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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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177
177
182
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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;
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•
•
•
•
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.
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• 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.
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Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) and
with other insurance partners in order to limit possible economic impacts associated with damages to both
third parties and the environment occurring in case of both onshore and offshore accidents. The main part
of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured
making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that
provides its members with a broad coverage of insurance services tailored to the specific requirements of
oil and energy companies. In addition, Eni uses insurance companies who it believes are established in the
marketplace. Insured liabilities vary depending on the nature and type of circumstances; however,
underlying amounts represent significant shares of
the plafond granted by insuring companies. In
particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of
cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up
to $1.2 billion for offshore events and $1.4 billion for onshore plants (refineries). These are complemented
by insurance policies that cover owners, operators and renters of vessels with the following maximum
amounts: $1,250 million for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment
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
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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
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Directive (MCP Directive) regulates pollutant emissions from the combustion of fuels in plants with a rated
thermal input equal to or greater than 1 megawatt (MWth) and less than 50 MWth. The MCP Directive is a
part of the Clean Air Policy Package 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
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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.
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•
•
•
•
•
•
•
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.
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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.
•
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The OSR-JIP carried out specific projects dealing with exercise planning, in situ burning, dispersants
advocacy-subsea, efficacy-post spill monitoring, upstream risk assessment 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.
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In order to strengthen this engagement and with a forward looking perspective, in 2015 Eni launched a
strategic internal Program on Climate Change aimed at developing a medium and long term roadmap able
to drive Eni towards a low carbon future. In line with this Program and the abovementioned strategy, Eni
published its targets and established the new “Energy Solutions” business line in order to integrate
traditional energy sources with the production of energy from renewable sources.
In particular, by 2025 we have confirmed three main commitments focused on improving our GHG
performance: to reduce by -43% vs 2014 the GHG emission intensity of our production, to reach zero
routine gas flaring and to abate by 80% the fugitive emissions coming from our Upstream business.
In addition to these operational actions and commitments, Eni actively participates in primary
international climate initiatives. In particular, in 2016 Eni contributed to further develop the “Oil and Gas
Climate Initiative” (OGCI), a voluntary CEO led initiative launched in 2014 along with other companies in
the oil&gas sector (currently, the ten OGCI member companies represent about 25% of global HC
production). On November 4, 2016, during a high-level event in London, OGCI CEOs announced an
investment of $1 billion over the next ten years to develop and accelerate the deployment of innovative low
emissions technologies able to improve the management of GHG emissions and contain climate impacts of
the Oil&Gas sector.
In 2016, Eni has continued its efforts in two international Public-Private Initiatives focused on
operational efficiency: the “zero routine gas flaring at 2030” program of the World Bank’s “Global Gas
Flaring reduction partnership” and the “Clean Air and Climate initiative - Oil & Gas Methane
Partnership”, aimed at reducing methane emissions in the oil&gas value chain. About this important topic,
in October 2016 was published the first report of the initiative, with details and information on Eni
methane LDAR monitoring campaign during the first year of the initiative.
Thanks to its climate strategy and the ambitious targets for the future, in 2016 Eni has been recognized
by the CDP as a global leader for its actions and strategies in response to climate change and was included
in the prestigious A-list of CDP. Eni was the only oil & gas major achieving this high recognition.
Another acknowledgment of Eni’s climate leadership was the invitation to take part in the works of
the Task Force on Climate Related 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
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dioxide emissions. The EU-ETS Directive states that any operator, who produces GHG emissions in excess
of the amounts allowed on the basis of the national allocation plan, is required to acquire allowances on
the market to cover the excess emissions or to pay a penalty.
Currently, Eni participates in the ETS with 41 plants, mostly located in Italy, which collectively
represent 49% of all direct GHG emissions generated by Eni’s plants worldwide. Due to stricter allocation
rules in the third phase (2013-2020) of the Emissions Trading Scheme, Eni has been receiving a lower
amount of free allowances in comparison with the second phase (2008-2012). As a consequence, in the next
four-year period (2017-2020), Eni will buy on the market an amount of allowances to cover GHG
emissions of its industrial plants. The large majority of the deficit is concentrated in the power sector due
to European allocation rules.
For additional information on Eni’s climate strategy and GHG management, please refer to the latest
Eni’s Corporate Sustainability Report (“Enifor”) or to the Eni’s CDP climate change questionnaire
response, both published on Eni’s website (www.eni.com).
Regulation of Eni’s businesses
Overview
The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or
EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and
uncertainties that could cause the actual results to differ materially from those in such forward-looking
statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of
such legal and regulatory changes or proposals, which may be affected by political and other developments.
Regulation of exploration and production activities
Eni’s exploration and production activities are conducted in many countries and are therefore subject
to a broad range of legislation and regulations. These cover virtually all aspects of exploration and
production activities, including matters such as license acquisition, production rates, royalties, pricing,
environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases,
licenses and contracts under which these oil&gas interests are held vary from country to country. These
leases, licenses and contracts are generally granted by or entered into with a government entity or state
company and are sometimes entered into with private property owners. These arrangements usually take
the form of licenses or production sharing agreements. See “Regulation of the Italian hydrocarbons
industry” and “Environmental matters” for a description of the specific aspects of the Italian regulation
and of environmental regulation concerning Eni’s exploration and production activities. Licenses (or
concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license,
the holder bears the risk of exploration, development and production activities and provides the financing
for these operations. In principle, the license holder is entitled to all production minus any royalties that are
payable in-kind. A license holder is generally required to pay production taxes or royalties, which may be in
cash or in-kind. 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.
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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.
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Eni’s management is monitoring these issues with a view of assessing any possible financial or
economic impact associated with the enacted measures and their evolution. Management also believes that
these regulations will increase competition in the wholesale natural gas market in Italy leading to further
margin pressures.
Law Decree No. 1 of January 24, 2012 for new liberalization measures in Italy
Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so-called Liberalization
Decree was converted to Law No. 20 on March 24, 2012. This law aimed to:
•
•
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.
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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.
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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
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minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil
security of supply through a reliable mechanism to assure the physical access to oil emergency and specific
stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the
Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and
transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific
and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and
commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain. As of
December 31, 2016, 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
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competitors that restricts competition within Italy and prohibits any abuse of a dominant position within
the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a
limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust
Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for
consumers.
Property, plant and equipment
Eni has freehold and leasehold interests in real estate in numerous countries throughout the world.
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).
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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.
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We expect to increase our hydrocarbons production at an average rate of 3% across the 2017-2020 plan
period. This growth target factors in the effects associated with our planned disposals. For 2017, we expect
a production growth of approximately 5%. This grow will be fuelled organically by 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
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(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
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power companies and resellers, and to match our minimum contractual take with the dimension of our
addressable market. The renegotiation strategy is subject to the constraints dictated by availability of the
contractual windows. Management believes that the outcome of those renegotiations is uncertain in respect
of both the amount of the economic benefits that will ultimately be achieved and the timing of recognition
in profit. In case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration
procedure could be commenced to solve the commercial dispute. Furthermore, Eni’s suppliers may file a
counterclaim to dismiss Eni’s request for a price review or renewed contractual terms. These possible
developments increase the risks and uncertainties relating the outcome of those renegotiations. Therefore,
future results of the 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”.
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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.
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Capital expenditure plans
Over the next four years, the Company plans to invest €31.6 billion, excluding capex associated with
the disposal plan, to support continued organic growth in oil&gas production; approximately 86% of
planned capital expenditures is expected to be directed to the Exploration & Production segment. Eni’s
capital expenditure program is reflective of a lower oil price environment and of uncertainties 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,
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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
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2014 he was a member of the anticorruption working group for the B20, coordinator for activities relating
to the development of an international regulatory framework for the B20 held in Russia in 2013 and
leading expert for the 2014 B20 in Australia. Massimo Mantovani has been Eni’s Chief Midstream Gas &
Power Officer since 17 October 2016.
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
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Director. In 2008, following the centralization of the Eni’s legal function into one Legal Department, he
took on responsibility for the legal assistance to the company’s activities outside Europe. In 2013 he was
appointed Executive Vice President International Business Legal Area and, in 2015, he became Executive
Vice President International and Finance Legal Affairs of Eni, with a strong exposure to international
matters, 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
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Persian Gulf. In this period, he also taught at the IFP School and published several technical papers,
including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head
of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to
2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as
Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From
2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed Senior Vice
President Non Operated Business Performance and Stranded Resources Valorization. Since November 1,
2015, he has been Executive Vice President Energy Solutions Department.
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
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the following three years, he was engaged in consolidating and aligning the company’s business and
financial processes with those of Eni and rationalising the company structure. In 2011 he was part of the
project for the creation of Eni Trading & Shipping SpA, becoming its Senior Vice President for Operations
& Control. From the end of 2012 until July 2015 he was Senior Vice President Credit and in August 2015
he was appointed Senior Vice President for Integrated Risk Management. Since September 12, 2016 he
reports directly to the Chief Executive Officer in his role as Executive Vice President Integrated Risk
Management.
Compensation
Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of
the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of
Directors, which considers relevant proposals made by the Compensation Committee after consultation
with the Board of Statutory Auditors.
Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter of Legislative
Decree No. 58 of February 24, 1998 and Article 84-quater of Consob Decision No. 11971 of May 14, 1999,
and subsequent modifications) and in line with the Corporate Governance Code recommendations for
Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting
advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy
Guidelines adopted for Directors and other Managers with strategic responsibilities5.
The main elements of the 2017 remuneration policy and of the compensation paid in 2016 to
Directors, Statutory Auditors, CEO and General Manager and other Managers with strategic
responsibilities, are described below.
2017 Remuneration Policy Guidelines
This chapter contains the Remuneration Guidelines for the new 2017-2020 term, approved by the
Board of Directors on February 28, 2017 for the Directors who will be appointed at the Shareholders’
Meeting on April 13, 2017. The new Board of Directors will retain the prerogative to determine, specific
remuneration for the exercise of delegated powers and for participating on Board Committees, based on a
proposal by the Compensation Committee. The Shareholders’ Meeting will retain the prerogative to
approve the Share-based Variable Incentive Plans.
Furthermore, the Remuneration Guidelines below for Directors in office until April 13, 2017 are also
briefly outlined. These were already extensively discussed in the Remuneration Report 2016 and reflect the
decisions made by the Board of Directors on May 28, 2014 for the 2014-2017 term.
Policies For Directors During The 2017-2020 Term Of Office
The main novelty of the Remuneration Policy in the new term of office is the comprehensive review of
the variable incentive scheme for the Chief Executive Officer and General Manager and for all other Senior
Managers in order to simplify the incentive scheme’s overall architecture (which will be broken down into
two incentive plans instead of
three) and further align performance objectives with shareholder
expectations. More specifically, the new incentive scheme provides for the introduction of:
•
•
a Short-Term Monetary Plan with the deferral of a portion of the accrued bonus, which will start
from the assignment of the 2017 objectives with the first payment in 2018, to replace the previous
Annual Monetary Incentive and Deferred Monetary Incentive plans.
a Long-Term Performance Share Plan 2017-2019, with first attribution in 2017, to replace the
previous Long-Term Monetary Incentive Plan (subject to approval by the Shareholders’ Meeting
on April 13, 2017).
(5)
Those persons who have the power and responsibility, directly or indirectly, for planning, directing and controlling Eni fall under the definition of
“Managers with strategic responsibilities”, pursuant to Consob regulations. Eni Managers with strategic responsibilities, other than Directors and
Statutory Auditors, are those who sit on the Management Committee and, in any case, those who report directly to the Chief Executive Officer.
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For the Chairman and the Non-Executive Directors, adjustments are proposed for the remuneration
envisaged for delegated powers and for participating on Board Committees compared with median levels in
the reference markets.
Market references and peer group
For the Chief Executive Officer and General Manager, the positioning of the Company’s remuneration
is assessed by comparing similar roles only in the international Oil & Gas sector, with regard to upstream
activities in particular, and in line with the company’s strategy to increase its focus on the business. More
specifically, the comparator group has been expanded to include the main listed companies in the Oil &
Gas sector, which are Eni competitors at the international
level and possess comparable business
characteristics (Anandarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell,
Statoil and Total).
This panel also constitutes the Peer Group used for the relative comparison of Eni performance in the
new Long-Term Performance Share Plan.
For the Chairman and the Non-Executive Directors, the positioning of remuneration is assessed by
comparing similar roles in the Top Italy Panel, composed of the main companies listed on the FTSE MIB
(Assicurazioni Generali, Atlantia, Enel, Intesa Sanpaolo, Leonardo-Finmeccanica, Luxottica, Mediaset,
Mediobanca, Poste Italiane, Snam, Terna, TIM, Unicredit).
For Managers with strategic responsibilities, the positioning of remuneration is assessed by comparing
roles with the same level of managerial responsibility and complexity in national and international panels
of companies in the industrial sector.
General principle of clawback
Clawback mechanisms will be adopted, through a specific regulation proposed by the Compensation
Committee and approved by the Board of Directors, allowing the variable remuneration components
already paid and/or granted to be reclaimed, or those subject to deferral to be withheld, where their
achievement was based on data that was subsequently proven to be manifestly misstated, or allowing the
recoupment of all the incentives for the year (or years) in which subsequent checks confirm the fraudulent
alteration of the results data used to obtain the right to incentives, and/or the commission of serious and
deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to
the employment and trust relationship, without prejudice to any other action permitted by law and
regulations to protect the interests of the Company. The regulation provides that the activation of
recoupment claims (or revocation of incentives awarded but not yet paid) must take place, once the checks
have been completed, within three years of payment (or award) in the case of error, and within five years in
the case of fraud.
Chairman of the Board of Directors
Remuneration for the delegated powers
Remuneration will be defined in line with the decisions taken by the Shareholders’ Meeting on 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:
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•
•
•
for the Control and Risk Committee, annual remuneration consists of €70,000 for the Chairman
and €50,000 for the other members;
for the Compensation Committee and the Sustainability and Scenarios Committee, the annual
remuneration consists of €50,000 for the Chairman and €35,000 for the other members;
for the Nomination Committee, the annual remuneration consists of €40,000 for the Chairman
and €30,000 for the other members.
Payments due in the event of termination of office or employment
No specific severance payments are provided for the Non-Executive Directors, nor do any agreements
exist for indemnities in the case of early termination of office.
Chief Executive Officer and General Manager
The Policy Guidelines for the Chief Executive Officer and General Manager take into account the
specific delegated powers granted in accordance with the By-laws, the instructions contained in the chapter
“Purpose and general principles of the Remuneration Policy” as well as the remuneration levels and best
practices in the reference Oil & Gas panel.
Fixed remuneration
Fixed remuneration (FR) will be set by the new Board of Directors based on a proposal of the
Compensation Committee in relation to the delegated powers and positions held, taking into account the
median levels in the reference market. Fixed remuneration includes the remuneration for Directors
established by the Shareholders’ Meeting on April 13, 2017, as well as any compensation that may be due
for participating on the Board of Directors of subsidiaries or associated companies.
Variable incentive plans
Short-Term Monetary Plan with deferral
The new Short-Term Monetary Plan with deferral of a portion of the accrued bonus brings together
the previous Annual Monetary Incentive and Deferred Monetary Incentive plans.
Compared with the previous Plans, the performance scales have been extended to include achievement
of results that are above or far above the target levels.
In this Plan, a portion of the incentive is paid annually and a portion is deferred for a three-year
period, as described below.
The Short-Term Monetary Plan with deferral is linked to the achievement of the 2017 objectives
approved by the Board of Directors on February 28, 2017. These objectives keep the structure focused on
the essential goals consistent with the guidelines outlined in the Strategic Plan and balanced against the
interests of the various stakeholders, in terms of economic and financial results (25%), operating results
and sustainability of the economic performance (25%), environmental sustainability and human capital
(25%), efficiency and financial strength (25%). The value of each objective, at target performance level, is
aligned with the budgeted value.
Each objective is measured in accordance with a performance scale of 70 to 150 points (target=100), in
relation to the weight assigned to each target (below 70 points, the performance of each target is considered
to be zero). For the purposes of the incentive award, the minimum overall performance is 85 points. This
Plan provides for remuneration calculated with reference to a minimum (performance=85), target
(performance=100) and maximum (performance=150) multiplier, equal respectively to 85%, 100% and
150% to be applied to the target incentive, as determined by results achieved by Eni over the previous year.
Total incentive (TI) is calculated using the following formula:
TI = FR x % ITarget x Multiplier
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Where “ITarget” is the incentive percentage at target performance level, which is set at 150% of total
fixed remuneration for the Chief Executive Officer.
The Plan conditions state that the total incentive is divided into 2 portions.
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.
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Item 9. THE OFFER AND THE LISTING
Offer and listing details
The principal trading market for the ordinary shares of Eni SpA (Eni), without indication of par value
(the “Shares”), is the Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, which is
the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa
Italiana SpA (Borsa Italiana). Eni’s American Depositary Receipts (ADRs), each representing two Shares,
are listed on the New York Stock Exchange.
The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs
on the New York Stock Exchange, respectively. See “Item 3 – Key information – Exchange rates” regarding
applicable exchange rates during the periods indicated below.
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
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MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the
Italian Stock Exchange. The constituents of the FTSE MIB are selected based on market capitalization of
free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free
float and foreign ownership limits. Since June 1, 2009, the FTSE MIB is the principal indicator used to
track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded
on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are the first largest
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.
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Directors’ issues
Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary
management of the Company and, in particular, the Board has the power to perform all acts it deems
advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts
that the law or Eni’s By-laws reserve to the Shareholders’ Meeting.
If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one
from among its members.
The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers
for the management of the Company, with the exception of those powers that cannot be delegated in
accordance with current legislation and those retained exclusively by the Board of Directors on matters
regarding major strategic, operational and organizational decisions.
According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify
and promote integrated projects and international agreements of strategic importance.
The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of
revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive
Officer at the same time.
The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief
Executive Officer, may confer powers for individual acts or categories of acts on other members of the
Board of Directors.
In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors
must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the
event of a tie, the person who chairs the meeting shall have a casting vote.
For further information on Directors’ duties and responsibilities and, in particular, the role of the
Chairman see “Item 6 – Board of Directors’ duties and responsibilities”.
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.
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shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In
any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding
opinion from the Control and Risk Committee is required.
Moreover, to ensure compliance with the procedures envisaged by the above mentioned MSG,
Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in
which they explain 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.
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The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise
as per Article 1, letter w-quater.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.
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As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable
by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities
represented by the American Depositary Shares (ADSs), 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).
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Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the
Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax
Representative, according to the Italian tax law.
Inheritance and gift tax
Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of
November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the
transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no
consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:
(a) 4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the
transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary);
(b) 6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the
tax on the value exceeding €100,000 (per beneficiary);
(c) 6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct
affinity, as well as to persons related by collateral affinity up to the third degree; and
(d) 8 per cent: in all other cases.
If the transfer is made in favor of persons with severe disabilities, the tax applies on the value
exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001
for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains
subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In
particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift,
the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.
United States taxation
The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as
defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S.
Holders that hold Shares or ADSs as capital assets, and does not 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.
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The table below summarizes the Group principal contractual obligations as of the balance sheet date,
shown on an undiscounted basis.
Maturity year
(€ 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
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Other information about financial instruments
The carrying amount of financial instruments and the relevant economic and equity effect as of and
for the years ended December 31, 2015 and 2016 consisted of the following:
2015
2016
(€ 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
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The offsetting of financial assets and liabilities related to: (i) for €1,281 million (€2,410 million at
December 31, 2015) 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
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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
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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:
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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
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fauna of the industrial port of Porto Torres. The proceeding continues before the Prosecutor of Sassari. In
February 2013, the Prosecutor of Sassari has notified the conclusion of preliminary investigations and
requested a new imputation for negligent behaviour instead of illicit conduct. In the conclusions of the
preliminary hearing, the GUP of Sassari dismissed the accusation because of the statute of limitations. The
Public Prosecutor filed an appeal before a Third Instance Court. After a hearing on a question of
constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the
Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the
Constitutional Court.
(vi) Syndial SpA 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
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million of lower profitability due to the reduced competitive position on the marketplace. With a decision
dated May 23, 2014, the Court of Rome declared the connection with a judgment previously proposed by
Alitalia itself before the Court of Milan against other oil companies participating to an alleged cartel
agreement. The case was thus summed up by Alitalia before the Court of Milan. The proceedings is still
pending before the First Degree Court. Eni accrued a risk provision against this proceeding.
(ii) Eni’s arbitration with GasTerra.
In 2013, Eni initiated an arbitration against GasTerra, as part of
a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for
the gas supplied in the 2012-2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional
price, which was lower than the previous price, until the definition of a new contractual price based on an
arrangement between parties or an arbitration award. An arbitration award of June 23, 2016 dismissed
Eni’s claim for price revision, without however determining a new price applicable in the relevant period.
GasTerra considers that, by dismissing Eni’s claim, the award restored the original contract price, based on
which GasTerra now claims an additional amount to be paid by Eni which corresponds to the difference
between the provisional price and the contractual price. Eni, relying also on the opinion of its external
consultants, does not agree with GasTerra’s interpretation and regards GasTerra claim groundless.
However, GasTerra, based on its own interpretation, commenced arbitration proceedings and obtained
from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV, for
the alleged trade receivable due by Eni (equal to €1.01 billion). This measure, which was granted after a
summary review only and without Eni being heard, does not prejudice the outcome on the 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,
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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
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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
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decision, on March 13, 2014, the Eni legal team requested to the Public Prosecutor to dismiss the
proceeding. The Prosecutor’s Office filed a request for dismissal of all the natural persons, and, on 5
January 2017, the judge for preliminary investigations who issued the relevant decree granted the
above-mentioned filing request. A similar measure is expected for Eni that was involved at the same
proceeding pursuant to Legislative Decree no. 231/01.
(iv) Block OPL 245 — 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
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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
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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
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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
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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
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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.
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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
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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.
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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.
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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.
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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”.
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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
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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.
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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.
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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.
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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;
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•
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.
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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;
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•
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;
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•
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.
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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
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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:
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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:
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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.
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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.
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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
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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
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Eni S.p.A. – Third Party
February 27, 2017
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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.
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Eni S.p.A. – Third Party
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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
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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
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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
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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.
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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.
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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
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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
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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
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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
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(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
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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.
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(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.
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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.
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