Company information 2.4. Privileged information 2.5. Information means 3. Relations with institutions, associations, local communities 3.1 Authorities and Public Institutions 3.2 Political organizations and trade unions 3.3 Development of local communities 3.4 Promotion of “non profit” activities 4. Relations with customers and suppliers 4.1. Customers and consumers 4.2. Suppliers and external collaborators 5. The management, employees and collaborators of eni 5.1. Development and protection of Human Resources 5.2. Knowledge Management 5.3. Corporate security 5.4. Harassment or mobbing in the workplace 5.5. Abuse of alcohol or drugs and no smoking III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS 1. Internal Control and Risk Management System 1.1 Conflicts of interest 1.2 Transparency of accounting records 2. Health, safety, environment and public safety protection 3. Research, innovation and intellectual property protection 4. Confidentiality 4.1. Protection of business secret 4.2. Protection of privacy 4.3. Membership in associations, participation in initiatives, events or external meetings IV. CODE OF ETHICS SCOPE OF APPLICATION AND REFERENCE STRUCTURES 1. Obligation to know the Code and to report any possible violation thereof 2. Reference structures and supervision 2.1. Guarantor of the Code of Ethics 2.2. Promotion and diffusion of the Code of Ethics 3. Code review 4. Contractual value of the Code E-11 Eni’s Code of Ethics INTRODUCTION Eni1 is an internationally oriented industrial group which, because of its size and the importance of its activities, plays a significant role in the marketplace and in the economic development and welfare of the individuals who work or collaborate with Eni and of the communities where it is present. The complexity of the situations in which Eni operates, the challenges of sustainable development and the need to take into consideration the interests of all people having a legitimate interest in the corporate business (“Stakeholders”), strengthen the importance to clearly define the values that Eni accepts, acknowledges and shares as well as the responsibilities it assumes, contributing to a better future for everybody. For this reason the new Eni’s Code of Ethics (“Code” or “Code of Ethics”) has been devised. Compliance with the Code by Eni’s directors, statutory auditors, management and employees as well as by all those who operate in Italy and abroad for achieving Eni’s objectives (“Eni’s People”), each within their own functions and responsibilities, is of paramount importance – also pursuant to legal and contractual provisions governing the relationship with Eni – for Eni’s efficiency, reliability and reputation, which are all crucial factors for its success and for improving the social situation in which Eni operates. Eni undertakes to promote awareness of the Code among Eni’s People and the other Stakeholders and their constructive contribution to its principles Eni undertakes to take into account any suggestions and observations by the Stakeholders, with the aim of confirming or supplementing the Code. Eni carefully checks for compliance with the Code by providing suitable information, prevention and control tools and ensuring transparency in all transactions and behaviours by taking corrective measures if and as required. The Watch Structure of each Eni company performs the functions of guarantor of the Code of Ethics (“Guarantor”). The Code is brought to the attention of every person or body having business relations with Eni. (1) “Eni” means Eni spa and its direct and indirect subsidiaries, in Italy and abroad. E-12 I. GENERAL PRINCIPLES: SUSTAINABILITY AND CORPORATE RESPONSIBILITY Compliance with the law, regulations, statutory provisions, self-regulatory codes, ethical integrity and fairness, is a constant commitment and duty of all Eni’s People, and characterizes the conduct of its entire organization. Eni’s business and corporate activities have to be carried out in a transparent, honest and fair way, in good faith, and in full compliance with competition protection rules. Eni undertakes to maintain and strengthen a governance system in line with international best practice standards, able to deal with the complex situations in which Eni operates, and with the challenges to face for sustainable development. Systematic methods for involving Stakeholders are adopted, fostering dialogue on sustainability and corporate responsibility. In conducting both its activities as an international company and those with its partners, Eni stands up for the protection and promotion of human rights, inalienable and fundamental prerogatives of human beings and basis for the establishment of societies founded on principles of equality, solidarity, repudiation of war, and for the protection of civil and political rights, of social, economic and cultural rights and the so-called third generation rights (self-determination right, right to peace, right to development and protection of the environment). Any form of discrimination, corruption, forced or child labor is rejected. Particular attention is paid to the dignity, freedom and equality of human beings, to the acknowledgement and safeguarding of protection of labor and of the freedom of trade union association, of health, safety, the environment and biodiversity, as well as the set of values and principles concerning transparency, energy efficiency and sustainable development, in accordance with International Institutions and Conventions. In this respect Eni operates within the reference framework of Declaration of Human Rights, the Fundamental Conventions of Organization – and the OECD Guidelines on Multinational Enterprises. the United Nations Universal the ILO – International Labor All Eni’s People, without any distinction or exception whatsoever, respect the principles and contents of the Code in their actions and behaviours while performing their functions and according to their responsibilities, because compliance with the Code is fundamental for the quality of their working and professional performance. Relationships among Eni’s People, at all levels, must be characterized by honesty, fairness, cooperation, loyalty and mutual respect. The belief that one is acting in favour or to the advantage of Eni can never, in any way, justify, not even in part, any behaviours that conflict with the principles and contents of the Code. II. BEHAVIOUR RULES AND RELATIONS WITH STAKEHOLDERS 1. ETHICS, TRANSPARENCY, FAIRNESS, PROFESSIONALISM In conducting its business, Eni is inspired by and complies with the principles of loyalty, fairness, transparency, efficiency and an open market, regardless of the importance level of the transaction in question. Any action, transaction and negotiation performed and, generally, the conduct of Eni’s People in the performance of their duties is inspired by the highest principles of fairness, completeness and transparency of information and legitimacy, both in form and substance, as well as clarity and truthfulness of all accounting documents, in compliance with the applicable laws in force and internal regulations. All Eni’s activities have to be performed with the utmost care and professional skill, with the duty to provide skills and expertise adequate to the tasks assigned, and to act in a way capable to protect Eni’s image and reputation. Without prejudice to the compliance with applicable laws and obligations arising out from the adhesion to the principles contained in the Code of Conduct, the corporate objectives, as well as the proposal and implementation of projects, investments and actions, have to be aimed at improving the company’s assets, management, technological and information level in the long term, and at creating value and welfare for all Stakeholders. Bribes, illegitimate favours, collusion, requests for personal benefits for oneself or others, either directly or through third parties, are prohibited without any exception. It is prohibited to pay or offer, directly or indirectly, money and material benefits and other advantages of any kind to third parties, whether representatives of governments, public officers and public servants or private employees, in order to influence or remunerate the actions of their office. E-13 Commercial courtesy, such as small gifts or forms of hospitality, is only allowed when its value is small and it does not compromise the integrity and reputation of either party, and cannot be construed by an impartial observer as aimed at obtaining undue advantages. In any case, these expenses must always be authorized by the designated managers as per existing internal rules, and be accompanied by appropriate documentation. It is forbidden to accept money from individuals or companies that have or intend to have business relations with Eni. Anyone who receives proposals of gifts or special or hospitality treatment that cannot be considered as commercial courtesy of small value, or requests therefore by third parties, shall reject them and immediately inform their superior, or the body they belong to, as well as the Guarantor. Eni shall properly inform all third parties about the commitments and obligations provided for in the Code, require third parties to respect the principles of the Code relevant to their activities and take proper internal actions and, if the matter is within its own competence, external actions in the event that any third party should fail to comply with the Code. 2. RELATIONS WITH SHAREHOLDERS AND WITH THE MARKET 2.1. Value for shareholders, efficiency, transparency The internal structure of Eni and the relations with the parties directly and indirectly taking part in its activities are organized according to rules able to ensure management reliability and a fair balance between the management’s powers and the interests of shareholders and of the other Stakeholders in general as well as transparency and market traceability of management decisions and general corporate events which may considerably influence the market value of the financial instruments issued. Within the framework of the initiatives aimed at maximizing the value for shareholders and at guaranteeing transparency of the management’s work, Eni defines, implements and progressively adjusts a coordinated and homogeneous set of behaviour rules concerning both its internal organizational structure and relations with shareholders and third parties, in compliance with the highest corporate governance standards at national and international level, based on the awareness that the company’s capacity to impose efficient and effective functioning rules upon itself is a fundamental tool for strengthening its reputation in terms of reliability and transparency as well as Stakeholders’ trust. Eni deems it necessary that shareholders are enabled to participate in decisions which come within the limits of their competence and make informed choices. Therefore, Eni undertakes to ensure maximum transparency and timeliness of information communicated to shareholders and to the market, by means of the corporate internet site, too, in compliance with the laws and regulations applicable to listed companies. Eni also undertakes to keep in due consideration the legitimate remarks expressed by shareholders whenever they are entitled to do so. 2.2. Self-Regulatory Code The main corporate governance rules of Eni are contained in the Corporate Governance Code for listed companies, to which Eni adheres and which is referred to herein as may be required. 2.3. Company information Eni ensures the correct management of company information, by means of suitable procedures for in-house management and communication to the outside, with particular reference to privileged information. 2.4. Privileged information All Eni’s People are required, while performing the tasks entrusted to them, to properly manage privileged information such as to know and comply with corporate procedures referring to market abuse. Any conduct liable to constitute market abuse or facilitate its commission is specifically prohibited. In any case, the purchase or sale of shares of Eni or of companies outside Eni shall always be based on absolute and transparent fairness. 2.5. Information means It is responsibility of Eni to provide third parties with true, prompt, transparent and accurate information. Relations with the media are exclusively dealt with by the departments and managers specifically appointed to do so; information to be supplied to media representatives, as well as the undertaking to provide such information, have to be agreed upon beforehand by Eni’s People with the relevant Eni Corporate structure. 3. RELATIONS WITH INSTITUTIONS, ASSOCIATIONS, LOCAL COMMUNITIES Eni encourages dialogue with Institutions and with organized associations of civil society in all the countries where it operates. E-14 3.1 Authorities and Public Institutions Eni, through its People, actively and fully cooperates with Authorities. Eni’s People, as well as external collaborators whose actions may somehow be referred to Eni, must have behaviours towards the Public Administration characterized by fairness, transparency and traceability. These relations have to be exclusively dealt with by the departments and individuals specifically appointed to do so, in compliance with approved plans and corporate procedures. The departments of the subsidiaries concerned shall coordinate with the relevant Eni Corporate structure for assessing the quality of the interventions to be carried out and for the sharing, implementing and monitoring of their actions. It is forbidden to make, induce or encourage false statements to Authorities. 3.2 Political organizations and trade unions Eni does not make any direct or indirect contributions in whatever form to political parties, movements, committees, political organizations and trade unions, nor to their representatives and candidates. 3.3 Development of local Communities Eni is committed to actively contribute to promoting the quality of life, the socioeconomic development of the communities where Eni operates and to the development of their human resources and capabilities, while conducting its business activities according to standards that are compatible with fair commercial practices. Eni’s activities are carried out in the awareness of the social responsibility that Eni has towards all of its Stakeholders and in particular the local communities in which it operates, in the belief that the capacity for dialogue and interaction with civil society constitutes an important asset for the company. Eni respects the cultural, economic and social rights of the local communities in which it operates and undertakes to contribute, as far as possible, to their exercise, with particular reference to the right to adequate nutrition, drinking water, the highest achievable level of physical and mental health, decent dwellings, education, abstaining from actions that may hinder or prevent the exercise of such rights. Eni promotes transparency of the information addressed to local communities, with particular reference to the topics that they are most interested in. Forms of continuous and informed consultancy are either promoted, through the relevant Eni structures, in order to take into due consideration the legitimate expectations of local communities in conceiving and conducting corporate activities and in order to promote a proper redistribution of the profits deriving from such activities. Eni therefore undertakes to promote the knowledge of its corporate values and principles, at every level of its organization, also through adequate control procedures, and to protect the rights of local communities, with particular reference to their culture, institutions, ties and life styles. Within the framework of their respective responsibilities, Eni’s People are required to participate in the definition of single initiatives in compliance with Eni’s policies and intervention programs, to implement them according to criteria of absolute transparency and support them as an integral part of Eni’s objectives. 3.4 Promotion of “non profit” activities The philanthropic activity of Eni is in line with its vision and attention to sustainable development. Eni therefore undertakes to foster and support, as well as to promote among its People, its “non those profit” activities which demonstrate the company’s commitment to help meet the needs of communities where it operates. 4. RELATIONS WITH CUSTOMERS AND SUPPLIERS 4.1. Customers and consumers Eni pursues its business success on markets by offering quality products and services under competitive conditions while respecting the rules protecting fair competition. Eni undertakes to respect the right of consumers not to receive products harmful to their health and physical integrity and to get complete information on the products offered to them. Eni acknowledges that the esteem of those requesting products or services is of primary importance for success in business. Business policies are aimed at ensuring the quality of goods and services, safety and compliance with the precautionary principle. Therefore, Eni’s People shall: • • comply with in-house procedures concerning the management of relations with customers and consumers; supply, with efficiency and courtesy, within the limits set by the contractual conditions, high-quality products meeting the reasonable expectations and needs of customers and consumers; E-15 • supply accurate and exhaustive information on products and services and be truthful in advertisements or other kind of communication, so that customers and consumers can make informed decisions. 4.2. Suppliers and external collaborators Eni undertakes to look for suppliers and external collaborators with suitable professionalism and committed to sharing the principles and contents of the Code and promotes the establishment of long-lasting relations for the progressive improvement of performances while protecting and promoting the principles and contents of the Code. In relationships regarding tenders, procurement and, generally, the supply of goods and/or services and of external collaborations (including consultants, agents, etc.), Eni’s People shall: • • • follow internal procedures concerning selection and relations with suppliers and external collaborators and abstain from excluding any supplier meeting requirements from bidding for Eni’s orders; adopt appropriate and objective selection methods, based on established, transparent criteria; secure the cooperation of suppliers and external collaborators in guaranteeing the continuous satisfaction of customers and consumers, to an extent adequate to that legitimately expected by them, in terms of quality, costs and delivery times; use as much as possible, in compliance with the laws in force and the criteria for legality of transactions with related parties, products and services supplied by Eni companies at arm’s length and market conditions; state in contracts the Code acknowledgement and the obligation to comply with the principles contained therein; comply with, and demand compliance with, the conditions contained in contracts; maintain a frank and open dialogue with suppliers and external collaborators in line with good commercial practice; promptly inform superiors, and the Guarantor, about any possible violations of the Code; inform the relevant Eni Corporate structure about any serious problems that may arise with a particular supplier or external collaborator, in order to evaluate possible consequences for Eni. The remuneration to be paid shall be exclusively proportionate to the services to be rendered and described in the contract and payments shall not be allowed to any party different from the contract party nor in a third Country different from the one of the parties or where the contract has to be performed2. • • • • 5. THE MANAGEMENT, EMPLOYEES AND COLLABORATORS OF ENI 5.1. Development and protection of Human Resources People are basic components in the company’s life. The dedication and professionalism of management and employees represent fundamental values and conditions for achieving Eni’s objectives. Eni is committed to developing the abilities and skills of management and employees so that their energy and creativity can have full expression for the fulfilment of their potential in their working performance, such as to protect working conditions as regards both mental and physical health and dignity. Undue pressure or discomfort is not allowed, while appropriate working conditions promoting development of personality and professionalism are fostered. Eni undertakes to offer, in full compliance with applicable legal and contractual provisions, equal opportunities to all its employees, making sure that each of them receives a fair statutory and wage treatment exclusively based on merit and expertise, without discrimination of any kind. Competent departments shall: • • • adopt in any situation criteria of merit and ability (and anyhow strictly professional) in all decisions concerning human resources; select, hire, train, compensate and manage human resources without discrimination of any kind; create a working environment where personal characteristics or beliefs do not give rise to discrimination and which allows the serenity of all Eni’s People. Eni wishes that Eni’s People, at every level, cooperate in maintaining a climate of common respect for a person’s dignity, honour and reputation. Eni shall do its best to prevent attitudes that can be considered as offensive, discriminatory or abusive. In this regard, any behaviours outside the working place which are particularly offensive to public sensitivity are also deemed relevant. (2) For the purposes of application of the ban, third countries do not include States where a company/ entity, counter-party of Eni, has established its centralized cash management system and/or where the same has established, in whole or in part, its headquarters, offices or business units functional and necessary for the execution of the contract, in each case subject to all the additional control tools provided by internal regulatory instruments concerning the selection of counter-parties and payments. E-16 In any case, any behaviours constituting physical or moral violence are forbidden without any exception. 5.2. Knowledge Management Eni promotes culture and the initiatives aimed at disseminating knowledge within its structures, and at pointing out the values, principles, behaviours and contributions in terms of innovation of professional families in connection with the development of business activities and to the company’s sustainable growth. Eni undertakes to offer tools for interaction among the members of professional families, working groups and communities of practice, as well as for coordination and access to know-how, and shall promote initiatives for the growth, dissemination and systematization of knowledge relating to the core competences of its structures and aimed at defining a reference framework suitable for guaranteeing operating consistency. All Eni’s People shall actively contribute to Knowledge Management as regards the activities that they are in charge of, in order to optimize the system for knowledge sharing and distribution among individuals. 5.3. Corporate security Eni engages in the study, development and implementation of strategies, policies and operational plans aimed at preventing and overcoming any intentional or nonintentional behaviour which may cause direct or indirect damage to Eni’s People and/or to the tangible and intangible resources of the company. Preventive and defensive measures, aimed at minimizing the need for an active response – always in proportion to the attack – to threats to people and assets, are favoured. All Eni’s People shall actively contribute to maintaining an optimal corporate security standard, abstaining from unlawful or dangerous behaviours, and reporting any possible activities carried out by third parties to the detriment of Eni’s assets or human resources to superiors or to the body they belong to, as well as to the relevant Eni Corporate structure. In any case requiring particular attention to personal safety, it is compulsory to strictly follow the indications in this regard supplied by Eni, abstaining from behaviours which may endanger one’s own safety or the safety of others, promptly reporting any danger for one’s own safety, or the safety of third parties, to one’s superior. 5.4. Harassment or mobbing in the workplace Eni supports any initiatives aimed at implementing working methods for the achievement of a better organization. Eni demands that there shall be no harassment or mobbing behaviours in personal working relationships either inside or outside the company. Such behaviours are all forbidden, without exceptions. Such harassment is for instance: • • • the creation of an intimidating, hostile, isolating or in any case discriminatory environment for individual employees or groups of employees; unjustified interference in the work performed by others; the placing of obstacles in the way of the work prospects and expectations of others merely for reasons of personal competitiveness or because of other employees. Any form of violence or harassment, either sexual harassment or harassment based on personal and cultural diversity, is forbidden. Such harassment is for instance: • • • • subordinating decisions on someone’s working life to the acceptance of sexual attentions, or personal and cultural diversity; encouraging employees to sexual favours through the influence of a role; proposing private interpersonal relations, despite express or reasonably obvious non-acceptance; alluding to disabilities and physical or psychic impairment, or to forms of cultural, religious or sexual diversity. 5.5. Abuse of alcohol or drugs and no smoking All Eni’s People shall personally contribute to promoting and maintaining a climate of common respect in the workplace; particular attention is paid to respect of the feelings of others. Eni will therefore consider individuals who work under the effect of alcohol or drugs, or substances with similar effect, during the performance of their work activities and in the workplace, as being aware of the risk they cause. Chronic addiction to such substances, when it affects work performance, shall be considered similar to the above mentioned events in terms of contractual consequences; Eni is committed to favour social action in this field as provided for by employment contracts. It is forbidden to: • hold, consume, offer or give for whatever reason, drugs or substances with similar effect, at work and in the workplace; E-17 • smoke in the workplace. Eni supports voluntary initiatives addressed to People to help them quit smoking and, in identifying possible smoking areas, shall take into particular consideration the condition of those suffering physical discomfort from exposure to smoke in the workplace shared with smokers and requesting to be protected from “passive smoking” in their place of work. III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS 1. INTERNAL CONTROL AND RISK MANAGEMENT SYSTEM Eni is committed to promoting and maintaining an adequate internal control and risk management system, by adopting and implementing all useful instruments to direct, manage and monitor business activities with the aim of ensuring compliance with laws and company procedures, protecting corporate assets, efficiently and effectively managing activities and providing accurate and complete accounting and identification, measurement, management and financial data, as well ensuring a proper process of monitoring of main business risks. The responsibility for implementing an effective system of internal control and risk management is shared at every level of Eni’s organizational structure; therefore, all Eni’s People, according to their functions and responsibilities, shall define and actively participate in the correct functioning of the system of internal control and risk management. Eni promotes the dissemination, at every level of its organization, of policies and procedures characterized by awareness of the existence of controls and by an informed and voluntary control oriented mentality; consequently, Eni’s management in the first place and all Eni’s People in any case shall contribute to and participate in Eni’s system of internal control and risk management and, with a positive attitude, involve its collaborators in this respect. Each employee shall be held responsible for the corporate tangible and intangible assets relevant to his/ her job. No employee can make, or let others make, improper use of assets and equipment belonging to Eni. Any practices and attitudes linked to the perpetration or to the participation in the perpetration of frauds are forbidden without any exception. Control and watch structures, Eni Internal Audit department and appointed auditing companies shall have full access to all data, documents and information necessary to perform their own relevant activities. 1.1 Conflicts of interest Eni acknowledges and respects the right of its People to take part in investments, business and other kinds of activities other than the activity performed in the interest of Eni, provided that such activities are permitted by law and are compatible with the obligations assumed towards Eni. Eni adopts internal regulatory instruments that ensure transparency and fairness, substantive and procedural, of the transactions involving interests of Directors and Statutory Auditors and transactions with related parties. Eni’s management and employees shall avoid and report any conflicts of interest between personal and family economic activities and their tasks within the company. In particular, everyone shall point out any specific situations and activities of economic or financial interest (owner or member) to them or, as far as they know, of economic or financial interest to relatives of theirs or relatives by marriage within the 2nd degree of kinship, or to persons actually living with them, also involving suppliers, customers, competitors, third parties, or the relevant controlling companies or subsidiaries, and shall point whether they perform corporate administration or control or management functions therein. Moreover, conflicts of interest are determined by the following situations: • using one’s position in the company or the information or business opportunities acquired during one’s work, to undue personal advantage or to that of third parties; carrying out of work activities by employees and/or their family members at suppliers, subcontractors, competitors. • In any case, Eni’s management and employees shall avoid any situation and activity where a conflict with the Company’s interests may arise, or which can interfere with their ability to make impartial decisions in the best interests of Eni and in full accordance with the principles and contents of the Code, or in general with their ability to fully comply with their functions and responsibilities. Any situation that may constitute or give rise to a conflict of interest shall be immediately reported to one’s superior within management, or to the body one belongs to, and to the Guarantor. Furthermore, the party concerned shall abstain from taking part in the operational/decision-making process, and the relevant superior within management, or the relevant body, shall: • • identify the operational solutions suitable for ensuring, in the specific case, transparency and fairness of behaviours in the performance of activities; transmit to the parties concerned – and for information to one’s superior, as well as to the Guarantor – the necessary written instructions; E-18 • file the received and transmitted documentation. 1.2 Transparency of accounting records Accounting transparency is grounded on the use of true, accurate and complete information which form the basis for the entries in the books of accounts. Each member of company bodies, of management or employee shall cooperate, within their own field of competence, in order to have operational events properly and timely registered in the books of accounts. It is forbidden to behave in a way that may adversely affect transparency and traceability of the information within financial statements. For each transaction, the proper supporting evidence has to be maintained in order to allow: • • • easy and punctual accounting entries; identification of different levels of responsibility, as well as of task distribution and segregation; accurate representation of the transaction so as to avoid the probability of any material or interpretative error. Each record shall reflect exactly what is shown by the supporting evidence. All Eni’s People shall cause that the documentation can be easily traced and filed according to logical criteria. Eni’s People who become aware of any omissions, forgery, negligence in accounting or in the documents on which accounting is based, shall bring the facts to the attention of their superior, or to the body they belong to, and to the Guarantor. 2. HEALTH, SAFETY, ENVIRONMENT AND PUBLIC SAFETY PROTECTION Eni’s activities shall be carried out in compliance with applicable worker health and safety, environmental and public safety protection agreements, international standards and laws, regulations, administrative practices and national policies of the Countries where it operates. Eni actively contributes as appropriate to the promotion of scientific and technological development aimed at protecting the environment and natural resources. The operative management of such activities shall be carried out according to advanced criteria for the protection of the environment and energy efficiency, with the aim of creating better working conditions and protecting the health and safety of employees as well as the environment. Eni’s People shall, within their areas of responsibility, actively participate in the process of risk prevention as well as environmental, public safety and health protection for themselves, their colleagues and third parties. 3. RESEARCH, INNOVATION AND INTELLECTUAL PROPERTY PROTECTION Eni promotes research and innovation activities by management and employees, within their functions and responsibilities. Any intellectual assets generated by such activities are an important and fundamental heritage of Eni. Research and innovation focus in particular on the promotion of products, instruments, processes and behaviours supporting energy efficiency, reduction of environmental impact, attention to health and safety of employees, of customers and of the local communities where Eni operates, and in general sustainability of business activities. Eni’s People shall actively contribute, within their functions and responsibilities, to managing intellectual property in order to allow its development, protection and enhancement. 4. CONFIDENTIALITY 4.1. Protection of business secret Eni’s activities constantly require the acquisition, storing, processing, communication and dissemination of information, documents and other data regarding negotiations, administrative proceedings, financial transactions, and know-how (contracts, deeds, reports, notes, studies, drawings, pictures, software, etc.) that may not be disclosed to the outside pursuant to contractual agreements, or whose inopportune or untimely disclosure may be detrimental to corporate interest. Without prejudice to the transparency of the activities carried out and to the information obligations imposed by the provisions in force, Eni’s People shall ensure the confidentiality required by the circumstances for each piece of news they have got to know of because of their working function. Any information, knowledge and data acquired or processed during one’s work or because of one’s tasks at Eni, belong to Eni and may not be used, communicated or disclosed without specific authorization of one’s superior within management in compliance with specific procedures. 4.2. Protection of privacy Eni is committed to protecting information concerning its People and third parties, whether generated or obtained inside Eni or in the conduct of Eni’s business, and to avoiding improper use of any such information. E-19 Eni intends to guarantee that processing of personal data within its structures respects fundamental rights and freedoms, as well as the dignity of the parties concerned, as contemplated by the legal provisions in force. Personal data must be processed in a lawful and fair way and, in any case, the data collected and stored is only that which is necessary for certain, explicit and lawful purposes. Data shall be stored for a period of time no longer than necessary for the purposes of collection. Eni undertakes moreover to adopt suitable preventive safety measures for all databases storing and keeping personal data, in order to avoid any risks of destruction and losses or of unauthorized access or unallowed processing. Eni’s People shall: • obtain and process only data that are necessary and adequate to the aims of their work and responsibilities; obtain and process such data only within specified procedures, and store said data in a way that prevents unauthorized parties from having access to it; represent and order data in a way ensuring that any party with access authorization may easily get an outline thereof which is as accurate, exhausting and truthful as possible; disclose such data pursuant to specific procedures or subject to the express authorization by their superior and, in any case, only after having checked that such data may be disclosed, also making reference to absolute or relative constraints concerning third parties bound to Eni by a relation of whatever nature and, if applicable, after having obtained their consent. • • • 4.3. Membership in associations, participation in initiatives, events or external meetings Membership in associations, participation in initiatives, events or external meetings is supported by Eni if compatible with the working or professional activity provided. Membership and participation considered as such are: membership in associations, conferences, congresses, seminars, courses; drawing up of articles, essays and publications in general; participation in public events in general. • • • In this regard, Eni’s management and employees in charge of illustrating, or providing to the outside data or news concerning Eni’s objectives, aims, results and points of view, shall not only comply with corporate procedures relating to market abuse, but also obtain the necessary authorization from their superior within management for the lines of action to follow and the texts as well as reports drawn up, such as to agree on contents with the relevant Eni Corporate structure. IV. CODE OF ETHICS SCOPE OF APPLICATION AND REFERENCE STRUCTURES The principles and contents of the Code apply to Eni’s People and activities. Subsidiaries listed on the Stock Exchange receive the Code and adopt it, adjusting it – where necessary – to the characteristics of their company in accordance with their management independence. The representatives indicated by Eni in the company bodies of partially owned companies, in consortia and in joint ventures shall promote the principles and contents of the Code within their own respective areas of competence. Directors and management must be the first to give concrete form to the principles and contents of the Code, by assuming responsibility for them both towards the inside and the outside and by enhancing trust, cohesion and a sense of team-work, as well as providing a behaviour model for their collaborators in order to have them comply with the Code and make questions and suggestions on specific provisions. To achieve full compliance with the Code, each of Eni’s People may even apply directly to the Guarantor. 1. OBLIGATION TO KNOW THE CODE AND TO REPORT ANY POSSIBLE VIOLATION THEREOF The Code is made available to Eni’s People in compliance with applicable standards, and is also available on the internet and intranet sites of Eni spa and of the Subsidiaries. Each of Eni’s People is expected to know the principles and contents of the Code as well as the reference procedures governing own functions and responsibilities. Each of Eni’s People shall: • • refrain from all conduct contrary to such principles, contents and procedures; carefully select, as long as within their field of competence, their collaborators, and have them fully comply with the Code; require any third parties having relations with Eni to confirm that they know the Code; immediately report to their superiors or the body they belong to, and to the Guarantor, any • • E-20 remarks of theirs or information supplied by Stakeholders concerning a possible violation or any request to violate the Code; reports of possible violations shall be sent in compliance with conditions provided for by the specific procedures established by the Board of Statutory Auditors and by the Watch Structure of Eni spa; cooperate with the Guarantor and with the relevant departments according to the applicable specific procedures in ascertaining any violations; adopt prompt corrective measures whenever necessary, and in any case prevent any type of retaliation. • • Eni’s People are not allowed to conduct personal investigations, nor to exchange information, except to their superiors, or to the body that they belong to, and to the Guarantor. If, after notifying a supposed violation, any of Eni’s People feels that he or she has been subject to retaliation, then he or she may directly apply to the Guarantor. 2. REFERENCE STRUCTURES AND SUPERVISION Eni is committed to ensuring, even through the Guarantor’s appointment: • the widest dissemination of the principles and contents of the Code among Eni’s People and the other Stakeholders, providing any possible instruments for understanding and clarifying the interpretation and the implementation of the Code, as well as for updating the Code as required to meet evolving civil sensibility and relevant laws; the execution of checks on any notice of violation of the Code principles and contents or of reference procedures; an objective evaluation of the facts and, if necessary, the adoption of appropriate sanctions; that no one may suffer any retaliation whatsoever for having provided information regarding possible violations of the Code or of reference procedures. • 2.1. Guarantor of the Code of Ethics The Code of Ethics is, among other things, a compulsory general principle of the Organizational, Management and Control Model adopted by Eni spa according to the Italian provision on the “administrative liability of legal entities deriving from offences” contained in Legislative Decree no. 231 of June 8, 2001. Eni spa assigns the functions of Guarantor to the Watch Structure established pursuant to the above-mentioned Model. Each direct or indirect subsidiary, in Italy and abroad, entrusts the function of Guarantor to its own Watch Structure by formal deed of the relevant corporate body. The Guarantor is entrusted with the task of: • promoting and facilitating the implementation of the Code of Ethics and the issue of reference procedures; reporting and proposing to the CEO of the company the useful initiatives for a greater dissemination and knowledge of the Code, also in order to prevent any recurrences of violations; promoting awareness of the Code of Ethics also through communication programs and specific training of management and employees of Eni; investigating reports of any violation of the Code by initiating proper inquiry procedures; taking action at the request of Eni’s People in the event of receiving reports that violations of the Code have not been properly dealt with or in the event of being informed of any retaliation against Eni’s People for having reported violations; notifying relevant structures of the results of investigations relevant to the adoption of possible penalties; informing the relevant line/area structures about the results of investigations relevant to the adoption of the necessary measures. • • • Moreover, the Guarantor of Eni spa submits to the Control and Risk Committee and to the Board of Statutory Auditors as well as to the Chairman and to the Chief Executive Officer, which report about it to the Board of Directors, a six-monthly report on the implementation and possible need for updating the Code. In carrying out its tasks, the Guarantor of Eni spa avails itself of the units of the Integrated Compliance Department in charge of the activities of the technical secretariat of the Watch Structure 231 of Eni spa. Each information flow to the Guarantor may be sent to the following email address: organismo_di_vigilanza@Eni.com. 2.2. Promotion and diffusion of the Code of Ethics The Code is made available to Eni’s People in compliance with applicable standards, and is also available on the internet and Intranet sites of Eni spa and of subsidiaries. The Guarantor of Eni spa promotes the provision of every possible instrument for understanding and clarifying the interpretation and implementation of the Code. E-21 3. CODE REVIEW The Code review is approved by the Board of Directors of Eni spa, upon proposal of the Chief Executive Officer with the agreement of the Chairman, after hearing the opinion of the Board of Statutory Auditors. The proposal is made taking into consideration the Stakeholders’ evaluation with reference to the principles and contents of the Code, promoting active contribution and notification of possible deficiencies by Stakeholders themselves. 4. CONTRACTUAL VALUE OF THE CODE Respect of the Code’s rules is an essential part of the contractual obligations of all Eni’s People pursuant to and in accordance with applicable law. Any violation of the Code’s principles and contents may be considered as a violation of primary obligations under labour relations or of the rules of discipline and can entail the consequences provided for by law, including termination of the work contract and compensation for damages arising out of any violation. E-22 EXHIBIT 12.1 I, Claudio Descalzi, certify that: 1. I have reviewed this Annual Report on Form 20-F of Eni SpA; Certification 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and 5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting. Date: March 22, 2017 /s/ CLAUDIO DESCALZI Claudio Descalzi Title: Chief Executive Officer E-23 EXHIBIT 12.2 I, Massimo Mondazzi certify that: 1. I have reviewed this annual report on Form 20-F of Eni SpA; Certification 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and 5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting. Date: March 22, 2017 /s/ MASSIMO MONDAZZI Massimo Mondazzi Title: Chief Financial Officer E-24 EXHIBIT 13.1 Certification Pursuant to 18 U.S.C. Section 1350 For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the “Company”), hereby certifies, to such officer’s knowledge, that: (i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2016 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 22, 2017 /s/ CLAUDIO DESCALZI Claudio Descalzi Title: Chief Executive Officer The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act. E-25 EXHIBIT 13.2 Certification Pursuant to 18 U.S.C. Section 1350 For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the “Company”), hereby certifies, to such officer’s knowledge, that: (i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2016 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 22, 2017 /s/ MASSIMO MONDAZZI Massimo Mondazzi Title: Chief Financial Officer The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act. E-26 EXHIBIT 15.a(i) DD e G o l y e r a n d M a c N a u g h t o n 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 February 28, 2017 Eni S.p.A. Pietro G. Consonni Vice President, Reserves Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Mr. Consonni: Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved oil, condensate, liquefied petroleum gas (LPG), and gas reserves, as of December 31, 2016, of certain properties in Africa, Asia, and Europe in which Eni S.p.A. (Eni) has represented that it owns an interest. This evaluation was completed on February 28, 2017. Eni has represented that these properties account for 29 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2016, and that Eni’s net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. It is our opinion that the procedures and methodologies employed by Eni for the preparation of their proved reserves evaluation as of December 31, 2016, comply with the current requirements of the SEC. We have reviewed information provided to us by Eni that it represents to be Eni’s estimates of the net reserves, as of December 31, 2016, for the same properties as those which we have independently evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Eni. Reserves estimates included herein are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2016. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Eni after deducting interests owned by others. DeGolyer and MacNaughton 5001 S p r i ng Valley Ro ad S u ite 800 E ast Dallas, Texas 75244 February 28, 2017 Eni S.p.A.Pietro G. Consonni Vice President, Reserves Via Emilia 120097 San Donato Milanese Milano, Italy Dear Mr. Consonni: Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved oil, condensate, liquefied petroleum gas (LPG), and gas reserves, as of December 31, 2016, of certain properties in Africa, Asia, and Europe in which Eni S.p.A. (Eni) has represented that it owns an interest. This evaluation was completed on February 28,2017. Eni has represented that these properties account for 29 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2016, and that Eni’s net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)– (32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. It is our opinion that the procedures and methodologies employed by Eni for the preparation of their proved reserves evaluation as of December 31, 2016, comply with the current requirements of the SEC. We have reviewed information provided to us by Eni that it represents to be Eni’s estimates of the net reserves, as of December 31, 2016, for the same properties as those which we have independently evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Eni. Reserves estimates included herein are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2016. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Eni after deducting interests owned by others. E-26 2 DeGolyer and MacNaughton Estimates of oil, condensate, LPG, and gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Data used in this audit were obtained from reviews with Eni personnel, from Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report. Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, the development plans provided by Eni, and the analyses of areas offsetting existing wells, reserves were classified as proved. When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP. Estimates of oil, condensate, LPG, and gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Data used in this audit were obtained from reviews with Eni personnel, from Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report. Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, the development plans provided by Eni, and the analyses of areas offsetting existing wells, reserves were classified as proved. When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP. E-27 3 DeGolyer and MacNaughton Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In these instances, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate. In certain cases, elements of the reserves estimates incorporated information based on analogy with similar reservoirs for which more complete data were available. Eni has represented that its estimates of oil, condensate, and LPG reserves are reported as a summed quantity, since there is no material effect in reporting the quantities separately. Definition of Reserves Petroleum reserves included in this report are classified as proved. Reserves classifications used for our estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Eni has represented that its estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using known production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including in existing prices provided only by contractual consideration of changes arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In these instances, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate. In certain cases, elements of the reserves estimates incorporated information based on analogy with similar reservoirs for which more complete data were available. Eni has represented that its estimates of oil, condensate, and LPG reserves are reported as a summed quantity, since there is no material effect in reporting the quantities separately. Definition of Reserves Petroleum reserves included in this report are classified as proved. Reserves classifications used for our estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Eni has represented that its estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using known production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: E-28 DeGolyer and MacNaughton 4 Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable the higher contact with reasonable certainty. technology establish (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not in the proved limited to, fluid classification when: injection) are included Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: E-29 DeGolyer and MacNaughton 5 (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. E-30 DeGolyer and MacNaughton 6 using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped for which an reserves be attributable to any acreage application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. Primary Economic Assumptions The following economic assumptions were used for estimating existing and future prices and costs, expressed in United States dollars (U.S.$): Oil, Condensate, and LPG Prices Eni provided all pricing information, and it has represented that the provided oil, condensate, and LPG prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A Brent oil price of U.S.$42.80 per barrel was the resulting reference price. Where appropriate, Eni supplied differentials by field to the relevant reference price, and the prices were held constant thereafter. The volume-weighted average oil, condensate, and LPG prices used in this report are presented below, expressed in United States dollars per barrel (U.S.$/bbl): (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. Primary Economic Assumptions The following economic assumptions were used for estimating existing and future prices and costs, expressed in United States dollars (U.S.$): Oil, Condensate, and LPG Prices Eni provided all pricing information, and it has represented that the provided oil, condensate, and LPG prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A Brent oil price of U.S.$42.80 per barrel was the resulting reference price. Where appropriate, Eni supplied differentials by field to the relevant reference price, and the prices were held constant thereafter. The volume-weighted average oil, condensate, and LPG prices used in this report are presented below, expressed in United States dollars per barrel (U.S.$/bbl): E-31 DeGolyer and MacNaughton 7 Oil (U.S.$/bbl) Condensate and LPG (U.S.$/bbl) 40.89 N/A N/A 35.98 42.43 35.88 Africa Asia Europe Average for Total Note: “N/A” is Not Applicable. Gas Prices Eni has represented that the provided gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A significant quantity of the gas sold by Eni is subject to contract prices, and the range of such prices is varied. A reference price is the United Kingdom National Balancing Point Index, which was U.S.$4.79 per thousand cubic feet. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices used in this report are presented below, expressed in United States dollars per thousand cubic feet (U.S.$/Mcf): Gas (U.S.$/Mcf) 4.62 3.53 5.07 Africa Asia Europe Average for Total Operating Expenses and Capital Costs Operating expenses and capital costs, based on information provided by Eni, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. Oil(U.S.$/bbl) Condensateand LPG(U.S.$/bbl) Africa 40.89 35.98 Asia N/A 42.43 Europe N/A 35.88 Average for Total Note: “N/A” is Not Applicable. Gas Prices Eni has represented that the provided gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A significant quantity of the gas sold by Eni is subject to contract prices, and the range of such prices is varied. A reference price is the United Kingdom National Balancing Point Index, which was U.S.$4.79 per thousand cubic feet. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices used in this report are presented below, expressed in United States dollars per thousand cubic feet (U.S.$/Mcf): Gas(U.S.$/Mcf) Africa 4.62 Asia 3.53 Europe 5.07 Average for Total Operating Expenses and Capital Costs Operating expenses and capital costs, based on information provided by Eni, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. E-32 8 DeGolyer and MacNaughton While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil, condensate, LPG, and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the oil, condensate, LPG, and gas reserves as of December 31, 2016, estimated herein. Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Africa, Asia, and Europe were based on the definitions of proved reserves of the SEC. Eni has represented that its estimates of the net proved reserves attributable to these properties, which represent 29 percent of Eni’s net reserves on a net equivalent basis, are summarized as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe): Estimated by Eni Net Proved Reserves as of December 31, 2016 Oil, Condensate, and LPG (MMbbl) Gas (Bcf) Oil Equivalent (MMboe) Properties reviewed by DeGolyer and MacNaughton Total Proved 402.0 9,607.4 2,162.2 Note: Gas is converted to oil equivalent using a factor of 5,458 cubic feet of gas per 1 barrel of oil equivalent based on energy equivalency. In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil, condensate, LPG, and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the oil, condensate, LPG, and gas reserves as of December 31, 2016, estimated herein. Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Africa, Asia, and Europe were based on the definitions of proved reserves of the SEC. Eni has represented that its estimates of the net proved reserves attributable to these properties, which represent 29 percent of Eni’s net reserves on a net equivalent basis, are summarized as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe): Estimated by EniNet Proved Reserves as of December 31, 2016 Oil,Condensate,and LPG(MMbbl) Gas(Bcf) OilEquivalent(MMboe) Properties reviewed byDeGolyer and MacNaughton Total Proved 402.0 9,607.4 2,162.2 Note: Gas is converted to oil equivalent using a factor of 5,458 cubic feet of gas per 1 barrel of oil equivalent based on energy equivalency. In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year. E-33 9 DeGolyer and MacNaughton To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative, resulting in an aggregate difference of less than 6 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable. DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 [SEAL] /s/ Regnald A. Boles Regnald A. Boles, P.E. Senior Vice President DeGolyer and MacNaughton To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative, resulting in an aggregate difference of less than 6 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable. DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 /s/ Regnald A. Boles Regnald A. Boles, P.E. [SEAL] Senior Vice President DeGolyer and MacNaughton E-34 DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Regnald A. Boles, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare to Eni dated February 28, 2017, and that I, as Senior Vice President, was responsible for the preparation of this letter report. letter report addressed the 2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1983; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 33 years of experience in oil and gas reservoir studies and evaluations. SIGNED: February 28, 2017 [SEAL] /s/ Regnald A. Boles Regnald A. Boles, P.E. Senior Vice President DeGolyer and MacNaughton To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative, resulting in an aggregate difference of less than 6 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable. DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 /s/ Regnald A. Boles Regnald A. Boles, P.E. [SEAL] Senior Vice President DeGolyer and MacNaughton E-35 Eni S.p.A. EXHIBIT 15.a(ii) Estimated Future Reserves and Income Attributable to Certain Interests SEC Parameters As of December 31, 2016 /s/ Herman G. Acuña Herman G. Acuña, P.E. TBPE License No. 92254 Managing Senior Vice President-International [SEAL] /s/ Adedeji A. Adeyeye Adedeji A. Adeyeye, P.E. TBPE License No. 109670 Senior Petroleum Engineer [SEAL] RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 Eni S.p.A. Estimated Future Reserves and Income Attributable to Certain Interests SEC Parameters As of December 31, 2016 /s/ Herman G. Acuña /s/ Adedeji A. Adeyeye Herman G. Acuña, P.E. Adedeji A. Adeyeye, P.E. TBPE License No. 92254 TBPE License No. 109670 Managing Senior Vice President-International Senior Petroleum Engineer [SEAL] [SEAL] RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-36 TBPE REGISTERED ENGINEERING FIRM F-1580 1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 FAX (713) 651-0849 TELEPHONE (713) 651-9191 February 27, 2017 Eni S.p.A Mr. Pietro G. Consonni Vice President Reserves Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Mr. Consonni, At the request of Eni S.p.A. (Eni), Ryder Scott Company, L.P (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni’s engineering and geological staff as of December 31, 2016 based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on February 27, 2017 and presented herein, was prepared for public disclosure by Eni in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Eni has indicated that the proved net reserves attributable to the properties that we reviewed account for 12 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations: Europe Asia Americas Sub-Saharan Africa As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.” Based on our review, including the data, technical processes and interpretations presented by Eni, it is our opinion that the overall procedures and methodologies utilized by Eni in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott’s estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. The conclusions discussed in this report are related to hydrocarbon prices. Eni has informed us that in preparation of their reserve and income projections, as of December 31, 2016, they used SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (403) 262-2799 TEL (303) 623-9147 FAX (403) 262-2790 FAX (303) 623-4258 February 27, 2017 Eni S.p.A Mr. Pietro G. Consonni Vice President Reserves Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Mr. Consonni, At the request of Eni S.p.A. (Eni), Ryder Scott Company, L.P (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni’s engineering and geological staff as of December 31, 2016 based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on February 27, 2017 and presented herein, was prepared for public disclosure by Eni in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Eni has indicated that the proved net reserves attributable to the properties that we reviewed account for 12 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations: Europe Asia Americas Sub-Saharan Africa As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.” Based on our review, including the data, technical processes and interpretations presented by Eni, it is our opinion that the overall procedures and methodologies utilized by Eni in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott’s estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. The conclusions discussed in this report are related to hydrocarbon prices. Eni has informed us that in preparation of their reserve and income projections, as of December 31, 2016, they used E-37 Eni S.p.A. – Third Party February 27, 2017 Page 2 average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott. Reserves Included in This Report In our opinion, the proved reserves discussed herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein. Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni’s request, this report addresses only the proved reserves attributable to the properties evaluated herein. Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts. The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless RYDER SCOTT COMPANY PETROLEUM CONSULTANTS average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott. Reserves Included in This Report In our opinion, the proved reserves discussed herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein. Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni’s request, this report addresses only the proved reserves attributable to the properties evaluated herein. Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts. The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless E-38 Eni S.p.A. – Third Party February 27, 2017 Page 3 evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni’s representations regarding such contractual information should be construed as a legal opinion on this matter. Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities. The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices. Audit Data, Methodology, Procedure and Assumptions The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable RYDER SCOTT COMPANY PETROLEUM CONSULTANTS evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni’s representations regarding such contractual information should be construed as a legal opinion on this matter. Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities. The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices. Audit Data, Methodology, Procedure and Assumptions The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable E-39 Eni S.p.A. – Third Party February 27, 2017 Page 4 and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above. Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. The proved reserves for the properties included herein were estimated by performance methods, analogy methods, the volumetric method, or a combination of performance and volumetric methods. These performance methods include, but may not be limited to, decline curve analysis and analogy which utilized extrapolations of historical production and pressure data available through September 2016 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Eni and were considered sufficient for the purpose thereof. The volumetric method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Eni that were available through September 2016. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent RYDER SCOTT COMPANY PETROLEUM CONSULTANTS and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above. Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. The proved reserves for the properties included herein were estimated by performance methods, analogy methods, the volumetric method, or a combination of performance and volumetric methods. These performance methods include, but may not be limited to, decline curve analysis and analogy which utilized extrapolations of historical production and pressure data available through September 2016 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Eni and were considered sufficient for the purpose thereof. The volumetric method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Eni that were available through September 2016. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent E-40 Eni S.p.A. – Third Party February 27, 2017 Page 5 verification of the data furnished by Eni. We consider the factual data used in this report appropriate and sufficient for the purpose of our investigations. In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to conduct the audit of reserves of the properties described herein. The proved reserves discussed herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves reviewed in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. Future Production Rates For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Eni. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Eni relating to hydrocarbon prices and costs as noted herein. The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS verification of the data furnished by Eni. We consider the factual data used in this report appropriate and sufficient for the purpose of our investigations. In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to conduct the audit of reserves of the properties described herein. The proved reserves discussed herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves reviewed in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. Future Production Rates For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Eni. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Eni relating to hydrocarbon prices and costs as noted herein. The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. E-41 Eni S.p.A. – Third Party February 27, 2017 Page 6 Eni furnished us with the above mentioned average prices in effect on December 31, 2016. Eni has assured us that these initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. The average dated Brent oil price of $42.80/bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. All gas prices shown below are in dollars per thousand cubic meters ($/km3). The average realized prices provided by Eni and used in our evaluation are as follows: Geographic Area Product Europe Asia Americas Sub-Saharan Africa Gas Gas Oil Gas Gas Oil Condensate Average Proved Realized Prices $163.87/km3 $ 53.00/km3 $ 32.42/bbl $ 28.86/km3 $125.74/km3 $ 39.67/bbl $ 42.79/bbl The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Eni. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Eni to determine these differentials. Costs Operating costs used in our evaluation were based on the operating expense reports of Eni and include only those costs directly applicable to the evaluated assets. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Eni. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets. Development costs were furnished to us by Eni and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Eni were accepted without independent verification. The proved developed and undeveloped reserves in this report have been incorporated herein in accordance with Eni’s plans to develop these reserves as of December 31, 2016. The implementation of Eni’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Eni’s management. As the result of our inquires during the course of preparing this report, Eni has informed us that the development activities included herein have been Eni furnished us with the above mentioned average prices in effect on December 31, 2016. Eni has assured us that these initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. The average dated Brent oil price of $42.80/bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. All gas prices shown below are in dollars per thousand cubic meters ($/km3). The average realized prices provided by Eni and used in our evaluation are as follows: Geographic Area Product Average ProvedRealized Prices Europe Gas $163.87/km3 Asia Gas $ 53.00/km3 Oil $ 32.42/bbl Americas Gas $ 28.86/km3 Sub-Saharan Africa Gas $125.74/km3 Oil $ 39.67/bbl Condensate $ 42.79/bblThe product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Eni. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Eni to determine these differentials. Costs Operating costs used in our evaluation were based on the operating expense reports of Eni and include only those costs directly applicable to the evaluated assets. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Eni. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets. Development costs were furnished to us by Eni and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Eni were accepted without independent verification. The proved developed and undeveloped reserves in this report have been incorporated herein in accordance with Eni’s plans to develop these reserves as of December 31, 2016. The implementation of Eni’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Eni’s management. As the result of our inquires during the course of preparing this report, Eni has informed us that the development activities included herein have been RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-42 Eni S.p.A. – Third Party February 27, 2017 Page 7 subjected to and received the internal approvals required by Eni’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Eni. Additionally, Eni has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Current costs used by Eni were held constant throughout the life of the properties. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. We are independent petroleum engineers with respect to Eni. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed. The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. Terms of Usage The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Eni. subjected to and received the internal approvals required by Eni’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Eni. Additionally, Eni has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Current costs used by Eni were held constant throughout the life of the properties. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. We are independent petroleum engineers with respect to Eni. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed. The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. Terms of Usage The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Eni. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-43 Eni S.p.A. – Third Party February 27, 2017 Page 8 We have provided Eni with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Eni and the original signed report letter, the original signed report letter shall control and supersede the digital version. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L. P. TBPE Firm Registration No. F-1580 /s/ Herman G. Acuña Herman G. Acuna, P.E. TBPE License No. 92254 Managing Senior Vice President – International [SEAL] /s/ Adedeji A. Adeyeye Adedeji A. Adeyeye, P.E. TBPE License No. 109670 Senior Petroleum Engineer [SEAL] HGA-AAA (DPR)/pl We have provided Eni with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Eni and the original signed report letter, the original signed report letter shall control and supersede the digital version. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L. P. TBPE Firm Registration No. F-1580 /s/ Herman G. Acuña Herman G. Acuna, P.E. TBPE License No. 92254 Managing Senior Vice President – International [SEAL] /s/ Adedeji A. Adeyeye Adedeji A. Adeyeye, P.E. TBPE License No. 109670 Senior Petroleum Engineer [SEAL] HGA-AAA (DPR)/pl RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-44 Professional Qualifications of Primary Technical Person The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the independent estimation of the reserves, future production and income to render the audit conclusions of the report. Mr. Acuña, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1997, is a Managing Senior International Vice President and Board Member. He serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com. Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas, a member of the Association of International Petroleum Negotiators (AIPN) and the Society of Petroleum Engineers (SPE). In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. Mr. Acuña has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Acuña has recently taught various company reserves evaluation schools in Argentina, China, Denmark, Spain and the U.S.A. Mr. Acuña has participated in various capacities in reserves conferences such as being a panelist at Trinidad and Tobago’s Petroleum Conference, delivering the reserves evaluation seminar during IAPG convention in Mendoza, Argentina and chairing the first Reserves Evaluation Conference in the Middle East in Dubai, U.A.E. Based on his educational background, professional training and over 20 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. Professional Qualifications of Primary Technical Person The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the independent estimation of the reserves, future production and income to render the audit conclusions of the report. Mr. Acuña, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1997, is a Managing Senior International Vice President and Board Member. He serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com. Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas, a member of the Association of International Petroleum Negotiators (AIPN) and the Society of Petroleum Engineers (SPE). In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. Mr. Acuña has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Acuña has recently taught various company reserves evaluation schools in Argentina, China, Denmark, Spain and the U.S.A. Mr. Acuña has participated in various capacities in reserves conferences such as being a panelist at Trinidad and Tobago’s Petroleum Conference, delivering the reserves evaluation seminar during IAPG convention in Mendoza, Argentina and chairing the first Reserves Evaluation Conference in the Middle East in Dubai, U.A.E. Based on his educational background, professional training and over 20 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-45 PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4- 10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein). Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein). Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. E-46 PETROLEUM RESERVES DEFINITIONS Page 2 Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. Reserves do not include quantities of petroleum being held in inventory. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows: Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). PROVED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows: Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein). Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. E-47 PETROLEUM RESERVES DEFINITIONS Page 3 (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. PROVED RESERVES (SEC DEFINITIONS) CONTINUED (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. PROVED RESERVES (SEC DEFINITIONS) CONTINUED (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-48 PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) and PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE), WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). DEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions) While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) and PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE), WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). DEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions) While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-49 PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES Page 2 Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe reserves. Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals which are open at the time of the estimate but which have not yet started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. UNDEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe reserves. Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals which are open at the time of the estimate but which have not yet started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. UNDEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E-50 EXHIBIT 15.a(iii) 9th March, 2017 JKB/kab/EL-16-211000/0841 Mr. Pietro Consonni Vice President Reserves Eni S.p.A. Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Mr Consonni, Proved Reserves Statement (SEC Rules) Certain Properties in Asia as of 31st December, 2016 This proved reserves audit has been conducted by Gaffney, Cline & Associates (GCA) at the request of Eni S.p.A. (Eni or “the Client”), in certain properties located in Asia. This third party report, completed on February 14, is intended for inclusion in Eni’s filings to the U.S. Securities and Exchange Commission (SEC). This statement relates specifically and solely to the subject matter as set out herein and is conditional upon the specified assumptions. The report must be considered in its entirety and must only be used for the purpose for which it was intended. On the basis of technical and other information made available to GCA concerning these properties, GCA has conducted an independent audit examination, as of 31st December, 2016, of the proved crude oil and natural gas reserves as prepared by Eni in certain properties in Asia, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal register. Reserves included herein are expressed as net reserves as represented by Eni. Eni has advised GCA that the net proved reserves of the properties that GCA reviewed represent 0.4 percent of Eni’s total net proved reserves as of December 31, 2016, on an oil- equivalent basis. GCA is not in a position to verify this statement as it was not requested to review Eni’s other oil and gas assets. Reserves Assessment This audit examination was based on reserves estimates and other information provided by Eni to GCA through 31st December, 2016, and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the audit process were resolved to GCA’s satisfaction. For the purposes of this assessment, Eni provided GCA with a set of data and presentation material that included production, reservoir studies and a JKB/kab/EL-16-211000/0841 Eni S.p.A. Registered in England, number 1122740, at the above address 1 Gaffney, Cline & Associates Limited Bentley Hall, Blacknest Alton, Hampshire GU34 4PU, UK Telephone: +44 (0)1420 525366Fax: +44 (0) 1420 525367 www.gaffney-cline.com JKB/kab/EL-16-211000/0841 9th March, 2017 Mr. Pietro Consonni Vice President Reserves Eni S.p.A.Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Mr Consonni, Proved Reserves Statement (SEC Rules) Certain Properties in Asiaas of 31st December, 2016 This proved reserves audit has been conducted by Gaffney, Cline & Associates (GCA) at the request of Eni S.p.A. (Eni or “the Client”), in certain properties located in Asia. This third party report, completed on February 14, is intended for inclusion in Eni’s filings to the U.S. Securities and Exchange Commission (SEC).This statement relates specifically and solely to the subject matter as set out herein and is conditional upon the specified assumptions. The report must be considered in its entirety and must only be used for the purpose for which it was intended.On the basis of technical and other information made available to GCA concerning these properties, GCA has conducted an independent audit examination, as of 31st December, 2016, of the proved crude oil and natural gas reserves as prepared by Eni in certain properties in Asia, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal register.Reserves included herein are expressed as net reserves as represented by Eni.Eni has advised GCA that the net proved reserves of the properties that GCA reviewed represent 0.4 percent of Eni’s total net proved reserves as of December 31, 2016, on an oil- equivalent basis. GCA is not in a position to verify this statement as it was not requested to review Eni’s other oil and gas assets. Reserves AssessmentThis audit examination was based on reserves estimates and other information provided by Eni to GCA through 31st December, 2016, and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the audit process were resolved to GCA’s satisfaction. For the purposes of this assessment, Eni provided GCA with a set of data and presentation material that included production, reservoir studies and aJKB/kab/EL-16-211000/0841 1 Eni S.p.A. Registered in England, number 1122740, at the above address E-51 selection of static and dynamic models. GCA audited the data provided for consistency and reasonableness. GCA also had discussions and meetings with Eni technical and commercial personnel. As part of the audit GCA developed independent production forecasts, employing decline curve analysis, material balance and type well methods, in addition to auditing and reviewing Eni’s static, dynamic and material balance models, to ensure consistency with the volumetric and other methods performed by Eni. The properties are all mature producing fields and it is GCA’s opinion that performance-based methods are appropriate for the purposes of estimating remaining recoverable volumes and reserves. GCA has also performed an economic limit test to establish the economic limit and commerciality of the properties in aggregate. Up to the economic limit, the GCA estimates of proved reserves for the reviewed properties are, in aggregate, reasonable and within 7 percent of Eni’s estimates, when compared on the basis of net equivalent barrels. The economic tests for the 31st December, 2016 net proved reserves were based on a flat oil price of US$35.38 per barrel, based on an unweighted average of the first day of the month realized prices over the preceding 12 months, as per SEC rules. Future capital costs were derived from development plans prepared by Eni for the fields. Recent historical operating expense data were used as the basis for operating cost projections. GCA has reviewed Eni’s estimates of capital and operating costs and considers them to be reasonable. Excluding abandonment costs, GCA has found that Eni has projected sufficient capital investments and operating expenses to economically produce the projected volumes. It is GCA’s opinion that the estimates of net proved reserves as of 31st December, 2016, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I). GCA concludes that the methodologies employed by Eni in the derivation of the proved reserves estimates are appropriate, and that the quality of the data relied upon and the depth and thoroughness of the reserves estimation process are adequate. Basis of Opinion This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation. In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by, or at the direction of, the Client, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose. The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience, engineering and production data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such Eni S.p.A. March, 2017 2 selection of static and dynamic models. GCA audited the data provided for consistency and reasonableness. GCA also had discussions and meetings with Eni technical and commercial personnel. As part of the audit GCA developed independent production forecasts, employing decline curve analysis, material balance and type well methods, in addition to auditing and reviewing Eni’s static, dynamic and material balance models, to ensure consistency with the volumetric and other methods performed by Eni. The properties are all mature producing fields and it is GCA’s opinion that performance-based methods are appropriate for the purposes of estimating remaining recoverable volumes and reserves. GCA has also performed an economic limit test to establish the economic limit and commerciality of the properties in aggregate. Up to the economic limit, the GCA estimates of proved reserves for the reviewed properties are, in aggregate, reasonable and within 7 percent of Eni’s estimates, when compared on the basis of net equivalent barrels. The economic tests for the 31st December, 2016 net proved reserves were based on a flat oil price of US$35.38 per barrel, based on an unweighted average of the first day of the month realized prices over the preceding 12 months, as per SEC rules. Future capital costs were derived from development plans prepared by Eni for the fields. Recent historical operating expense data were used as the basis for operating cost projections. GCA has reviewed Eni’s estimates of capital and operating costs and considers them to be reasonable. Excluding abandonment costs, GCA has found that Eni has projected sufficient capital investments and operating expenses to economically produce the projected volumes. It is GCA’s opinion that the estimates of net proved reserves as of 31st December, 2016, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I). GCA concludes that the methodologies employed by Eni in the derivation of the proved reserves estimates are appropriate, and that the quality of the data relied upon and the depth and thoroughness of the reserves estimation process are adequate. Basis of Opinion This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation. In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by, or at the direction of, the Client, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose. The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience, engineering and production data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such Eni S.p.A. 2March, 2017 E-52 opinions and statements are representative of prevailing physical and economic circumstances. There are numerous uncertainties inherent in estimating reserves, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any reserves estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post- date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed. GCA’s review and audit involved reviewing pertinent facts, interpretations and assumptions made by Eni or others in preparing estimates of reserves and resources. GCA performed procedures necessary to enable it to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied on, depth and thoroughness of the reserves estimation process, classification and categorization of reserves appropriate to the relevant definitions used, and reasonableness of the estimates. Definition of 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. 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. GCA is not aware of any potential changes in regulations applicable to these fields that could affect the ability of Eni to produce the estimated reserves. GCA has not undertaken a site visit and inspection because it was not requested. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations. Further, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation. This report has been prepared based on GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA is not these rights (including in a position to attest to property title or rights, conditions of Eni S.p.A. March, 2017 3 selection of static and dynamic models. GCA audited the data provided for consistency and reasonableness. GCA also had discussions and meetings with Eni technical and commercial personnel. As part of the audit GCA developed independent production forecasts, employing decline curve analysis, material balance and type well methods, in addition to auditing and reviewing Eni’s static, dynamic and material balance models, to ensure consistency with the volumetric and other methods performed by Eni. The properties are all mature producing fields and it is GCA’s opinion that performance-based methods are appropriate for the purposes of estimating remaining recoverable volumes and reserves. GCA has also performed an economic limit test to establish the economic limit and commerciality of the properties in aggregate. Up to the economic limit, the GCA estimates of proved reserves for the reviewed properties are, in aggregate, reasonable and within 7 percent of Eni’s estimates, when compared on the basis of net equivalent barrels. The economic tests for the 31st December, 2016 net proved reserves were based on a flat oil price of US$35.38 per barrel, based on an unweighted average of the first day of the month realized prices over the preceding 12 months, as per SEC rules. Future capital costs were derived from development plans prepared by Eni for the fields. Recent historical operating expense data were used as the basis for operating cost projections. GCA has reviewed Eni’s estimates of capital and operating costs and considers them to be reasonable. Excluding abandonment costs, GCA has found that Eni has projected sufficient capital investments and operating expenses to economically produce the projected volumes. It is GCA’s opinion that the estimates of net proved reserves as of 31st December, 2016, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I). GCA concludes that the methodologies employed by Eni in the derivation of the proved reserves estimates are appropriate, and that the quality of the data relied upon and the depth and thoroughness of the reserves estimation process are adequate. Basis of Opinion This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation. In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by, or at the direction of, the Client, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose. The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience, engineering and production data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such Eni S.p.A. 2March, 2017 E-53 environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties). Qualifications In performing this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector. GCA’s remuneration was not in any way contingent on the contents of this report. In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with Eni. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or related with the analysis performed, as part of the technical person primarily responsible for overseeing this audit are provided in Appendix II. this report. The qualifications of Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work. Notice This report was prepared for public disclosure in its entirety in conjunction with filings to the SEC by Eni S.p.A. Yours sincerely, Gaffney, Cline & Associates Project Manager Jeremy Berry, Global Business Development Manager Reviewed by Dr. John W Barker, Technical Director Appendices Appendix I Appendix II SEC Reserves Definitions Technical Qualifications of Person Responsible for Audit Eni S.p.A. March, 2017 4 environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties). Qualifications In performing this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector. GCA’s remuneration was not in any way contingent on the contents of this report. In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with Eni. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or related with the analysis performed, as part of this report. The qualifications of the technical person primarily responsible for overseeing this audit are provided in Appendix II. Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work. Notice This report was prepared for public disclosure in its entirety in conjunction with filings to the SEC by Eni S.p.A. Yours sincerely, Gaffney, Cline & Associates Project Manager Jeremy Berry, Global Business Development Manager Reviewed by Dr. John W Barker, Technical Director Appendices Appendix I SEC Reserves Definitions Appendix II Technical Qualifications of Person Responsible for Audit Eni S.p.A. March, 2017 4 E-54 Appendix I SEC Reserves Definitions Eni S.p.A. March, 2017 Appendix I SEC Reserves Definitions Eni S.p.A. March, 2017 E-55 U.S. SECURITIES AND EXCHANGE COMMISSION (SEC) MODERNIZATION OF OIL AND GAS REPORTING1 Oil and Gas Reserves Definitions and Reporting (a) Definitions (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) (ii) (iii) (iv) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); Same environment of deposition; Similar geological structure; and Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi- solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at (4) original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) category that can be expected to be recovered: Developed oil and gas reserves. Developed oil and gas reserves are reserves of any (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 1 Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7- 15-08] RIN 3235-AK00]. U.S. SECURITIES AND EXCHANGE COMMISSION (SEC) MODERNIZATION OF OIL AND GAS REPORTING1 Oil and Gas Reserves Definitions and Reporting (a) Definitions (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi- solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate 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. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 1 Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7- 15-08] RIN 3235-AK00]. E-56 (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) (ii) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) of a stratigraphic horizon known to be productive. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) remaining as of a given date and cumulative production as of that date. Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) (ii) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. E-57 (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) (B) (C) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; The acquisition of property rights or properties for the purpose of exploration or for the purpose of removing the oil or gas from such properties; further The construction, drilling, and production activities necessary to retrieve oil and gas the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: their natural reservoirs, including from (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. b. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) (B) Transporting, refining, or marketing oil and gas; Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be E-58 recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) (iii) (iv) (v) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations including the reservoir or subject project within comparisons to results in successful similar projects. that are clearly documented, Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) 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. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. reserves or resources is called The method of estimation of (19) probabilistic when the full range of values that could reasonably occur for each unknown parameter Probabilistic estimate. recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) 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. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter E-59 (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related the cost of oil and gas produced. equipment and facilities, they become part of Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) attributed. Proved area. The part of a property to which proved reserves have been specifically (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) (B) The area identified by drilling and limited by fluid contacts, if any, and Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Pro ved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the E-60 proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. Reasonable certainty. (24) If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) 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 In addition, there must exist, or there must be a development projects to known accumulations. reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain from undiscovered prospective accumulations). recoverable potentially resources resources (i.e., Reservoir. (27) formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. A porous and permeable underground (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in- situ combustion. proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmental entities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.(23) Proved properties. Properties with proved reserves.(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. E-61 (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) (ii) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph this section, or by other evidence using reliable technology establishing (a)(2) of reasonable certainty. (32) Unproved properties. Properties with no proved reserves. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves. E-62 Appendix II Technical Qualifications of Person Responsible for Audit Eni S.p.A. March, 2017 Appendix II Technical Qualifications of Person Responsible for Audit E-63 Statement of Qualification Dr. John W. Barker Dr. John Barker is a Technical Director with Gaffney, Cline & Associates (GCA) in the UK and was responsible for overseeing the preparation of the audit. Dr. Barker has over 30 years of international industry experience as a reservoir engineer, both in major oil companies and in consulting. He has worked on conventional oil, gas and gas condensate fields of all types in many different parts of the world, including naturally fractured reservoirs and enhanced oil recovery projects, and also on some tight gas and heavy oil fields. He is an acknowledged expert in all aspects of reservoir simulation and has extensive experience in estimation, auditing and reporting of reserves and resources. Dr. Barker is a former Executive Editor of the SPE Reservoir Engineering journal, and has authored 34 technical publications, of which 20 have appeared in peer reviewed journals. He holds an M.A. in Mathematics from the University of Cambridge and a Ph.D. in Applied Mathematics from the California Institute of Technology. He is a member of the Society of Petroleum Engineers and of the Society of Petroleum Evaluation Engineers. Eni S.p.A. March, 2017 Statement of Qualification Dr. John W. Barker Dr. John Barker is a Technical Director with Gaffney, Cline & Associates (GCA) in the UK and was responsible for overseeing the preparation of the audit. Dr. Barker has over 30 years of international industry experience as a reservoir engineer, both in major oil companies and in consulting. He has worked on conventional oil, gas and gas condensate fields of all types in many different parts of the world, including naturally fractured reservoirs and enhanced oil recovery projects, and also on some tight gas and heavy oil fields. He is an acknowledged expert in all aspects of reservoir simulation and has extensive experience in estimation, auditing and reporting of reserves and resources. Dr. Barker is a former Executive Editor of the SPE Reservoir Engineering journal, and has authored 34 technical publications, of which 20 have appeared in peer reviewed journals. He holds an M.A. in Mathematics from the University of Cambridge and a Ph.D. in Applied Mathematics from the California Institute of Technology. He is a member of the Society of Petroleum Engineers and of the Society of Petroleum Evaluation Engineers. E-64

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