20-F 1 sj0415eni20f2014.htm

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
OR
|  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2014
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 |  | Name of each exchange on which registered
Shares American Depositary Shares |  | New York Stock Exchange* New York Stock Exchange
(Which represent the right to receive two Shares) |  | * Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Ordinary shares of euro 1.00 each 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 (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 have 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 if 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 17 |  |  | Item 18 |

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes |  |  | No |

##### TABLE OF CONTENTS

| I | Page
Certain defined terms | I | ii
Presentation of financial and other information | I | ii
Statements regarding competitive position | I | ii
Glossary | I | iii
Abbreviations and conversion table | I | vi

II | I | I | III | I

PART I | I |  | I |
Item 1. | I | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS | I | 1
Item 2. | I | OFFER STATISTICS AND EXPECTED TIMETABLE | I | 1
Item 3. | I | KEY INFORMATION | I | 1
I | I | Selected Financial Information | I | 1
I | I | Selected Operating Information | I | 4
I | I | Exchange Rates | I | 5
I | I | Risk factors | I | 6
Item 4. | I | INFORMATION ON THE COMPANY | I | 28
I | I | History and development of the Company | I | 28
I | I | BUSINESS OVERVIEW | I | 32
I | I | Exploration & Production | I | 32
I | I | Gas & Power | I | 61
I | I | Refining & Marketing | I | 67
I | I | Chemicals | I | 73
I | I | Engineering & Construction | I | 75
I | I | Corporate and Other activities | I | 77
I | I | Research and development | I | 78
I | I | Insurance | I | 79
I | I | Environmental matters | I | 80
I | I | Regulation of Eni’s businesses | I | 86
I | I | Property, plant and equipment | I | 91
I | I | Organizational structure | I | 91
Item 4A. | I | UNRESOLVED STAFF COMMENTS | I | 91
Item 5. | I | OPERATING AND FINANCIAL REVIEW AND PROSPECTS | I | 92
I | I | Executive summary | I | 92
I | I | Critical accounting estimates | I | 95
I | I | 2012-2014 Group results of operations | I | 99
I | I | Liquidity and capital resources | I | 113
I | I | Recent developments | I | 118
I | I | Management's expectations of operations | I | 119
Item 6. | I | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES | I | 128
I | I | Directors and Senior Management | I | 128
I | I | Compensation | I | 135
I | I | Board practices | I | 149
I | I | Employees | I | 158
I | I | Share ownership | I | 160
Item 7. | I | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS | I | 161
I | I | Major Shareholders | I | 161
I | I | Related party transactions | I | 161
Item 8. | I | FINANCIAL INFORMATION | I | 162
I | I | Consolidated Statements and other financial information | I | 162
I | I | Significant changes | I | 162
Item 9. | I | THE OFFER AND THE LISTING | I | 163
I | I | Offer and listing details | I | 163
I | I | Markets | I | 164
Item 10. | I | ADDITIONAL INFORMATION | I | 166
I | I | Memorandum and Articles of Association | I | 166
I | I | Material contracts | I | 172
I | I | Exchange controls | I | 172
I | I | Taxation | I | 172
I | I | Documents on display | I | 176
Item 11. | I | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | I | 178
Item 12. | I | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | I | 181
12A. | I | Debt securities | I | 181
12B. | I | Warrants and rights | I | 181
12C. | I | Other securities | I | 181
12D. | I | American Depositary Shares | I | 181
II | I | I | I | I
PART II | I | I | I | I
Item 13. | I | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES | I | 183
Item 14. | I | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | I | 183
Item 15. | I | CONTROLS AND PROCEDURES | I | 183
Item 16. | I | I | I | II
16A. | I | Board of Statutory Auditors financial expert | I | 184
16B. | I | Code of Ethics | I | 184
16C. | I | Principal accountant fees and services | I | 184
16D. | I | Exemptions from the Listing Standards for Audit Committees | I | 185
16E. | I | Purchases of equity securities by the issuer and affiliated purchasers | I | 185
16F. | I | Change in Registrant’s Certifying Accountant | I | 186
16G. | I | Significant Differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual | I | 186
16H. | I | Mine safety disclosure | I | 189
PART III I | I | I | I | II
Item 17. | I | FINANCIAL STATEMENTS | I | 190
Item 18. | I | FINANCIAL STATEMENTS | I | 190
Item 19. | I | EXHIBITS | I | 190

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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 IFRS 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", "€" and "EUR" 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 Eni’s business activities: Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction, Chemicals and Other activities.

References to Versalis or Chemicals 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.

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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.

Financial terms |  |
Leverage |  | A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, see "Item 5 – Financial Condition".
Net borrowings |  | Eni evaluates its financial condition by reference to "net borrowings", which is a non-GAAP measure. Eni calculates net borrowings as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, see "Item 5 – Financial condition".
TSR (Total Shareholder Return) |  | Management uses this measure to asses the total return of the Eni share. It is calculated on a yearly basis, keeping account of changes in prices (beginning and end of year) and dividends distributed and reinvested at the ex-dividend date.
Business terms |  |
AEEGSI (Authority for Electricity Gas and Water) formerly AEEG (Authority for Electricity and Gas) |  | 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 |  | Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
BOE |  | Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a certain coefficient (see "Conversion Table").
Concession contracts |  | Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state.
Condensates |  | Condensates is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Consob |  | The National Commission for listed companies and the stock exchange of Italy.
Contingent resources |  | Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
Conversion capacity |  | Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units.

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Conversion index |  | Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
Deep waters |  | Waters deeper than 200 meters.
Development |  | Drilling and other post-exploration activities aimed at the production of oil and gas.
Enhanced recovery |  | Techniques used to increase or stretch over time the production of wells.
EPC |  | Engineering, Procurement and Construction.
EPCI |  | Engineering, Procurement, Construction and Installation.
Exploration |  | Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.
FPSO |  | Floating Production Storage and Offloading System.
FSO |  | Floating Storage and Offloading System.
Infilling wells |  | Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
LNG |  | Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas.
LPG |  | Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
Margin |  | The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
Mineral Potential |  | (Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage.
Mineral Storage |  | According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
Modulation Storage |  | According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings in demand.
Natural gas liquids (NGL) |  | Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
Network Code |  | A code containing norms and regulations for access to, management and operation of natural gas pipelines.
Over/Under lifting |  | Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations.
Possible reserves |  | Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves |  | Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Primary balanced refining capacity |  | Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
Production Sharing Agreement (PSA) |  | Contract in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating 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

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|  | perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "cost oil" is used to recover costs borne by the contractor and "profit oil" is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.
Proved reserves |  | Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves |  | Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reserve life index |  | Ratio between the amount of proved reserves at the end of the year and total production for the year.
Reserve replacement ratio |  | Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.
Ship-or-pay |  | Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
Strategic Storage |  | According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
Take-or-pay |  | Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
Upstream/Downstream |  | The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.

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ABBREVIATIONS

mmCF | = | million cubic feet |  | ktonnes | = | thousand tonnes
BCF | = | billion cubic feet |  | mmtonnes | = | million tonnes
mmCM | = | million cubic meters |  | MW | = | megawatt
BCM | = | billion cubic meters |  | GWh | = | gigawatthour
BOE | = | barrel of oil equivalent |  | TWh | = | terawatthour
KBOE | = | thousand barrel of oil equivalent |  | /d | = | per day
mmBOE | = | million barrel of oil equivalent |  | /y | = | per year
BBOE | = | billion barrel of oil equivalent |  | E&P | = | the Exploration & Production segment
BBL | = | barrels |  | G&P | = | the Gas & Power segment
KBBL | = | thousand barrels |  | R&M | = | the Refining & Marketing segment
mmBBL | = | million barrels |  | E&C | = | the Engineering & Construction segment
BBBL | = | billion barrels |  |  |  |

CONVERSION TABLE

1 acre | = | 0.405 hectares |  |
1 barrel | = | 42 U.S. gallons |  |
1 BOE | = | 1 barrel of crude oil | = | 5,492 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 0.00643 barrels of oil equivalent |  |
1 kilometer | = | approximately 0.62 miles |  |
1 short ton | = | 0.907 tonnes | = | 2,000 pounds
1 long ton | = | 1.016 tonnes | = | 2,240 pounds
1 tonne | = | 1 metric ton | = | 1,000 kilograms
|  |  | = | approximately 2,205 pounds
1 tonne of crude oil | = | 1 metric ton of crude oil | = | approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees)

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB). The tables below present Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2010, 2011, 2012, 2013 and 2014.

The selected historical financial data presented herein are derived from Eni’s Consolidated Financial Statements included in Item 18.

All such data should be read in connection with the Consolidated Financial Statements and the related notes thereto included in Item 18.

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| Year ended December 31,

| 2010 |  | 2011 |  | 2012 |  | 2013 |  | 2014

| (euro million except data per share and per ADR)

CONSOLIDATED PROFIT STATEMENT DATA |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from continuing operations |  | 96,617 |  |  | 107,690 |  |  | 127,109 |  |  | 114,697 |  |  | 109,847 |
Operating profit by segment from continuing operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration & Production |  | 13,866 |  |  | 15,887 |  |  | 18,470 |  |  | 14,868 |  |  | 10,766 |
Gas & Power |  | 896 |  |  | (326 | ) |  | (3,125 | ) |  | (2,967 | ) |  | 186 |
Refining & Marketing |  | 149 |  |  | (273 | ) |  | (1,264 | ) |  | (1,492 | ) |  | (2,229 | )
Chemicals |  | (86 | ) |  | (424 | ) |  | (681 | ) |  | (725 | ) |  | (704 | )
Engineering & Construction |  | 1,302 |  |  | 1,422 |  |  | 1,453 |  |  | (98 | ) |  | 18 |
Other activities |  | (1,384 | ) |  | (427 | ) |  | (300 | ) |  | (337 | ) |  | (272 | )
Corporate and financial companies |  | (361 | ) |  | (319 | ) |  | (341 | ) |  | (399 | ) |  | (246 | )
Impact of unrealized intragroup profit elimination and other consolidation adjustments (1) |  | 1,100 |  |  | 1,263 |  |  | 996 |  |  | 38 |  |  | 398 |
Operating profit from continuing operations |  | 15,482 |  |  | 16,803 |  |  | 15,208 |  |  | 8,888 |  |  | 7,917 |
Net profit attributable to Eni from continuing operations |  | 6,252 |  |  | 6,902 |  |  | 4,200 |  |  | 5,160 |  |  | 1,291 |
Net profit (loss) attributable to Eni from discontinued operations |  | 66 |  |  | (42 | ) |  | 3,590 |  |  |  |  |  |  |
Net profit attributable to Eni |  | 6,318 |  |  | 6,860 |  |  | 7,790 |  |  | 5,160 |  |  | 1,291 |
Data per ordinary share (euro) (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- basic |  | 4.27 |  |  | 4.64 |  |  | 4.20 |  |  | 2.45 |  |  | 2.19 |
- diluted |  | 4.27 |  |  | 4.64 |  |  | 4.20 |  |  | 2.45 |  |  | 2.19 |
Net profit attributable to Eni basic and diluted from continuing operations |  | 1.72 |  |  | 1.90 |  |  | 1.16 |  |  | 1.42 |  |  | 0.36 |
Net profit attributable to Eni basic and diluted from discontinued operations |  | 0.02 |  |  | (0.01 | ) |  | 0.99 |  |  |  |  |  |  |
Net profit attributable to Eni basic and diluted |  | 1.74 |  |  | 1.89 |  |  | 2.15 |  |  | 1.42 |  |  | 0.36 |
Data per ADR ($) (2) (3) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- basic |  | 11.33 |  |  | 12.92 |  |  | 10.79 |  |  | 6.51 |  |  | 5.82 |
- diluted |  | 11.33 |  |  | 12.92 |  |  | 10.79 |  |  | 6.51 |  |  | 5.82 |
Net profit attributable to Eni basic and diluted from continuing operations |  | 4.56 |  |  | 5.32 |  |  | 2.98 |  |  | 3.77 |  |  | 0.96 |
Net profit attributable to Eni basic and diluted from discontinued operations |  | 0.05 |  |  | (0.03 | ) |  | 2.54 |  |  |  |  |  |  |
Net profit attributable to Eni basic and diluted |  | 4.62 |  |  | 5.26 |  |  | 5.53 |  |  | 3.77 |  |  | 0.96 |

(1) |  | 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.
(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 2014 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2015.
(3) |  | 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 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 2010 through 2013 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 2014 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 1.12 per ADR) at the Noon Buying Rate recorded on the payment date on September 22, 2014, while the balance of euro 1.12 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2014. The balance dividend for 2014 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 20, 2015 to holders of Eni shares, being the ex-dividend date May 18, 2015, while ADRs holders will be paid on June 5, 2015.

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| As of December 31,

| 2010 |  | 2011 |  | 2012 |  | 2013 |  | 2014

| (euro million except data per share and per ADR)

CONSOLIDATED BALANCE SHEET DATA |  |  |  |  |  |  |  |  |  |
Total assets |  | 131,860 |  | 142,945 |  | 140,192 |  | 138,341 |  | 146,207
Short-term and long-term debt |  | 27,783 |  | 29,597 |  | 24,192 |  | 25,560 |  | 25,891
Capital stock issued |  | 4,005 |  | 4,005 |  | 4,005 |  | 4,005 |  | 4,005
Non-controlling interest |  | 4,522 |  | 4,921 |  | 3,357 |  | 2,839 |  | 2,455
Shareholders’ equity - Eni share |  | 51,206 |  | 55,472 |  | 59,060 |  | 58,210 |  | 59,754
Capital expenditures from continuing operations |  | 12,450 |  | 11,909 |  | 12,805 |  | 12,800 |  | 12,240
Weighted average number of ordinary shares outstanding (fully diluted - shares million) |  | 3,622 |  | 3,623 |  | 3,623 |  | 3,623 |  | 3,610
Dividend per share (euro) (1) |  | 1.00 |  | 1.04 |  | 1.08 |  | 1.10 |  | 1.12
Dividend per ADR ($) (1) (2) |  | 2.64 |  | 2.73 |  | 2.82 |  | 3.00 |  | 2.79

(1) |  | Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2014 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2015.
(2) |  | Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/US$ 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 2010 through 2013 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 2014 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 1.12 per ADR) at the Noon Buying Rate recorded on the payment date on September 22, 2014, while the balance of euro 1.12 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2014. The balance dividend for 2014 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 20, 2015 to holders of Eni shares, being the ex-dividend date May 18, 2015, while ADRs holders will be paid on June 5, 2015.

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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, 2010, 2011, 2012, 2013 and 2014.

| Year ended December 31,

| 2010 |  | 2011 |  | 2012 |  | 2013 |  | 2014

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL) |  | 3,415 |  | 3,134 |  | 3,084 |  | 3,079 |  | 3,077
of which developed |  | 1,951 |  | 1,850 |  | 1,762 |  | 1,831 |  | 1,847
Proved reserves of liquids of equity-accounted entities at period end (mmBBL) |  | 208 |  | 300 |  | 266 |  | 148 |  | 149
of which developed |  | 52 |  | 45 |  | 44 |  | 35 |  | 46
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) (1) |  | 16,198 |  | 15,582 |  | 14,190 |  | 14,442 |  | 14,808
of which developed |  | 10,965 |  | 10,363 |  | 8,965 |  | 8,542 |  | 8,342
Proved reserves of natural gas of equity-accounted entities at period end (BCF) |  | 1,684 |  | 4,700 |  | 6,767 |  | 3,726 |  | 3,737
of which developed |  | 246 |  | 53 |  | 424 |  | 34 |  | 120
Proved reserves of hydrocarbons of consolidated subsidiaries at period end (mmBOE) (1) |  | 6,332 |  | 5,940 |  | 5,667 |  | 5,708 |  | 5,772
of which developed |  | 3,926 |  | 3,716 |  | 3,394 |  | 3,387 |  | 3,366
Proved reserves of hydrocarbons of equity-accounted entities at period end (mmBOE) |  | 511 |  | 1,146 |  | 1,499 |  | 827 |  | 830
of which developed |  | 96 |  | 54 |  | 122 |  | 40 |  | 67
Average daily production of liquids (KBBL/d) |  | 997 |  | 845 |  | 882 |  | 833 |  | 828
Average daily production of natural gas available for sale (mmCF/d) (2) |  | 4,222 |  | 3,763 |  | 4,118 |  | 3,868 |  | 3,782
Average daily production of hydrocarbons available for sale (KBOE/d) (2) |  | 1,757 |  | 1,523 |  | 1,631 |  | 1,537 |  | 1,517
Hydrocarbon production sold (mmBOE) |  | 638.0 |  | 548.5 |  | 598.7 |  | 555.3 |  | 549.5
Oil and gas production costs per BOE (3) |  | 8.89 |  | 10.86 |  | 10.82 |  | 12.19 |  | 12.00
Profit per barrel of oil equivalent (4) |  | 11.91 |  | 16.98 |  | 15.95 |  | 15.46 |  | 9.90

(1) |  | Includes approximately 767 BCF of natural gas held in storage in Italy as of December 31, 2010 and 2011.
(2) |  | Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (318, 321, 383, 451 and 442 mmCF/d in 2010, 2011, 2012, 2013 and 2014, respectively).
(3) |  | 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 on Consolidated Financial Statements".
(4) |  | 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 on Consolidated Financial Statements" for a calculation of results of operations from oil and gas producing activities.

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Selected Operating Information continued

| Year ended December 31,

| 2010 |  | 2011 |  | 2012 |  | 2013 |  | 2014

Sales of natural gas to third parties (1) |  | 75.81 |  | 77.84 |  | 77.87 |  | 77.67 |  | 76.11
Natural gas consumed by Eni (1) |  | 6.19 |  | 6.21 |  | 6.43 |  | 5.93 |  | 5.62
Sales of natural gas of affiliates (Eni’s share) (1) |  | 9.41 |  | 9.85 |  | 8.29 |  | 6.96 |  | 4.38
Total sales and own consumption of natural gas of the Gas & Power segment (1) |  | 91.41 |  | 93.90 |  | 92.59 |  | 90.56 |  | 86.11
E&P natural gas sales in Europe and in the Gulf of Mexico (1) |  | 5.65 |  | 2.86 |  | 2.73 |  | 2.61 |  | 3.06
Worldwide natural gas sales (1) |  | 97.06 |  | 96.76 |  | 95.32 |  | 93.17 |  | 89.17
Electricity sold (2) |  | 39.54 |  | 40.28 |  | 42.58 |  | 35.05 |  | 33.58
Refinery throughputs (3) |  | 34.80 |  | 31.96 |  | 30.01 |  | 27.38 |  | 25.03
Balanced capacity of wholly-owned refineries (4) |  | 564 |  | 574 |  | 574 |  | 574 |  | 404
Retail sales (in Italy and rest of Europe) (3) |  | 11.73 |  | 11.37 |  | 10.87 |  | 9.69 |  | 9.21
Number of service stations at period end (in Italy and rest of Europe) |  | 6,167 |  | 6,287 |  | 6,384 |  | 6,386 |  | 6,220
Average throughput per service station (in Italy and rest of Europe) (5) |  | 2,353 |  | 2,206 |  | 2,064 |  | 1,828 |  | 1,725
Chemical production (3) |  | 7.22 |  | 6.25 |  | 6.09 |  | 5.82 |  | 5.28
Engineering & Construction order backlog at period end (6) |  | 20,505 |  | 20,417 |  | 19,739 |  | 17,065 |  | 22,147
Employees at period end (number) (7) |  | 73,768 |  | 72,574 |  | 79,405 |  | 83,887 |  | 84,405

(1) | i | Expressed in BCM.
(2) | i | Expressed in TWh.
(3) | i | Expressed in mmtonnes.
(4) | i | Expressed in KBBL/d.
(5) | i | Expressed in thousand liters per day.
(6) | i | Expressed in euro million.
(7) | i | Relating 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)..

| High |  | Low |  | Average (1) |  | At period end

| (U.S. dollars per euro)

Year ended December 31, |  |  |  |  |  |  |  |
2010 |  | 1.46 |  | 1.19 |  | 1.33 |  | 1.34
2011 |  | 1.49 |  | 1.29 |  | 1.39 |  | 1.29
2012 |  | 1.35 |  | 1.21 |  | 1.29 |  | 1.32
2013 |  | 1.38 |  | 1.28 |  | 1.33 |  | 1.38
2014 |  | 1.39 |  | 1.21 |  | 1.33 |  | 1.21

(1) |  | Average of the Noon Buying Rates for the last business day of each month in the period.

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| High |  | Low |  | At period end

| (U.S. dollars per euro)

October 2014 |  | 1.28 |  | 1.25 |  | 1.25
November 2014 |  | 1.26 |  | 1.24 |  | 1.24
December 2014 |  | 1.25 |  | 1.21 |  | 1.21
January 2015 |  | 1.20 |  | 1.13 |  | 1.13
February 2015 |  | 1.15 |  | 1.12 |  | 1.12
March 2015 |  | 1.12 |  | 1.05 |  | 1.08

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 31, 2015 was $1.08 per euro 1.00.

Risk factors

The risks described below may have a material adverse effect on our operational and financial performance. We invite our investors to consider these risks carefully.

Our 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:

(i) |  | global and regional dynamics of oil and gas supply and demand. The price of crude oil dropped significantly in the last part of 2014 with oil prices falling from the level of approximately 110 $/BBL by mid-year down to below the 50-dollar mark. This decline was driven by surging crude oil output mainly in non-Opec countries, like the United States, Russia, Brazil and Canada, in the face of a continuing slowdown in global demand. Eni believes that global oil demand will grow at a moderate pace in the short to medium term due to sluggish economic activity in Europe and other macroeconomic uncertainties, and more efficient use of fuels and energy in OECD countries whereas crude oil production is forecast to grow at a higher pace than demand. We currently forecast 55 $/BBL for the full year 2015 which is lower than the average level achieved in 2014 of approximately 100 $/BBL. See "Item 5 – Management’s expectations of operations";
(ii) |  | global political developments, including sanctions imposed on certain producing countries and conflict situations;
(iii) |  | global economic and financial market conditions;
(iv) |  | the influence of the Organization of the Petroleum Exporting Countries ("OPEC") over world supply and therefore oil prices;
(v) |  | prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables);
(vi) |  | weather conditions;
(vii) |  | operational issues;
(viii) |  | governmental regulations and actions;
(ix) |  | 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
(x) |  | the effect of worldwide energy conservation and environmental protection efforts.

All these factors can affect the global balance between demand and supply for oil and prices of oil. Price fluctuations may have a material effect on the Group’s results of operations and cash flow. Generally speaking, lower oil prices from one year to another reduce the Group consolidated results of operations and cash flow and vice versa. The effect of changes in oil prices on Eni’s average realization for produced oil and therefore its revenues in the Exploration & Production segment is immediate. We estimate that our consolidated net profit and cash flow vary by approximately euro 0.15 billion for each one-dollar change in the price of the Brent crude oil benchmark with respect to our pricing scenario for the year 2015. See "Item 5 – Management’s expectations of operations – Outlook". 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 uneconomic in this type of environment, and asset impairments. Depending on the materiality and rapidity of a decrease in crude oil prices, we may also need to review investment decisions and the viability of development projects.

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Lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flows 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 at development projects either planned or being implemented forcing the Company to reschedule, postpone or cancel development projects. Finally, lower oil prices over prolonged periods may trigger a review of the future recoverability of the Company’s carrying amounts of oil and gas properties, resulting in the recognition of significant impairment charges, and may impact shareholders returns, including dividends and share buybacks, or share price.

Eni estimates that movements in oil prices impact approximately 50% of Eni’s current production. A further 35% of Eni’s current production which derives from production sharing contracts is unaffected by crude oil price movements which instead impact the Company’s volume entitlements (see disclosure below). Finally, Eni estimates that exposure to changes in crude oil prices of approximately 5-10% of Eni’s production is offset by equivalent and contrary movements in the procurement costs of gas in Eni’s long-term supply contracts which index the cost of gas to crude oil prices, reflecting Eni’s decision late in 2013 to fully exploit the benefits of the natural hedging occurring between Eni’s Exploration & Production and Gas & Power segments. In previous reporting periods Eni entered into commodity derivatives to protect margins on gas sales in Eni’s gas & power business from exposure to crude oil changes and late in 2013 Eni discontinued this policy with a view to exploiting the natural hedge provided by Eni’s production of crude oil. This development influenced Eni’s results of operations in 2014 and will affect the Group’s consolidated results going forward.

However, high oil and gas prices can adversely impact the demand for our products and consequently our profitability, especially in the refining & marketing businesses. Furthermore, a high price scenario may imply increase of costs and taxes and may negatively impact the share of production and reserve to which Eni is entitled under some Production Sharing Agreements (PSAs) (See the specific risks of the Exploration & Production segment below).

In gas markets, price volatility reflected the dynamics of demand and supply for natural gas. In 2014, gas demand in Europe dropped on average by approximately 12% in the 28-EU countries compared to the previous year driven by exceptionally mild weather conditions in the first part of the year and competition from coal and a growing share of electricity generation from renewables. Despite falling demand, gas supply has continued to increase due to a number of factors, mainly increased availability of liquefied natural gas ("LNG") on global scale, take-or-pay obligations provided by long-term supply contracts held by European gas wholesalers and the other trends described in the specific risk-factors section of our gas & power business below. The increased liquidity of European hubs put significant downward pressure on spot prices. We expect those trends to continue in the foreseeable future due to a weak outlook for gas demand and continued oversupplies. In case we fail to renegotiate our long-term gas supply contract in order to make our gas competitive as market conditions evolve, our profitability and cash flow in the Gas & Power segment would be significantly impacted by current downward trends in gas prices.

The Refining & Marketing segment is substantially affected by changes in European refining margins, which reflect changes in prices of crude oil and refined products. The prices of refined products depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather conditions. Furthermore, Eni’s realized margins are also affected by price differentials between heavy crudes versus light ones, taking into account the ability of Eni’s refineries to process complex crudes. This may represent a cost advantage for Eni when light-heavy differential widens. Finally, it is worth noting that the impact of changes in crude oil prices on Eni’s refining businesses depends on the speed at which the prices of refined products adjust to reflect movements in oil prices, as a time lag exists between movements in oil prices and in prices of finished products. Generally speaking, when oil prices decline, depending also on the rapidity and materiality of the decline, our refining margins improve on the short term, and vice versa. However, we believe that in the current depressed environment for refining margins, lower costs of the crude oil feedstock could represent only a temporary boost to our refining margins due to the structural headwinds existing in the European industry. Those headwinds include excess capacity and the competitive pressure from oil products having a cheaper cost structure than ours. See "Competition" below.

Also our Chemical segment is subject to fluctuations in supply and demand for petrochemical products and movements in crude oil prices, to which costs of feedstock are indexed, with a consequent effect on prices and profitability. Similarly to our Refining & Marketing segment, our Chemical segment has been negatively impacted by structural headwinds tied to excess capacity, weak commodity demand in Europe and the competition from cheaper products coming from Asia and the United States. See "Competition" below. Based on these negative trends, we believe that any improvement in the oil-linked costs of the petrochemical feedstock will represent only a temporary boost to our margins of petrochemical products.

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> 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 license costs and product prices, with a consequent effect on our margins and our market shares. Eni’s ability to remain competitive requires continuous focus on technological innovation, reducing unit costs and improving efficiency. It is also depends on our ability to get an 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 industry-wide cost increases to a greater extent compared to its larger competitors given its potentially smaller market power with respect to suppliers. If, as a result 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 flows 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, oversupplies which have been supported by large availability of liquefied natural gas ("LNG") on global scale, and inter-fuel competition due to rising 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) which have materially impacted the use of gas in the production of electricity and hence sales of gas to the thermoelectric industry. The extensive development of shale gas in the United States was another fundamental trend that aggravated the oversupply situation in Europe. The continuing growth in the production of shale gas in the United States 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 till 2020 and beyond driven by economic growth and increased use of gas in firing power production. European gas wholesalers including Eni committed well in advance to purchasing large amounts of gas under long-term supply contracts with so-called "take-or-pay" clauses from the main producing countries bordering Europe (namely Russia and Algeria) and invested heavily to upgrade existing pipelines and to build new infrastructure along several European routes 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 built, thus driving the development of very liquid continental hubs to trade spot gas. Spot prices at continental hubs became the main benchmarks to which selling prices are indexed in supplies to large industrial customers and thermoelectric utilities. 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-tem supply contracts. We believe that those headwinds have become structural ones and therefore we do not expect any meaningful improvement in the European gas sector for the foreseeable future. Gas demand will remain weak due to macroeconomic uncertainties and unclear EU policies regarding how to satisfy energy demand in Europe and the energetic mix. Supplies at continental hubs will continue building up also in view of a possible ramp-up of LNG exports from the United States due to steady growth in gas production and ongoing projects to reconvert LNG re-gasification facilities into liquefaction export units and the start of several LNG projects in the Pacific Region and elsewhere.
|  | We believe 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 to 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 of Italy who sell electricity on the Italian market. Going forward, the Company expects continuing competition due to the projections of weak economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production in the Italian market. The economics of the gas-fired electricity business have dramatically changed over the last

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|  | 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 benefited from governmental subsides, and a recovery in the production of coal-fired electricity generation 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.
• |  | Our Refining & Marketing business faces strong competition in the marketing of refined products to final customers in the retail and wholesale markets in Italy and in certain countries in Europe where we have an established presence. The economics of this business have progressively deteriorated over the latest years due to structural headwinds in the industry. Refining and distribution margins have been negatively impacted by a combination of drivers, including weak demand for fuels due to the economic downturn particularly in Italy, high crude oil feedstock costs, trends in oil-linked costs of energy and other plant utilities, excess refining capacity across Europe and increasing competition of products streams coming from Russia, the Middle East, East Asia and the United States. This latter trend is particularly worrisome as refiners in those areas can leverage on cost advantages due to plans scale and availability of cheap raw materials. The United States for example, have become a net exporter of refined products, particularly gasoline and middle distillates, due to the tight oil revolution which has improved the competitiveness of U.S.-based refiners as prices of U.S. crudes are generally lower than the Brent crude to which crude oil purchases of European refiners are mainly indexed. Instead, Eni’s margins of refined products were affected by cost disadvantages due to unfavorable geographic location and lack of scale of Eni’s refineries. Furthermore, narrowing price differentials between the Brent benchmark and heavy crude qualities hit Eni’s profitability of complex cycles which depends upon the availability of cheaper crude qualities than the Brent crude in order to remunerate the higher operating costs of complex plants. This latter trend reflected reduced supplies of heavy crudes in the Mediterranean area, reversing the pattern observed historically whereby heavy crude qualities traded at a discount vs. the Brent benchmark due to their relatively smaller yield of valuable products. These trends negatively affected Eni’s integrated refining and marketing results of operations and cash flows in recent years. This segment reported losses at the operating level and negative cash flows for several consecutive years. In 2014, operating losses amounted to euro 2.23 billion. We believe that these competitive headwinds have become structural trends and looking forward we do not expect any reversal of those trends in the foreseeable future, thus negatively impacting the profitability outlook in our Refining & Marketing segment over the foreseeable future.
|  | In the retail marketing of refined products both in Italy and abroad, Eni competes with oil companies and non-oil operators (such as supermarket chains and other commercial operators) to obtain concessions to establish and operate service stations. Eni’s service stations compete primarily on the basis of pricing, services and availability of non-petroleum products. Eni expects that competitive pressures will continue in the foreseeable future.
• |  | In the Chemical segment, 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 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 which we believe have become structural headwinds. This segment has reported losses at the operating level and negative cash flows for several consecutive years, driven by the trends in the industry described above. In 2014, operating losses amounted to euro 704 million. Management believes that the profitability outlook in Eni’s petrochemical segment will remain negative over the foreseeable future due to anticipated weak trends in European demand for petrochemical commodities, strong competitive pressures and overcapacity.
• |  | Competition in the oil field services, construction and engineering industries is primarily based on technical expertise, quality and number of services and availability of technologically advanced facilities (for example, vessels for offshore construction). Lower oil prices could result in lower margins and lower demand for oil services. Failure or inability to respond effectively to competition could adversely impact the Company’s growth prospects, future results of operations and cash flows in this business. In 2014, the Company’s Engineering & Construction segment returned to profit following the sizeable losses incurred in the previous year. However the level of profitability in 2014 was below management’s own targets and initial guidance as the execution of legacy, low-margin contracts dragged down profitability. Furthermore, there was a slow ramp-up of activities at newly acquired orders due to market uncertainties and a continuing deterioration in the competitive environment. The business outlook remains challenging due to a number of headwinds. These include strong competitive pressures and risks and uncertainties relating to the acceptance by customers of the works done in the execution of certain legacy contracts which are still in progress. Finally a slowdown in oil prices may force oil companies to revise their capital budget plans and postpone investment decision. This trend may hurt profitability of our oilfield services and engineering segment in the next future years.

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> 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, 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 from operations and liquidity depend on its ability to identify and mitigate the risks and hazards inherent to operating in those industries.

In Exploration & Production, 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 property, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operation, liquidity, reputation and prospects of the Group.

Eni’s activities in the Refining & Marketing and Chemical segments 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 impacts 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, maritime, river-maritime, rail, road, 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 risks could effectively result in unexpected incidents, including releases or oil spills, blowouts, fire, 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. 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’s insurance subsidiary provides insurance coverage to Eni’s entities, generally up to $1.1 billion in case of offshore incident and $1.5 billion in case of incident at onshore facilities (refineries). In addition, the Company also maintains worldwide third-party liability insurance coverage for all of its subsidiaries. Management believes that its insurance coverage is in line with industry practice and 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 like BP Deepwater Horizon, 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, shareholders’ return and damage the Group’s reputation.

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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

The exploration and production of oil and natural gas requires high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil and gas fields. A description of the main risks facing the Company’s business in the exploration and production of oil and gas is provided below.

> (i) Eni’s oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks

Eni has material operations relating to the exploration and production of hydrocarbons located offshore. In 2014, approximately 55% 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. As the Macondo accident in the Gulf of Mexico has shown, the potential impacts of offshore accidents and spills to health, safety, security and the environment can be catastrophic due to the objective difficulties in handling hydrocarbons containment and other factors. Further, offshore operations are subject to marine risks, including severe 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, 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 and prospects.

> (ii) 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 as a result of a large variety of factors, including geological play 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, also 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 high reward 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. The Company plans to conduct exploration projects offshore West Africa (Angola, Nigeria, Congo, and Gabon), East Africa (Mozambique, Kenya and South Africa), South-East Asia (Indonesia, Vietnam, Myanmar and other locations), Australia, the Norwegian Barents Sea, the Mediterranean and offshore Gulf of Mexico. In 2014, the Company spent euro 1.4 billion to conduct exploration projects and plans to spend approximately euro 1.2 billion on average in the next four-year plan on exploration activities. 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 exploratory program.

> (iii) Development projects bear significant operational risks which may adversely affect actual returns

Eni is executing 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:

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• |  | the outcome of negotiations with co-venturers, governments and state-owned companies, suppliers, customers or others, including, for example, Eni’s ability to negotiate favorable long-term contracts to market gas reserves;
• |  | the development of reliable spot markets that may be necessary to support the development of particular production projects, or commercial arrangements for pipelines and related equipment to transport and market hydrocarbons;
• |  | timely issuance of permits and licenses 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, for example by obtaining more favorable contractual terms by suppliers of equipment and services;
• |  | the ability to carefully carry out front-end engineering design so as to prevent the occurrence of technical inconvenience during the execution phase;
• |  | timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; 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. Due to the recent downtrend in crude oil prices, the Company will seek to renegotiate construction contracts, daily rates for rigs and other field services and costs for materials and other productive factors to preserve margins at its development projects. In case it fail to obtaining the planned cost reductions, its profitability in the Exploration & Production segment could be adversely affected;
• |  | 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 final 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 successfully deliver major projects on time and on budget could negatively impact results of operations, cash flow and the achievement of short-term targets of production growth. Finally, 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-lead-time 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 co-venturers 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 operation control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operation and strategic objectives due to the nature of its relationships.

For example in the Kashagan offshore field, in the Kazakh section of the Caspian Sea, the latest issue related to the downtime of a pipeline which forced the consortium to shut down production after the start-up. The damaged pipeline needs to the replaced with the consequence of additional costs to the project and the production will resume in late 2016.

Finally, in case 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 charges of capitalized costs associated with reduced future cash flows of those projects.

> (iv) 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 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

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reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The opposite occurs incase 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 portion 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.

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 and liquidity.

> (v) Eni expects that tightening regulation in oil and gas activities following the Macondo accident will lead to rising compliance costs and other restrictions

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. Following the Macondo accident in the Gulf of Mexico, governments throughout the world have enacted stricter regulations on environmental protection, risk prevention and other forms of restrictions to drilling and other well operations. These new regulations and legislation, as well as evolving practices, increase the burden of compliance costs by requiring industry participants to adopt new security and risk prevention measures and procedures. They may also require changes to Eni’s drilling operations and exploration and development plans and may lead to higher royalties and taxes.

> (vi) 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 production sharing agreements and similar contractual schemes.

The prices used in calculating our estimated proved reserves are, in accordance with U.S. SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ended December 31, 2014, average prices used to calculate our estimated proved reserves were based on 101 $/BBL for the Brent crude oil. Commodity prices declined significantly in the fourth quarter of 2014 and if such prices do not increase significantly, our future calculations of estimated proved reserves will be based on lower commodity prices which could result in our having to remove non-economic reserves from our proved reserves in future periods. This effect will be partially counterbalanced by an increase of reserves corresponding to the additional production entitlement under the PSA relating to cost oil: i.e. because of lower oil and gas prices the reimbursement of expenditures incurred by the Company requires additional volumes of reserves.

Many of these factors, assumptions and variables involved in estimating proved reserves are subject to change over time therefore impacting the estimates of oil and natural gas reserves. Accordingly, the estimated reserves reported as of the end of the period covered by this filing could be significantly different from the quantities of oil and natural gas that will ultimately be 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.

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> (vii) Oil and gas activity may be subject to increasingly high levels of income taxes

The oil and gas industry is subject to the payment of royalties and income taxes which tend to be higher than those payable in many other commercial activities. In addition, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. As a result of these trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the Italian statutory tax rate for corporate profit which currently stands at 38 per cent.

The tax rate of the Company’s Exploration & Production segment for the fiscal year 2014 was estimated at approximately 60 per cent. Eni believes that the tax rate in the Company’s Exploration & Production segment for the fiscal year 2015 will trend higher due to a projected higher share of taxable profit which will be reported in countries with higher taxation than this segment average.

Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices. Adverse changes in the tax rate applicable to the Group profit before income taxes in its oil and gas operations would have a negative impact on Eni’s future results of operations and cash flows.

In the current uncertain financial and economic environment also due to falling oil prices, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal framework for the oil and gas industry, including the risk of increased taxation, windfall taxes, nationalization and expropriations.

Eni’s results depend on its ability to identify and mitigate the above mentioned risks and hazards which are inherent to Eni’s operation.

> (viii) The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our 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 our proved reserves is the current market value of our estimated crude oil and natural gas reserves. In accordance with U.S. SEC rules, we base 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 we receive 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 our production and our 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 we use 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 our reserves or the crude oil and natural gas industry in general.

At December 31, 2014, the net present value of our proved reserves totaled approximately euro 59.6 billion. The average prices used to estimate our proved reserves and the net present value at December 31, 2014, as calculated in accordance with U.S. SEC rules, were 101 $/BBL for the Brent crude oil. Actual future prices may materially differ from those used in our year-end estimates.

Commodity prices have decreased significantly in recent months. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were in line with the pricing environment existing in the first quarter of 2015, our PV-10 at December 31, 2014 could decrease significantly.

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> Political considerations

A substantial portion of Eni’s oil and gas reserves and gas supplies are located in countries where the socio-political framework and macroeconomic outlook is less stable than those of 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, 2014, approximately 79% of Eni’s proved hydrocarbon reserves were located in such countries and 60% of Eni’s supplies of natural gas derived from non-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 any of those less stable countries may negatively affect 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:

(i) |  | lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
(ii) |  | unfavorable enforcement of laws, regulations and contractual arrangements leading, 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 to obtain a larger profit share from a given project, thereby reducing Eni’s profit share. Furthermore, as of the balance sheet date receivables for euro 663 million relating to cost recovery under certain petroleum contracts in a non-OECD country were the subject of an arbitration proceeding;
(iii) |  | restrictions on exploration, production, imports and exports;
(iv) |  | tax or royalty increases (including retroactive claims); and
(v) |  | 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 in 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 worldwide. 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. Areas where Eni operates where the Company is exposed to the political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Indonesia, Kazakhstan, Venezuela, Iraq, Iran and Russia. In addition, any possible reprisals as a consequence 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, consolidated results of operations, and consolidated financial condition. In recent years, Eni’s production levels in Libya were negatively impacted by acts of local conflict, social unrest, protests, strikes, which forced Eni to temporarily interrupt or reduce its producing activities, negatively affecting Eni’s results of operations and cash flow. Also 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. Looking forward, Eni expects that those risks will continue to affect Eni’s operations in those countries. Particularly, the uncertain socio-political outlook in Libya and unsafe operational conditions onshore Nigeria were factored in the Company’s projections of future production levels in these two countries. For more information about the status of Eni’s operations in Libya see “Risks associated with continuing political instability in North Africa and the Middle East” below.

In the current low oil price environment, the financial outlook of few countries where Eni’s hydrocarbons reserves are located has significantly deteriorated due to a contraction in the proceeds associated with the exploitation of hydrocarbons resources. This may increase the risk of default which may lead to higher political and macroeconomic instability. Furthermore in few cases, Eni is partnering with the national oil companies of such countries in executing oil&gas development projects. A possible sovereign default might jeopardize the financial feasibility of ongoing projects or increase the financial exposure of Eni which would be forced to finance the share of development expenditures of the first party.

There are certain instances where Eni is contractually obligated to finance the share of costs of the first party. This risk is mitigated by the customary default clause 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.

While the occurrence of those events is unpredictable, it is likely that the occurrence of such events could adversely impact Eni financial exposure.

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> Risks associated with continuing political instability in North Africa and the Middle East

As of the end of 2014, approximately 27% of the Company’s proved oil and gas reserves were located in North Africa and the Middle East. Since 2011, several North African and Middle Eastern oil producing countries have been experiencing an extreme level of political instability that has resulted in changes of governments, internal conflict, unrest and violence which led to economic disruptions and shutdowns in industrial activities.

The instability of the socio-political framework in those countries still represents an area of concern involving risks and uncertainties for the foreseeable future. Particularly, the internal situation in Libya continues to represent an issue to Eni’s management. Following the internal conflict of 2011 and the fall of the regime which forced the Company to shutdown almost all its producing facilities including gas exports for a period of about 8 months, a period of social and political instability began which turned into disorders, strikes, protests and a resurgence of the internal conflict. These events jeopardized Eni’s ability to perform its industrial activity in safety, forcing the Company to interrupt its operations on certain occasions as precautionary measure. These events were fairly frequent in 2013 and more sporadic in 2014. In 2014, Eni’s facilities in Libya produced on average 233 KBOE/d, registering a small increase compared to 2013.

The political instability in Egypt hindered the Country’s access to the financial markets, and resulted in continued difficulties for the local oil and gas companies to fulfill financial obligations towards international oil companies including trade payables due to Eni which supplies its oil and gas entitlements to local companies. Eni has not experienced any disruptions at its producing activities in the Country to date.

The Company believes that the political outlook in North Africa and the Middle East remains an area of risk for the Company’s operations, results, liquidity and prospects. In light of the recent developments in Libya, management decided to strengthen security measures at the Company’s production installations and facilities in the Country. However, we did not suffer any significant production shutdowns in the first part of 2015 up to the filing date.

> Risks associated with Eni’s presence in sanction targets

Eni is currently engaging in residual oil and gas operations in Iran. The legislation and other regulations in the United States and the European Union that target Iran and persons who have certain dealings with Iran may lead to the imposition of sanctions on any persons doing business in Iran or with Iranian counterparties, unless specific authorizations, exceptions and assurances apply, as is currently the case for Eni. With reference to recent sanctions imposed on Russia, see "An escalation of the political crisis in Russia and Ukraine could affect Eni’s business in particular and the global energy supply generally" below.

> United States measures towards Iran

The United States enacted the Iran Sanctions Act of 1996 (ISA), which required the President of the United States to impose sanctions against any entity that is determined to have engaged in certain activities, including investing in Iran’s petroleum sector. The ISA was amended in July 2010 by the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 (CISADA) which targets activities that either: (i) support the maintenance or expansion of Iran’s domestic production of refined petroleum products, or (ii) contribute to the enhancement of Iran’s ability to import refined petroleum products.

CISADA expanded the list of sanctions available to the President of the United States while at the same time providing that an investigation need not be initiated, and may be terminated once begun, if the President certifies in writing to the U.S. Congress that the person whose activities in Iran were the basis for the investigation is no longer engaging in those activities or has taken significant steps toward stopping the activities, and that the President has received reliable assurances that the person will not knowingly engage in any sanctionable activity in the future.

After the passage of CISADA, Eni engaged in discussions with officials of the U.S. State Department, which administers the ISA, regarding Eni’s activities in Iran. On September 30, 2010, the U.S. State Department announced that the U.S. Government, pursuant to a provision of the ISA added by CISADA that allows it to avoid making a determination of sanctionability under the ISA with respect to any party that provides certain assurances, would not make such a determination with respect to Eni based on Eni’s commitment to end its investments in Iran’s energy sector and not to undertake any new energy-related activity. The U.S. State Department further indicated at that time that, as long as Eni acts in accordance with these commitments, it will not be regarded as a company of concern for its past Iran-related activities.

The United States maintains, however, broad and comprehensive economic sanctions targeting Iran that are administrated by the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC sanctions”). These

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sanctions generally restrict the dealings of U.S. citizens and persons subject to the jurisdiction of the United States. In addition, Eni is aware of initiatives by certain U.S. states and U.S. institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as states sponsoring terrorism. CISADA specifically authorized certain state and local Iran-related divestment initiatives. If Eni’s operations in Iran are determined to fall within the scope of divestment laws or policies, sales resulting from such divestment laws and policies, if significant, could have an adverse effect on the value of Eni’s shares. Even if Eni’s activities in and with respect to Iran do not expose it to sanctions or divestment, companies with investments in the oil and gas sectors in Iran may suffer reputational harm as a result of increased international scrutiny.

Between the end of 2011 and 2013, the United States adopted new measures designed to intensify the scope of U.S. sanctions against Iran, in particular related to Iran’s energy and financial sectors.

Such restrictive measures are: the Executive Orders 13590 of November 21, 2011 and 13622 of July 31, 2012, the Iran Threat Reduction and Syrian Human Rights Acts of August 10, 2012 (ITRSHRA), which expanded the ISA/CISADA scope by increasing from three to five the minimum number of sanctions to be imposed in case of violations of the energy sector restrictions; the National Defense Authorization Acts - 2012, related to transactions with the Iranian Central Bank and transactions for the acquisition of Iranian crude oil and the National Defense Authorization Acts - 2013, which, inter alia, adds the shipbuilding sector to those areas subject to sanctions.

While Eni has no formal assurances that the U.S. State Department’s 2010 determination of non-sanctionability under the ISA would similarly extend to sanctions under the measures issued in 2011, 2012 and 2013, during this period, Eni has continued to inform the U.S. State Department of its Iran-related activities. Eni does not believe that its activities in Iran (the completion of existing contracts which were notified to the U.S. Administration when the Special Rule was applied) are sanctionable under such more recent measures described above.

> European Union restrictive measures towards Iran

On March 23, 2012, the Council of the European Union enacted a regulation which prohibits the supply, import and transport of Iranian crude oil and petroleum products. The rules waive the execution of contracts entered into force before January 23, 2012, whereby the supply of Iranian crude oil and petroleum products is intended to reimburse outstanding receivables due to entities under the jurisdiction of EU Member States. According to these waivers, Eni received by the empowered European Member States’ Authorities the relevant authorizations in order to carry out its oil import activities from Iran. This waiver is renewed from time to time.

In 2012, the Council of the European Union adopted a new round restrictive measures against Iran including among others: prohibition of transactions between the European Union and Iranian banks and financial institutions, unless an authorization is granted in advance by the relevant Member State, an embargo on the supply to Iran and use in Iran of key equipment or technology which could be used in the sectors of the oil, natural gas and petrochemical industries from April 15, 2013.

Furthermore, the new measures designate new Iranian entities as subject to asset freeze, including the Iranian oil and gas industry companies (the National Iranian Oil Co - NIOC and its subsidiary operating companies).

Eni has been operating in Iran for several years under four service contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the NIOC between 1999 and 2001, and no other exploration and development contracts have been entered into since then. Under such service contracts, Eni has carried out development operations in respect of certain oilfields, and is entitled to recovery of expenditures made, as well as a service fee. All projects mentioned above have been completed: the Darquain project was handed over to NIOC in the final months of 2014 and as such Eni’s obligations to provide technical assistance, commissioning services and spare parts and supplies for field maintenance and operations have been winded down. In 2014, Eni incurred operating expenses of $1 million to provide such activities and services and does not expect to incur further operating costs in this respect. Therefore, Eni’s only involvement in the Country will be the recovery of its past investments.

Eni’s projects in Iran are currently in the cost recovery phase. Therefore, Eni has ceased making any further investment in the Country and is not planning to make additional capital expenditures in Iran in future years. In 2014, Eni’s production in Iran averaged less than 1 KBOE/d, and is negligible in comparison with Eni Group’s total production. Eni’s entitlement in 2014 represented approximately 1 per cent of the overall production from the oil and gas fields that Eni has developed in Iran. Eni believes that the results from its Iranian activities are immaterial to the Group’s results of operations and cash flow.

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Eni has no involvement in Iran’s refined petroleum sector and does not export refined petroleum to Iran.

Finally, Eni’s Chemical segment licensed a number of technologies in Iran in past years, relating to plastics/elastomers and relevant raw materials, but it never supplied equipment or materials for plant construction. By April 2013, Eni had suspended all contracts to comply with EU restrictions.

Eni will continue to monitor closely legislative and other developments in the United States and the European Union in order to determine whether its remaining interests in Iran could subject Eni to application of either current or future sanctions under the OFAC sanctions, the ISA, the EU measures or otherwise. If any of its activities in and with respect to Iran are found to be in violation of any Iran-related sanctions, and sanctions are imposed on Eni, it could have an adverse effect on Eni’s business, plans to raise financing, sales and reputation.

An escalation of the political crisis in Russia and Ukraine could affect Eni’s business in particular and the global energy supply generally

The political crisis in Ukraine and the Crimean Peninsula unfolded in February 2014 and led to the impeachment of the President of Ukraine Viktor Yanukovych and the subsequent reaction by the Russian Federation. In March 2014, the announcement of the Supreme Council of Crimea and the City Council of Sevastopol of their intention to declare Crimea’s independence from Ukraine as a single united nation with the possibility of joining the Russian Federation as a federal subject was followed by a referendum where 96 per cent of those who voted in Crimea supported joining Russia. The Russian Federation annexed Crimea immediately after the result of the referendum. The Ukrainian Parliament, the United States and the European Union consider the referendum to be illegal and unconstitutional. Sanctions were imposed by the EU and the United States on officials and politicians from Russia and Crimea. Subsequently, allegations that the Russian Government has provided military and other support to separatists in Ukraine have led to further EU and U.S. sanctions.

Eni is closely monitoring developments to the political situation in Russia, Ukraine and the Crimea Region, is adapting its business activities to the sanctions already adopted by the relevant authorities and will adapt to any further related regulations and/or economic sanctions that could be adopted by the authorities.

Among other activities, Eni is currently part of a strategic co-operation agreement for exploration activities in the Russian sections of the Barents Sea and the Black Sea. Contracts pertaining to this exploration were entered into before enactment of the restrictive measures. Eni also holds a 50% interest in the Blue Stream pipeline which links the Russian and Turkish coasts and transport volumes of gas which are jointly supplied by Eni and is Russian partner to Turkish companies.

The EU and U.S.-enacted sanctions are mainly target the financial sector and the energy sector in Russia. The EU sanctions relating to the upstream sector in Russia may negatively impact our ongoing activities, mainly in the exploration sector, unless the Company obtains a waiver from the relevant EU Authorities for projects entered into before enactment of restrictions. Eni started the required authorization procedure before the relevant EU Authorities. However, the outcome is uncertain and we cannot exclude major delays in certain ongoing upstream projects in Russia.

It is possible that wider sanctions covering the Russian energy, banking and/or finance industries may be implemented, which may be targeted at specific individuals or companies or more generally. Further sanctions imposed on Russia, Russian individuals or Russian companies by the international community, such as sanctions enacting restrictions on purchases of Russian gas by European companies or restricting dealings with Russian counterparties could adversely impact Eni’s business, results of operations and cash flow. In addition, an escalation of the crisis and of imposed sanctions could result in 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

> (i) Risks associated with the trading environment and competition in the industry

The Company expects that the profitability outlook in its Gas & Power segment will be negatively affected by a projected weak demand recovery, strong competitive pressures and oversupplies. We believe that these downtrends have become structural headwinds. Gas demand was severely hit by the economic slowdown in Europe and, more importantly, a steep fall in consumption in the thermoelectric sector. The latter trend was affected by an ongoing expansion of renewable sources of electricity which have benefited from governmental subsides across Europe, whilst coal has displaced gas on a large scale in firing power plants due to cost advantages and lowering rates for obtaining emission allowances in Europe due to the economic downturn. Coal prices have seen a dramatic fall in recent years due to a massive glut of coal on a global scale. We do not expect any meaningful recovery in demand for the foreseeable

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future. In the face of weak demand, supplies on the European marketplace have continued to increase due to a number of factors. First of all, before the beginning of the downturn, gas wholesaler operators in Europe (overestimating the projected growth rates in demand) were committed to purchase large amounts of gas under long-term supply contracts with producing countries also bearing the volume risk as a result of the take-or-pay clause of those contracts. They also built large pipeline upgrades to import gas to Europe. Secondly, several LNG projects came on stream, which improved the liquidity of spot markets. Finally, production of shale gas in the United States continued to ramp-up forcing LNG exporters from the Gulf Region and other areas to redirect their LNG supplies to other markets, contributing to increase global gas supplies. Besides certain operators in the United States are planning to build or are actually building LNG export facilities. Those trends drove the expansion of very liquid European hubs where spot prices have become the prevailing benchmark of sale contracts, particularly in the industrial and thermoelectric segments. Spot prices have been on a downtrend over the last few years pressured by oversupplies and weak demand. This trend hit the profitability of European gas marketing operators, including Eni. In particular, Eni’s results of operations were adversely impacted by a faster than anticipated alignment between continental benchmarks and spot prices at Italian hubs leading to sharply lower price realizations in the Italian wholesale market, which is the main market to the Company Gas & Power segment. Adding to the pressure, reduced sales opportunities due to weak demand forced operators to compete even more aggressively on pricing to limit the financial risks associated with the take-or-pay clause provided by the long term supply contracts. Eni forecasts that market conditions will remain unfavorable in the gas sector in Italy and Europe for the foreseeable future due to the structural headwinds described above, volatile commodity prices and lack of visibility. Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the next two to three years. Those include weak demand growth due to a projected slow recovery in the Euro-zone and macroeconomic uncertainties, declining thermoelectric consumption due to inter-fuel competition, continuing oversupplies and strong competition. Eni believes that those trends will negatively impact the gas marketing business future results of operations and cash flows by reducing gas selling prices and margins, also considering Eni’s obligations under its take-or-pay supply contracts.

> The Company is seeking to improve its cost competitiveness by renegotiating more favorable contractual terms with Eni’s long-term suppliers. If it fails to achieve this its profitability could be adversely affected

The Company’s long-term supply contracts provide clauses whereby the parties are entitled to renegotiate pricing terms and other contractual conditions from time to time to reflect a changed market environment. The Company plans to renegotiate better terms and pricing of Eni’s long-term supply contracts in the coming years to align its cost structure which comprise the raw material purchase cost and the associated logistic costs to prices prevailing in the marketplace in order to preserve the profitability of its gas operations and to fulfill the contractual obligation of off-taking the annual minimum take in its long-term supply contracts. If it fails to obtain the planned benefits, future results and cash flow could be adversely affected.

The outcome of the planned renegotiations is uncertain in respect of both the amount of the economic benefits which will be ultimately achieved and the timing of recognition in profit. Should we fail to obtain revised contractual terms, we will evaluate whether to commence arbitration proceedings to satisfy our claims. However, arbitration proceedings may require complex and lengthy processes in order to reach a ruling, thus adding to the uncertainty about the final outcome of those renegotiations. Considering also ongoing price renegotiations with Eni long-term buyers, results of gas marketing activities are subject to an increasing rate of volatility and unpredictability.

> 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 of supplying the Italian gas market and anticipating certain trends in gas demand which actually failed to materialize, Eni has signed a number of long-term gas supply contracts with national operators of key producing countries that supply the European gas markets. These contracts have a residual life of approximately 13 years. 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. The take-or-pay clause entitles the Company to off-take pre-paid volumes of gas in later years. Amounts of cash pre-payments and time schedules for off-taking pre-paid gas vary from contract to contract. Generally, cash pre-payments are calculated on the basis of the energy prices current in the year when the Company is scheduled to purchase the gas, with the balance due in the year when the gas is actually purchased. Amounts of prepayments range from 10 to 100 per cent of the full price.

The right to off-take pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, the right to off-take the pre-paid gas can be exercised in future years provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity. In this case, Eni will pay the residual price calculating it as the percentage that complements

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100 per cent, based on the arithmetical average of monthly base prices current in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.

Although during the recent supply contract round of renegotiations the minimum pre-set volumes of gas that the Company is required to off-take has been significantly reduced, management believes that the current market outlook which will be driven by a weak recovery in gas demand and large gas availability, as well as strong competitive pressures in the marketplace and the possible changes in the sector specific regulation represent a risk factor to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts, considering also the Company’s plans for its sales volumes which are anticipated to remain flat or to decrease slightly in 2015 and in the subsequent years.

This risk materialized during the sector downturn in 2009 through 2012 when the Company accumulated deferred costs amounting to euro 1.9 billion paying the related cash advances to its gas suppliers due to the incurrence of the take-or-pay clause. This amount was substantially reduced in the subsequent years by approximately 50% due to the benefits of contract renegotiations and other commercial initiatives.

> (ii) Risks associated with sector-specific regulations in Italy

> Risks associated with the regulatory powers entrusted to the Italian Authority for Electricity Gas and Water in the matter of pricing to residential customers

The Authority for Electricity Gas and Water (the “AEEGSI”) is entrusted with certain powers in the matter of natural gas pricing. Specifically, the AEEG has general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users (as provided for by Resolution ARG/gas No. 64/2009) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the AEEGSI on these matters may limit the ability of Eni to pass an increase in the cost of the raw material onto final consumers of natural gas.

Effective on October 1, 2013, AEEGSI with Resolution No. 196 reformulated the pricing mechanism of gas supplies to retail customers by introducing a full indexation of the raw material cost component of the tariff to spot prices which replaced an oil-linked indexation. The new regulatory regime negatively impacted the Gas & Power results of operations and cash flow in 2014 compared to 2013 due to unfavorable trends in hub-based pricing to residential compared to the previous oil-linked tariff.

Furthermore, this new regulation provides a mechanism of compensation which addresses the wholesaler operators, as in the case of Eni, who have long-term procurement contracts to supply the Italian market and is designed to promote effective renegotiations of these contracts. The compensation mechanism covers a three-year period and is intended to indemnify wholesalers of possible unfavorable spreads between the oil-linked average prices of gas imported to Italy and the spot prices of gas in sales to residential customers. Vice versa, in case of favorable trends in the above mentioned spreads, the wholesalers have an obligation to refund residential customers. Wholesalers are free to adhere to this compensation mechanism. Eni elected to adhere to it. In 2014, due to unfavorable trends in the cost of oil-linked supplies with respect to spot prices to which gas selling prices are indexed, based on the Authority’s index of procurement costs the Company recognized a gain of euro 60 million. However, due to the current downturn in crude oil prices, Eni is projecting that the oil-linked index of the procurement costs set by the Authority could determine a loss to Eni up to euro 480 million. This contingent liability reflects the fact that the Authority index is not reflective of the current setup of Eni’s portfolio of gas supply costs which due to the renegotiations achieved in 2014 is largely indexed to hub prices and therefore Eni’s procurement costs are not expected to benefit from a fall in oil-linked gas procurement costs. It is still possible that the Authority updates its index of procurement costs to better reflect the status of the gas portfolio of those wholesalers who achieved new pricing terms for their gas supplies. Alternatively, Eni might file an administrative appeal against any deliberations of the Authority on this matter which might possibly lead to unfair results to Eni.

Due to a structurally adverse competitive environment in our Refining & Marketing and Chemicals segments, our prospects to recover profitability depends on our ability to restructure those businesses

Our Refining & Marketing and Chemical segments have been unprofitable for many years to date. Those trends reflected (in addition to movements in the cost of crude oil), competitive disadvantages of our businesses due to industry excess capacity, lack of efficient scale at our refining and chemicals plants and competition from cheaper oil products and commodities coming from Asia, Russia and the United States. We believe that these trends will not reverse in the foreseeable future. We plan on rightsizing our production capacity in those businesses through plant closure, divestments, restructuring and plant conversion to production based on renewable feedstock. If we fail to

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implement capacity restructuring and rationalization as planned, our business, results of operations and financial condition and cash flow could be negatively impacted.

> Antitrust and competition law

The Group’s activities are subject to antitrust and competition laws and regulations in many countries of operations, especially in Europe. It is possible that the Group may incur significant loss provisions in future years relating to ongoing antitrust proceedings or new proceedings that may possibly arise. The Group is particularly exposed to this risk in its natural gas, refining and marketing and petrochemical activities due to the fact that Eni is the incumbent operator in those markets in Italy and a large European player. Furthermore, based on the findings of antitrust proceedings, plaintiffs could seek payment to compensate for any alleged damages as a result of antitrust business practices on part of Eni. Both these risks could adversely affect the Group’s future results of operations and cash flows.

> Environmental, health and safety regulations

> Eni has incurred in the past and will incur material operating expenses and expenditures in relation to compliance with applicable environmental, health and safety regulations in future years

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, refining, chemicals, hydrocarbons transportation and other activities. Generally, these laws and regulations require the 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, as well as refining, petrochemical and other Group’s 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 oil, natural gas, refining, petrochemical and other 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.

Breach of environmental, health and safety laws expose the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for 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 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 addressing the safeguard of the environment, safety on the workplace, health of employees, contractors and communities involved by the Company operations, including:

• |  | costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change;
• |  | remedial and clean-up 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, pollution, contamination or other environmental liability involving 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 license 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:

• |  | modifying operations;

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• |  | installing pollution control equipment;
• |  | implementing additional safety measures; and
• |  | performing site clean-ups.

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. Security threats require continuous assessment and response measures. Acts of terrorism against Eni’s plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change could have a negative impact on Eni’s business and may result in additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for oil and natural gas and production may decline as a result of environmental requirements (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 greenhouse gases 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 greenhouse gases and climate change, including incentives to conserve 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. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon dioxide that could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

Risks of environmental, health and safety incidents and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management’s belief that Eni adopts high operational standards to ensure the safety of its operations and the protection of the environment and the health of people and employees, it is possible that incidents like blowouts, oil spills, contaminations, pollution, release in the air, soil and ground water of pollutants and other dangerous materials, liquids or gases, and similar events could occur that would result in damage to the environment, employees and communities. 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 provisions in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. 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 damages, and other damages as a result of Eni’s conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Also plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found guilty of having violated any environmental laws or regulations.

Eni is periodically notified of potential liabilities at Italian sites. These potential liabilities may arise from both historical Eni operations and the historical operations of companies that Eni has acquired. Many of those potential liabilities relate to certain industrial sites 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 locations Eni has commenced 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. Notwithstanding the Group’s position that it cannot be held liable for contaminations occurred in past years or (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, nonetheless several public administrations used Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company.

Eni expects remedial and clean-up activities at Eni’s sites to continue in the foreseeable future impacting Eni’s liquidity. As of December 31, 2014, 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 liability.

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

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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 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, consolidated results of operations, and consolidated financial condition.

> 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 December 31, 2014 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 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 non-compliance with applicable laws and regulations, including non-compliance 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.

> Risks from acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or companies in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – a significant risk, among other matters, that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks 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 segment, 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.

> Eni’s crisis management systems may be ineffective and Eni may be the target of cyber attacks

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 time frame could prolong the impact of any disruption and could severely affect business and operations. Likewise, 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.

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> 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 optimize 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. The Group’s risk management has evolved particularly in response to the major changes which have occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid gas spot markets.

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 and Risk Management 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 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.

> Commodity risk

Commodity risk is the risk associated with fluctuations in the price of commodities which may impact the Group’s results of operations and cash flow. Exposure to commodity risk is both of a strategic and commercial nature. Generally, the Group does not hedge its strategic exposure to commodity risk. However, the Group actively manages its exposure to commercial risk arising when a contractual sale of a commodity has occurred or it is highly probable that it will occur and the Group aims to lock in the associated commercial margin.

The Group’s risk management policies have evolved particularly in response to the deep changes occurred in the competitive landscape of the gas marketing business, volatile gas margins and development of liquid markets to trade spot gas. These policies also contemplate the use of derivative contracts for speculative purposes whereby Eni is seeking to profit from opportunities available in the gas market based, among other things, on its expectations regarding trends in future prices.

As part of those trading activities, the Company is implementing strategies of asset-backed trading in order to maximize the economic value of the flexibilities associated with its assets. Management believes that the price risks related to asset-backed trading activities are mitigated by the natural hedge granted by the assets’ availability.

These derivative contracts entered into for trading purposes may lead to gains, as well as losses, which, in each case, may be significant. Those derivatives are accounted for through profit and loss, resulting in higher volatility in Eni’s earnings.

> 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 denominated in euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the Chemical segment are denominated both in euros and U.S. dollars. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact

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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 U.S. 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. In 2014, the Exploration & Production results of operations were marginally affected by trends in exchange rate of the euro against the U.S. dollar as the average exchange rate for the full year was substantially flat at 1 EUR = 1.33 US$. However, the decline of the euro against the U.S. dollar in the fourth quarter 2014 resulted in a appreciation of approximately 12% of the U.S. dollar at the closing rate on December 31, 2014 with respect to the closing rate at December 31, 2013 which movements boosted the Group net equity by approximately euro 5 billion as a result of the translation differences of the net assets of dollar-denominated subsidiaries. This trend has continued in the first quarter of 2015.

> 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 impact 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 concerns over the European sovereign debt crisis and weak macroeconomic growth, particularly in the Euro-zone. If there are 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. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation and production of oil and natural gas reserves.

Historically, our capital expenditures have been financed with cash generated by operations, proceeds from asset disposal, borrowings under our credit facility and proceeds from the issuance of debt and bonds. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, changes in commodity prices, available cash flows, lack of access to capital, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments.

Our cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to:

• |  | the amount of our proved reserves;
• |  | the volume of crude oil and natural gas we are able to produce and sell from existing wells;
• |  | the prices at which crude oil and natural gas are sold;
• |  | our ability to acquire, find and produce new reserves; and

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• |  | the ability and willingness of our lenders to extend credit or of participants in the capital markets to invest in our bonds.

If revenues or our ability to borrow decrease significantly due to factors like a prolonged decline in crude oil and natural gas prices, we might have limited ability to obtain the capital necessary to sustain our planned capital expenditures. If cash generated by operations, cash from asset disposal, or cash available under our liquidity reserve or our 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 our reserves, which in turn could adversely affect our business, financial condition, results of operations, and cash flows and our ability to achieve our growth plans.

In addition, funding our capital expenditures with additional debt will increase our leverage and the issuance of additional debt will require a portion of our cash flows from operations to be used for the payment of interest and principal on our debt, thereby reducing our 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 recent years, the Group has experienced a higher than normal level of counterparty default 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. In Eni’s 2014 Consolidated Financial Statements, Eni accrued an allowance against doubtful accounts amounting to euro 531 million (compared to euro 384 million), mainly relating to the Gas & Power business. Management believes that this business is particularly exposed to credit risks due to its large and diversified customer base which include a large number of medium and small sized businesses and retail customers who have been particularly impacted by the financial and economic downturn. However, trade receivable amounts due at the balance sheet date have also increased in relation to supplies of the Group’s products to state-owned companies, public administrations and other governmental agencies in Italy and abroad. Eni believes that the management of doubtful accounts represents an issue to the Company which will require management focus and commitment going forward. In the future we cannot exclude the recognition of significant provisions for doubtful accounts.

> Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, 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 and 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 activities, specifically the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and other risk provisions and recognition of revenues in the oilfield services construction and engineering businesses. Although management believes these estimates to represent the best outcome of the estimation process, actual results could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information, availability of new informative elements, variations in economic conditions such as prices, costs, other significant factors including evolution in technologies, industrial practices and standards (e.g. removal technologies) and the final outcome of legal, environmental or regulatory proceedings.

> Digital infrastructure is an important part of maintaining Eni’s operations, and 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

The reliability and security of Eni’s digital infrastructure is critical to maintaining the availability of Eni’s business applications, including the reliable operation of technology in Eni’s various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. If Eni’s systems for protecting Eni’s digital security prove not to be sufficient, either due to intentional actions such as cyber attacks or due to negligence, Eni could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data, having Eni’s business operations interrupted, and increased costs to prevent, respond to, or mitigate potential risks to Eni’s digital infrastructure; also, in some circumstances, failures to

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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.

> The Company’s auditors, like all other independent registered public accounting firms operating in Italy, are not permitted to be subject to inspection by the Public Company Accounting Oversight Board, and accordingly, investors may be deprived of the benefits of such inspection

The independent registered public accounting firm that issues the audit reports included in Eni’s annual reports filed with the U.S. Securities and Exchange Commission (the U.S. SEC), as auditor of companies that are traded publicly in the United States and firms registered with the Public Company Accounting Oversight Board, or PCAOB, is required by the laws of the United States to undergo regular inspections by the PCAOB to assess its compliance with U.S. SEC rules and PCAOB professional standards.

Because Eni’s auditor is a registered public accounting firm in Italy, a jurisdiction where the PCAOB is currently unable under Italian law to conduct inspections pending the mutual agreement between the PCAOB and the Italian Authorities, Eni’s auditor, like all other independent registered public accounting firms in Italy, is currently not inspected by the PCAOB. Inspections of audit firms that the PCAOB has conducted where allowed have identified deficiencies in those firms’ audit procedures and quality control procedures, which may be addressed as part of the inspection process to improve future audit quality. The lack of PCAOB inspections in Italy prevents the PCAOB from regularly evaluating Eni’s auditor’s audits and quality control procedures. As a result, the inability of the PCAOB to conduct inspections of auditors in Italy may deprive investors of the benefits of PCAOB inspections.

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Item 4. INFORMATION ON THE COMPANY

History and development of the Company

Eni SpA with its consolidated subsidiaries engages in oil and gas exploration, development and production, marketing of gas, electricity and LNG, power generation, refining and marketing of petroleum products, production and marketing of petrochemical products, commodity trading and oilfield services and engineering industries. Eni has operations in 83 countries and 84,405 employees as of December 31, 2014.

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.

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

The name of the agent of Eni in the United States is Pasquale Salzano, 485 Madison Avenue, New York, NY 10002.

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 40 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2014, Eni average daily production amounted to 1,517 KBOE/d on an available-for-sale basis. As of December 31, 2014, Eni’s total proved reserves amounted to 6,602 mmBOE; proved reserves of subsidiaries totaled 5,772 mmBOE; Eni’s share of reserves of equity-accounted entities was 830 mmBOE. In 2014, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 28,488 million and operating profit of euro 10,766 million.

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international gas transport activities, and LNG supply and marketing. This segment also includes the activity of electricity generation that is ancillary to the marketing of electricity. In 2014, Eni’s worldwide sales of natural gas amounted to 89.17 BCM. Sales in Italy amounted to 34.04 BCM, while sales in European markets were 55.13 BCM which included 4.01 BCM of gas sold to certain importers to Italy. Eni produces power at a number of operated sites in Italy with a total installed capacity of 4.9 GW as of December 31, 2014. In 2014, sales of power totaled 33.58 TWh. In 2014, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 28,250 million and operating profit of euro 186 million.

Eni’s Refining & Marketing segment engages in crude oil supply and refining and marketing of petroleum products at retail and wholesale markets mainly in Italy and in the rest of Europe. In 2014, processed volumes of crude oil and other feedstock amounted to 25.03 mmtonnes and sales of refined products were 44.41 mmtonnes, of which 22.76 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 9.21 mmtonnes in Italy and in the rest of Europe. In 2014, Eni’s retail market share in Italy through its "Eni" and "Agip" branded network of service stations was 25.5%. In 2014, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 56,153 million and operating loss of euro 2,229 million.

Eni also engages in commodity risk management and 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. The objective of this activity is both to hedge part of the Group exposure to the commodity risk and to optimize commercial margins by entering speculative derivative transactions. Eni Trading & Shipping SpA and its subsidiaries also provide Group companies with crude oil and products supply, trading and shipping services. The results of the activity of commodity risk management and other services are reported within the Gas & Power segment with regard to the results on commodity risk management activities relating to gas and electricity; while the portion of results which pertains to oil and products trading derivatives and supply and shipping services are reported within the Refining & Marketing segment.

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Eni’s chemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s chemical operations are concentrated in Italy and Western Europe. In 2014, Eni sold 3.46 mmtonnes of chemical products. In 2014, Eni’s Chemical segment reported net sales from operations (including inter-segment sales) of euro 5,284 million and operating loss of euro 704 million.

Eni engages in oilfield services, construction and engineering activities through its partially-owned subsidiary Saipem and Saipem’s controlled entities (Eni’s interest being 42.91%). Saipem provides a full range of engineering, drilling and construction services to the oil and gas industry and downstream refining and petrochemical sectors, mainly in the field of performing large EPC contracts offshore and onshore for the construction and installation of fixed platforms, sub-sea pipe laying and floating production systems and onshore industrial complexes. In 2014, Eni’s Engineering & Construction segment reported net sales from operations (including intragroup sales) of euro 12,873 million and operating profit of euro 18 million.

A list of Eni’s subsidiaries is included as an exhibit to this Annual Report on Form 20-F.

> Strategy

In order to manage a radically changed price environment, the Company outlined for the next four-year period an action plan which comprises a number of rigorous initiatives and objectives in order to mitigate the impact of lower oil prices and to preserve a robust financial structure, particularly in the short to medium term. Our oil price assumptions for the Brent benchmark are $55 per barrel in 2015 and we expect a gradual recovery in the subsequent years up to our long term case of $90 per barrel. Against the backdrop of a low price environment in the short to medium term, our primary target remains cash generation which will be underpinned by well-designed industrial actions, capital discipline, focus on Exploration & Production activities and a large disposal plan. In approving the capital expenditure plan the Company selected high-return projects with short pay-back periods; this optimization will result in a euro 48 billion capital expenditures in the next four years, down by approximately 17% compared to the previous plan, net of exchange rate effects. The disposal plan, amounting to more than euro 8 billion in the 2015-2018 period, is based on the anticipated monetization of exploratory discoveries, optimization of the upstream portfolio, rationalization of midstream and downstream portfolio, and the divestment of residual interests in Snam and Galp. The Company forecasts that the planned industrial actions, the selective approach to capital expenditure and the disposal plan will enable Eni to preserve a robust financial structure and we plan to maintain the leverage below the threshold of 0.3 throughout the oil cycle. As part of its effort to preserve liquidity and the balance sheet, the Company decided to rebase the dividend as it is planning to pay a dividend of euro 0.8 per share for fiscal year 2015. In the subsequent years, management will re asses its progressive dividend policy against the backdrop of an expected improvement in the oil price scenario and the planned growth in our cash generation as our value-generation strategy in Exploration & Production and our turnaround of Gas & Power, Refining & Marketing and Chemicals progress towards our goals. See “Item 5 – Management’s expectations of operations”.

• |  | In the Exploration & Production segment we plan to preserve cash generation in a low oil price environment. To achieve this objective we plan the following strategic actions: (i) focus on near-field exploration reducing expenditures; (ii) fast track development of discovered resources through the optimization of the time-to-market and strict control of project execution; (iii) monetization of interests in discoveries made; (iv) production growth at an average rate of 3.5% across the plan period, maintaining a solid base of long plateau/long-term cash flow projects; (v) modular approach and phased project development in order to reduce the financial exposure and fasten production start-up; and (vi) increased efficiency through a wide range of actions aimed at reducing operating costs, pursued also through the renegotiations of supply contracts.
• |  | In the Gas & Power segment we are seeking to preserve the economic and financial sustainability in the long term against the backdrop of structural headwinds in the European gas sector where we do not expect significant improvement in the trading environment due to continued weak demand, strong competition and oversupplies which will affect sale prices and margins.
|  | Our turnaround strategy will be driven by the renegotiation of our entire portfolio of long-term supply contracts in order to align our cost position to prevailing market conditions. The consolidation of profitability and cash generation will be helped by the streamlining of operations and optimization of logistic costs, focusing on the development and growth in value added segments.
• |  | Our priority in the Refining & Marketing segment is to recover profitability and positive cash generation in a short time frame against the backdrop of weak industry fundamentals and an unfavorable trading environment. We plan to complete our target of up to 50% refining capacity reduction also through process reconversion in Italy and to implement a number of efficiency and cost reduction initiatives, energy saving and optimization of plant operations, in order to drive margin expansions. In the marketing business in Italy we plan to enhance profitability by closing down marginal outlets and continuing upgrading our modern and most efficient service stations, also improving service quality and client retention and non-oil profit contribution taking into account a weak outlook for fuel consumption. Outside Italy, Eni plans to grow selectively in target European markets and divest marginal assets.

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• |  | Our Engineering & Construction segment is expected to strength profitability and reinforce the financial structure. Management plans to focus on working capital optimization and selective capital expenditure. In the next four-year plan we will leverage on our competitive advantages in ultra-deep projects, in the lying of large-diameter pipelines in harsh environments and complex onshore projects. We intend to complete legacy projects with low profitability with the aim to focus on certain projects leveraging on our technologically-advanced assets and our skills in engineering and project management, as well as by strengthening the EPC model.
• |  | In the Chemical segment, management intends to recover profitability by progressively reducing the exposure to loss-making commodity business lines. This will be achieved by restructuring production capacity by plant closure, divestment or reconversion, and by refocusing the chemical business on more profitable market segments. Our return to profitability will be underpinned by a progressive growth in the production of chemicals based on green technologies and in niche productions such as elastomers where we have the competitive advantage granted by proprietary technologies. We also plan to expand our elastomers and other niche productions internationally to seek to capture opportunities for growth and returns in the fast-growing Asian markets leveraging our technologies and know-how in those fields.

In executing this strategy, management intends to pursue integration opportunities among segments and within each segment to strongly focus on efficiency improvement through technology upgrading, cost efficiencies, commercial and supply optimization and continuing process streamlining across all segments.

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 2014 and to date in 2015 were the following:

• |  | In April 2015, Versalis and the South Korean petrochemical company LOTTE Chemical extended their cooperation in the elastomers business under a technology license agreement regarding, in particular, the Styrene-Isoprene-Styrene and Styrene-Butadiene-Styrene (SIS/SBS) product lines to target the specialty hot-melt adhesives market and additional market segments such as technical and sports articles, bitumen and plastics.
• |  | In March 2015, Eni signed, within the framework of Egyptian Economic Development Conference (EEDC), a framework agreement for the development of Egypt’s oil and gas resources by investing approximately $5 billion. The investments to be implemented in the next 4 years are directed to the development of significant oil and gas reserves.
• |  | In March 2015, Eni made a significant discovery of gas and condensates offshore Libya, in the Bahr Essalam South exploration prospect. The proximity to the Bahr Essalam infrastructures will allow a quick development of this new discovery.
• |  | On January 15, 2014, Eni sold to certain Gazprom subsidiaries its 60% interest in Artic Russia which is the parent company with a 49% stake of Severenergia, which holds four licenses for the exploration and production of hydrocarbons in the Region of Yamal Nenets (Siberia), including in particular the on stream field of Samburgskoye, Eni’s first development in the Russian upstream. The cash consideration for the disposal amounted to euro 2.16 billion ($2,940 million).
• |  | In December 2014, Eni divested to Gazprom its 20% stake in South Stream Transport BV engaged in the economic feasibility, procurement and construction of the offshore section of the South Stream pipeline. Pursuant to the shareholders’ agreement, Eni exercised a put option of its stake whereby the Company will recover the capital invested to date in the project, determined in accordance with existing agreements.
• |  | At the end of December 2014, Versalis signed an agreement to divest the Sarroch plant to the refining company Saras, which owns a refinery close to Eni’s petrochemical site. The agreement includes the disposal of the Versalis plants connected with the production cycle of the refinery, in particular the reforming unit, the propylene splitter unit and other related services, including the logistics system. Versalis will continue to operate on the site with the planned HSE activities and environmental remediation activities, not included in the transaction.
• |  | The exploration campaign carried out in 2014 achieved success with: (i) the Ochigufu well, in the deep waters of Block 15/06 (Eni operator with a 35% interest). This discovery is located near the West Hub oil project, which started up at the end of 2014. In January 2015, Eni obtained from the Angolan authorities a three-year extension of the exploration period of the above mentioned block; (ii) Congo: in the conventional waters of Block Marine XII, the Minsala well marked the third oil discovery in the last two, with characteristics similar to the previous discoveries of Litchendjili and Nené, the latter started up early production in quick time; (iii) Ecuador: the Oglan well in Block 10 (Eni operator with a 100% interest), located near the processing facilities of the operated Villano oilfield; (iv) Indonesia: the Merakes gas discovery in East Sepinggan offshore Block (Eni operator with a 85% interest). This discovery is located in proximity of the operated field of Jangkrik, which is currently under development and will supply additional gas volumes to the Bontang

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|  | LNG plant; and (v) Mozambique: the appraisal gas wells Agulha 2 at Mamba and Coral 4 DIR confirmed the extension of their respective discoveries in Area 4 (Eni operator with a 50% interest).
• |  | In November 2014, Eni defined with the Ministry for Economic Development, the Region of Sicily and interested stakeholders (including trade unions and local communities) a plan to restore the profitability of the Gela refinery. Key to the agreement is the reconversion of the Gela site into a bio-refinery. This will follow the model adopted in the Venice green refinery scheme, where green diesel will be produced from raw vegetable materials by using the proprietary EcofiningTM technology. The agreement also defines terms for building a modern logistic pole and new initiatives in the upstream sector in Sicily. Eni will also perform environmental remediation and cleanup activities and institute a competence center for safety. The investment plan for such initiatives amounts to euro 2.2 billion, mainly relating to upstream projects in the Sicily Region.
• |  | In August 2014, Eni divested its stake in EnBW Eni Verwaltungsgesellschaft (EEV), a joint venture which controls the companies Gasversorgung Süddeutschland (GVS) and Terranets BW, to its current partner EnBW (Energie Baden-Württemberg). In 2013, Eni’s share of the sales volumes made by the joint venture amounted to 2.62 BCM.
• |  | In June 2014, the start-up of the bio-refinery of Porto Marghera was achieved, with green diesel capacity of approximately 300 ktonnes/y, from refined vegetable oil, utilizing the proprietary EcofiningTM technology. The production will fulfill half of Eni’s annual requirement of green diesel, thus ensuring new perspectives for the industrial site of Venice and allowing economic and environmental benefits.
• |  | In June 2014, the green chemical project of Matrìca, a 50/50 joint venture between Eni’s subsidiary Versalis and Novamont, started operations marking the full conversion of the Porto Torres site. Matrìca’s plant is currently leveraging on innovative technology to transform vegetable oils into monomers and intermediates that are feedstock for the production of complex bio-products destined for a number of industries such as the tyre industry, bio-lubricants and plastic production. The overall production capacity of approximately 70 ktonnes per year will come gradually online during 2015. Cracking production line was closed definitively.
• |  | In the first half of 2014, Eni completed the divestment of Galp through the sale of approximately 8% of the share capital of the investee for a cash consideration of euro 824 million. Following the sale, Eni holds approximately 8% of Galp’s share capital, entirely underlying the approximately euro 1,028 million exchangeable bond issued on November 30, 2012 and due on November 30, 2015.
• |  | In May 2014, Eni signed a preliminary agreement for the divestment of Eni’s marketing activities of fuels located in Czech Republic, Slovakia and Romania to the Hungarian Company MOL. The agreement also comprises the refinery capacity to supply the marketing network through a 32.445% interest in the joint refining asset Ceská Rafinérská as (CRC). The latter will be ultimately purchased by another partner in the venture, Unipetrol, which exercised the relevant preemption rights according to the conditions agreed by Eni and MOL. All these agreements are subject to the approval of the relevant European Antitrust Authorities.

In addition, Eni closed the following transactions:

• |  | In March 2015, following its participation in the competitive International Bid Round launched by the Republic of the Union of Myanmar, Eni signed two Production Sharing Contracts (PSC) for offshore blocks MD-02 and MD-04. These contracts foresee a study period of two years, followed by a 3-phases exploration period lasting six years.
• |  | In January 2015, Eni and the relevant authorities of Ghana sanctioned the OCTP integrated oil and gas project (Eni 47.22%, operator). First oil is expected in 2017, first gas in 2018 and production is expected to peak at 80,000 BOE/d.
• |  | In June 2014, Eni signed a strategic agreement with the Kazakh national company KazMunaiGas (KMG) for the exploitation of exploration and production rights in the Isatay area, located in the North Caspian Sea, through a joint operating company.
• |  | In October 2014, a Memorandum of Understanding and Cooperation was signed with the National Company Petroleos Mexicanos (Pemex) establishing the basis for future cooperation in the upstream and other business segments and areas.
• |  | In November 2014, Eni and the State oil company Turkmenneft agreed to extend up to 2032 the production sharing agreement regulating exploration and production activities at the onshore Nebit Dag Block. The agreements also establish the transfer of a 10% stake out of the contractor share to Turkmenneft.
• |  | In July 2014, a cooperation agreement was signed with the relevant authorities to extend existing oil permits and to develop new initiatives in the Country’s coastal basin, which extends from onshore Mayombe to frontage deep waters. At the end of December 2014, Eni started production at the recent Nené discovery in Block Marine XII (Eni’s interest 65%, operator) just eight months after obtaining the production permit. The early production phase is yielding 7,500 BOE/d and the fast-track development of the field has leveraged on the synergies with the front-end loading and the infrastructures of the fields located in the area. The full-field development will take place in several stages and will include the installation of production platforms and the drilling of over 30 wells, with a plateau of over 120,000 BOE/d.

In 2014, capital expenditures amounted to euro 12,240 million, of which 92% related to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 9,021 million) deployed mainly in Norway, Angola, Congo, the United States, Italy, Nigeria, Egypt, Indonesia and Kazakhstan and exploratory projects (euro 1,398 million) carried out primarily in Libya, Mozambique, the United States, Nigeria, Angola, Indonesia, Cyprus, Norway and Gabon; (ii) upgrading of the fleet used in the Engineering

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& Construction segment (euro 694 million); (iii) refining, supply and logistics in Italy and outside Italy (euro 362 million) with projects designed to improve the conversion rate and flexibility of refineries, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 175 million); and (iv) initiatives to improve flexibility of the combined-cycle power plants (euro 98 million).

In 2013, capital expenditures of continuing operations amounted to euro 12,800 million, of which 89% related to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 8,580 million) deployed mainly in Norway, the United States, Angola, Congo, Italy, Nigeria, Kazakhstan, Egypt and the United Kingdom, and exploration projects (euro 1,669 million) carried out mainly in Mozambique, Norway, Congo, Togo, Nigeria, the United States and Angola; (ii) upgrading of the fleet used in the Engineering & Construction segment (euro 902 million); (iii) refining, supply and logistics in Italy and outside Italy (euro 462 million) with projects designed to improve the conversion rate and flexibility of refineries, in particular at the Sannazzaro refinery, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 210 million); and (iv) initiatives to improve flexibility of the combined-cycle power plants (euro 119 million). There were no significant acquisitions in the year.

In 2012, capital expenditures of continuing operations amounted to euro 12,805 million, of which 89% related to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 8,304 million) deployed mainly in Norway, the United States, Congo, Italy, Kazakhstan, Angola and Algeria, and exploration projects (euro 1,850 million) carried out mainly in Mozambique, Liberia, Ghana, Indonesia, Nigeria, Angola and Australia; (ii) upgrading of the fleet used in the Engineering & Construction segment (euro 1,011 million); (iii) refining, supply and logistics with projects designed to improve the conversion rate and flexibility of refineries (euro 639 million), in particular at the Sannazzaro refinery, as well as upgrading and rebranding of the refined product retail network (euro 259 million); and (iv) initiatives to improve flexibility of the combined-cycle power plants (euro 123 million). There were no significant acquisitions in the year.

BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 40 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2014, Eni average daily production amounted to 1,517 KBOE/d on an available-for-sale basis. As of December 31, 2014, Eni’s total proved reserves amounted to 6,602 mmBOE; proved reserves of subsidiaries totaled 5,772 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 830 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 3.5% on average in the next 2015-2018 four-year period, based on our long-term Brent price assumptions of 90 $/BBL and 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, Barents Sea, Kazakhstan, Venezuela and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. We plan to start 16 new large fields over the next four years which will contribute more with than 650 KBOE/d of new production by 2018; about 90% of these new projects have already been sanctioned and 84% operated.

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 euro 36 billion to develop reserves over the next four years, with a decrease of 12% net of exchange rate effects versus the previous four-year plan to mitigate the impact of a low oil price environment. We plan to prioritize lower intensity projects, brown-field developments and infilling wells mainly in Congo, Angola and Egypt, 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.

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Exploration projects will attract some euro 5 billion with a reduction of 35% net of exchange rate effects in 2015 and 25% over the plan period. Exploration expenditure will be focused on proven plays and near-field exploration, where we plan to drill 70% of our scheduled wells. The most important amounts of exploration expenses will be incurred in Norway, Nigeria, the United States and Italy.

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 these initiatives we believe that almost all of our project which we are currently developing over the next four-year plan will be completed on time and on cost schedule.

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; (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 2015, management plans to spend over euro 10 billion in reserves development and exploration projects.

> Disclosure of reserves

> Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and 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 and 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 and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and 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.

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> 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 tasks 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.

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 U.S. SEC rules1. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines.

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditures, 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 "Politecnico di Torino" and received a Master of Science degree in Mining Engineering in 1985. She has more than 25 years of experience in the oil and 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 evaluation2 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 report3. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.

In order to calculate the 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 2014, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 27% of Eni’s total proved reserves at December 31, 20144, confirming, as in previous years, the reasonableness of Eni internal evaluation5.

In the 2012-2014 three-year period, 94% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2014, the main Eni properties not subjected to independent evaluation in the last three years were M’Boundi (Congo) and Junin 5 (Venezuela).

(1) | i | See "Item 19 – Exhibits" in the Annual Report on Form 20-F 2009.
(2) | i | From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.
(3) | i | See "Item 19 – Exhibits".
(4) | i | Includes Eni’s share of proved reserves of equity-accounted entities.
(5) | i | See "Item 19 – Exhibits".

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> Summary of proved oil and gas reserves

The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2014, 2013 and 2012. Net proved reserves are set out in more detail under the heading "Supplemental oil and gas information" on page F-138.

HYDROCARBONS (mmBOE) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total reserves

Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  | 524 |  | 591 |  | 1,915 |  | 1,048 |  | 1,041 |  | 184 |  | 236 |  | 128 |  | 5,667
developed |  | 406 |  | 349 |  | 1,080 |  | 716 |  | 458 |  | 108 |  | 170 |  | 107 |  | 3,394
undeveloped |  | 118 |  | 242 |  | 835 |  | 332 |  | 583 |  | 76 |  | 66 |  | 21 |  | 2,273
Year ended Dec. 31, 2013 |  | 499 |  | 557 |  | 1,783 |  | 1,155 |  | 1,035 |  | 263 |  | 240 |  | 176 |  | 5,708
developed |  | 408 |  | 343 |  | 1,003 |  | 701 |  | 566 |  | 90 |  | 153 |  | 123 |  | 3,387
undeveloped |  | 91 |  | 214 |  | 780 |  | 454 |  | 469 |  | 173 |  | 87 |  | 53 |  | 2,321
Year ended Dec. 31, 2014 |  | 503 |  | 544 |  | 1,740 |  | 1,239 |  | 1,069 |  | 285 |  | 232 |  | 160 |  | 5,772
developed |  | 401 |  | 335 |  | 904 |  | 702 |  | 589 |  | 112 |  | 188 |  | 135 |  | 3,366
undeveloped |  | 102 |  | 209 |  | 836 |  | 537 |  | 480 |  | 173 |  | 44 |  | 25 |  | 2,406
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  |  |  |  |  | 20 |  | 81 |  |  |  | 668 |  | 730 |  |  |  | 1,499
developed |  |  |  |  |  | 20 |  |  |  |  |  | 82 |  | 20 |  |  |  | 122
undeveloped |  |  |  |  |  |  |  | 81 |  |  |  | 586 |  | 710 |  |  |  | 1,377
Year ended Dec. 31, 2013 |  |  |  |  |  | 19 |  | 75 |  |  |  | 7 |  | 726 |  |  |  | 827
developed |  |  |  |  |  | 19 |  |  |  |  |  | 3 |  | 18 |  |  |  | 40
undeveloped |  |  |  |  |  |  |  | 75 |  |  |  | 4 |  | 708 |  |  |  | 787
Year ended Dec. 31, 2014 |  |  |  |  |  | 16 |  | 81 |  |  |  | 5 |  | 728 |  |  |  | 830
developed |  |  |  |  |  | 15 |  | 23 |  |  |  | 3 |  | 26 |  |  |  | 67
undeveloped |  |  |  |  |  | 1 |  | 58 |  |  |  | 2 |  | 702 |  |  |  | 763
Consolidated subsidiaries and equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  | 524 |  | 591 |  | 1,935 |  | 1,129 |  | 1,041 |  | 852 |  | 966 |  | 128 |  | 7,166
developed |  | 406 |  | 349 |  | 1,100 |  | 716 |  | 458 |  | 190 |  | 190 |  | 107 |  | 3,516
undeveloped |  | 118 |  | 242 |  | 835 |  | 413 |  | 583 |  | 662 |  | 776 |  | 21 |  | 3,650
Year ended Dec. 31, 2013 |  | 499 |  | 557 |  | 1,802 |  | 1,230 |  | 1,035 |  | 270 |  | 966 |  | 176 |  | 6,535
developed |  | 408 |  | 343 |  | 1,022 |  | 701 |  | 566 |  | 93 |  | 171 |  | 123 |  | 3,427
undeveloped |  | 91 |  | 214 |  | 780 |  | 529 |  | 469 |  | 177 |  | 795 |  | 53 |  | 3,108
Year ended Dec. 31, 2014 |  | 503 |  | 544 |  | 1,756 |  | 1,320 |  | 1,069 |  | 290 |  | 960 |  | 160 |  | 6,602
developed |  | 401 |  | 335 |  | 919 |  | 725 |  | 589 |  | 115 |  | 214 |  | 135 |  | 3,433
undeveloped |  | 102 |  | 209 |  | 837 |  | 595 |  | 480 |  | 175 |  | 746 |  | 25 |  | 3,169

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LIQUIDS (mmBBL) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total reserves

Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  | 227 |  | 351 |  | 904 |  | 672 |  | 670 |  | 82 |  | 154 |  | 24 |  | 3,084
developed |  | 165 |  | 180 |  | 584 |  | 456 |  | 203 |  | 41 |  | 109 |  | 24 |  | 1,762
undeveloped |  | 62 |  | 171 |  | 320 |  | 216 |  | 467 |  | 41 |  | 45 |  |  |  | 1,322
Year ended Dec. 31, 2013 |  | 220 |  | 330 |  | 830 |  | 723 |  | 679 |  | 128 |  | 147 |  | 22 |  | 3,079
developed |  | 177 |  | 179 |  | 561 |  | 465 |  | 295 |  | 38 |  | 96 |  | 20 |  | 1,831
undeveloped |  | 43 |  | 151 |  | 269 |  | 258 |  | 384 |  | 90 |  | 51 |  | 2 |  | 1,248
Year ended Dec. 31, 2014 |  | 243 |  | 331 |  | 776 |  | 739 |  | 697 |  | 131 |  | 147 |  | 13 |  | 3,077
developed |  | 184 |  | 174 |  | 521 |  | 470 |  | 306 |  | 64 |  | 116 |  | 12 |  | 1,847
undeveloped |  | 59 |  | 157 |  | 255 |  | 269 |  | 391 |  | 67 |  | 31 |  | 1 |  | 1,230
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  |  |  |  |  | 17 |  | 16 |  |  |  | 114 |  | 119 |  |  |  | 266
developed |  |  |  |  |  | 17 |  |  |  |  |  | 8 |  | 19 |  |  |  | 44
undeveloped |  |  |  |  |  |  |  | 16 |  |  |  | 106 |  | 100 |  |  |  | 222
Year ended Dec. 31, 2013 |  |  |  |  |  | 16 |  | 15 |  |  |  | 1 |  | 116 |  |  |  | 148
developed |  |  |  |  |  | 16 |  |  |  |  |  |  |  | 19 |  |  |  | 35
undeveloped |  |  |  |  |  |  |  | 15 |  |  |  | 1 |  | 97 |  |  |  | 113
Year ended Dec. 31, 2014 |  |  |  |  |  | 14 |  | 17 |  |  |  | 1 |  | 117 |  |  |  | 149
developed |  |  |  |  |  | 13 |  | 7 |  |  |  |  |  | 26 |  |  |  | 46
undeveloped |  |  |  |  |  | 1 |  | 10 |  |  |  | 1 |  | 91 |  |  |  | 103
Consolidated subsidiaries and equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  | 227 |  | 351 |  | 921 |  | 688 |  | 670 |  | 196 |  | 273 |  | 24 |  | 3,350
developed |  | 165 |  | 180 |  | 601 |  | 456 |  | 203 |  | 49 |  | 128 |  | 24 |  | 1,806
undeveloped |  | 62 |  | 171 |  | 320 |  | 232 |  | 467 |  | 147 |  | 145 |  |  |  | 1,544
Year ended Dec. 31, 2013 |  | 220 |  | 330 |  | 846 |  | 738 |  | 679 |  | 129 |  | 263 |  | 22 |  | 3,227
developed |  | 177 |  | 179 |  | 577 |  | 465 |  | 295 |  | 38 |  | 115 |  | 20 |  | 1,866
undeveloped |  | 43 |  | 151 |  | 269 |  | 273 |  | 384 |  | 91 |  | 148 |  | 2 |  | 1,361
Year ended Dec. 31, 2014 |  | 243 |  | 331 |  | 790 |  | 756 |  | 697 |  | 132 |  | 264 |  | 13 |  | 3,226
developed |  | 184 |  | 174 |  | 534 |  | 477 |  | 306 |  | 64 |  | 142 |  | 12 |  | 1,893
undeveloped |  | 59 |  | 157 |  | 256 |  | 279 |  | 391 |  | 68 |  | 122 |  | 1 |  | 1,333

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NATURAL GAS (BCF) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total reserves

Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  | 1,633 |  | 1,317 |  | 5,558 |  | 2,061 |  | 2,038 |  | 562 |  | 449 |  | 572 |  | 14,190
developed |  | 1,325 |  | 925 |  | 2,720 |  | 1,429 |  | 1,401 |  | 372 |  | 334 |  | 459 |  | 8,965
undeveloped |  | 308 |  | 392 |  | 2,838 |  | 632 |  | 637 |  | 190 |  | 115 |  | 113 |  | 5,225
Year ended Dec. 31, 2013 |  | 1,532 |  | 1,247 |  | 5,231 |  | 2,374 |  | 1,957 |  | 744 |  | 509 |  | 848 |  | 14,442
developed |  | 1,266 |  | 904 |  | 2,432 |  | 1,295 |  | 1,488 |  | 286 |  | 310 |  | 561 |  | 8,542
undeveloped |  | 266 |  | 343 |  | 2,799 |  | 1,079 |  | 469 |  | 458 |  | 199 |  | 287 |  | 5,900
Year ended Dec. 31, 2014 |  | 1,432 |  | 1,171 |  | 5,291 |  | 2,744 |  | 2,049 |  | 846 |  | 468 |  | 807 |  | 14,808
developed |  | 1,192 |  | 887 |  | 2,110 |  | 1,271 |  | 1,553 |  | 261 |  | 393 |  | 675 |  | 8,342
undeveloped |  | 240 |  | 284 |  | 3,181 |  | 1,473 |  | 496 |  | 585 |  | 75 |  | 132 |  | 6,466
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  |  |  |  |  | 16 |  | 353 |  |  |  | 3,043 |  | 3,355 |  |  |  | 6,767
developed |  |  |  |  |  | 16 |  |  |  |  |  | 402 |  | 6 |  |  |  | 424
undeveloped |  |  |  |  |  |  |  | 353 |  |  |  | 2,641 |  | 3,349 |  |  |  | 6,343
Year ended Dec. 31, 2013 |  |  |  |  |  | 15 |  | 330 |  |  |  | 28 |  | 3,353 |  |  |  | 3,726
developed |  |  |  |  |  | 15 |  |  |  |  |  | 14 |  | 5 |  |  |  | 34
undeveloped |  |  |  |  |  |  |  | 330 |  |  |  | 14 |  | 3,348 |  |  |  | 3,692
Year ended Dec. 31, 2014 |  |  |  |  |  | 15 |  | 351 |  |  |  | 18 |  | 3,353 |  |  |  | 3,737
developed |  |  |  |  |  | 15 |  | 89 |  |  |  | 10 |  | 6 |  |  |  | 120
undeveloped |  |  |  |  |  |  |  | 262 |  |  |  | 8 |  | 3,347 |  |  |  | 3,617
Consolidated subsidiaries and equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2012 |  | 1,633 |  | 1,317 |  | 5,574 |  | 2,414 |  | 2,038 |  | 3,605 |  | 3,804 |  | 572 |  | 20,957
developed |  | 1,325 |  | 925 |  | 2,736 |  | 1,429 |  | 1,401 |  | 774 |  | 340 |  | 459 |  | 9,389
undeveloped |  | 308 |  | 392 |  | 2,838 |  | 985 |  | 637 |  | 2,831 |  | 3,464 |  | 113 |  | 11,568
Year ended Dec. 31, 2013 |  | 1,532 |  | 1,247 |  | 5,246 |  | 2,704 |  | 1,957 |  | 772 |  | 3,862 |  | 848 |  | 18,168
developed |  | 1,266 |  | 904 |  | 2,447 |  | 1,295 |  | 1,488 |  | 300 |  | 315 |  | 561 |  | 8,576
undeveloped |  | 266 |  | 343 |  | 2,799 |  | 1,409 |  | 469 |  | 472 |  | 3,547 |  | 287 |  | 9,592
Year ended Dec. 31, 2014 |  | 1,432 |  | 1,171 |  | 5,306 |  | 3,095 |  | 2,049 |  | 864 |  | 3,821 |  | 807 |  | 18,545
developed |  | 1,192 |  | 887 |  | 2,125 |  | 1,360 |  | 1,553 |  | 271 |  | 399 |  | 675 |  | 8,462
undeveloped |  | 240 |  | 284 |  | 3,181 |  | 1,735 |  | 496 |  | 593 |  | 3,422 |  | 132 |  | 10,083

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 282 mmBOE as of December 31, 2014 (536 and 648 mmBOE as of December 31, 2013 and 2012, respectively). Said volumes are not included in reserves volumes shown in the table herein.

| Subsidiaries |  | Equity-accounted entities

| 2012 |  | 2013 |  | 2014 |  | 2012 |  | 2013 |  | 2014

| (mmBOE)

Additions to proved reserves |  | 549 |  |  | 621 |  |  | 643 |  |  | 404 |  |  |  |  |  | 11 |
Purchases of minerals-in-place |  |  |  |  | 4 |  |  | 4 |  |  |  |  |  |  |  |  |  |
Sales of minerals-in-place |  | (212 | ) |  | (13 | ) |  | (8 | ) |  | (38 | ) |  | (652 | ) |  |  |
Production for the year (a) |  | (610 | ) |  | (571 | ) |  | (575 | ) |  | (13 | ) |  | (20 | ) |  | (8 | )

(a) |  | The difference over production sold of 549.5 mmBOE (598.7 mmBOE in 2012 and 555.3 mmBOE in 2013) reflected natural gas volumes of 29.4 mmBOE consumed in operations (25.5 mmBOE in 2012 and 30 mmBOE in 2013), changes in inventories and other factors.

| Subsidiaries and equity-accounted entities

| 2012 |  | 2013 |  | 2014

| (%)

Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources |  | 113 |  | (7) |  | 112

Eni’s proved reserves as of December 31, 2014 totaled 6,602 mmBOE (liquids 3,226 mmBBL; natural gas 18,545 BCF). Eni’s proved reserves reported an increase of 67 mmBOE, or 1%, from December 31, 2013. All sources

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additions to proved reserves booked in 2014 were 654 mmBOE of which 643 mmBOE came from Eni’s subsidiaries and 11 mmBOE from Eni’s share of equity-accounted entities.

Price effects were negligible, leading to an upward revision of 33 mmBOE, due to a lowered Brent price used in the reserve estimation process down to 101 $/BBL in 2014 compared to 108 $/BBL in 2013. 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 – Risks associated with the exploration and production of oil and natural gas”.

The methods (or technologies) used in the Eni’s proved reserves assessment in 2014 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modeling, 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 112% in 2014 (negative in 2013 and 113% in 2012). 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 "Item 18 – Supplemental oil and gas information – of the Notes on 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 reserves 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, as well as changes in oil and gas prices, political risks, geological, reservoir performance and environmental risks. See "Item 3 – Risks associated with the exploration and production of oil and natural gas and Uncertainties in estimates of oil and natural gas reserves".

The average reserves life index of Eni’s proved reserves was 11.3 years as of December 31, 2014 which included reserves of both subsidiaries and equity-accounted entities.

> Eni’s subsidiaries

Eni’s subsidiaries added 643 mmBOE of proved oil and gas reserves in 2014. This comprised 302 mmBBL of liquids and 1,872 BCF of natural gas. Additions to proved reserves derived from: (i) revisions of previous estimates were 513 mmBOE mainly reported in Libya, Italy, Kazakhstan and Congo due to contractual revisions, continuous development activities and field performances; (ii) extensions and discoveries were 124 mmBOE, with major increases booked in Ghana, Indonesia, the United States and Congo, following new project sanctions and proved area extensions; (iii) improved recovery were 6 mmBOE mainly reported in Algeria and Kazakhstan; (iv) sales of mineral-in-place related to the divestment of assets in Nigeria (7 mmBOE) and the United Kingdom (1 mmBOE); and (v) purchase of mineral-in-place referred to interests in assets located in the United Kingdom (4 mmBOE).

> Eni’s share of equity-accounted entities

Additions in Eni’s share of equity-accounted entities’ proved oil and gas reserves amounted to 11 mmBOE in 2014 and derived from revisions of previous estimates reported mainly in Angola and Venezuela.

> Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2014 totaled 3,169 mmBOE. At year end, proved undeveloped reserves of liquids amounted to 1,333 mmBBL, mainly concentrated in Africa and Kazakhstan. Proved undeveloped reserves of natural gas amounted to 10,083 BCF, mainly located in Africa and Venezuela. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,230 mmBBL of liquids and 6,466 BCF of natural gas.

In 2014, total proved undeveloped reserves increased by 61 mmBOE mainly due to: (i) discoveries and extensions (up by 109 mmBOE) in particular in Ghana and Indonesia associated to new project sanctions and proved area

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extensions; (ii) revisions of previous estimates (up by 173 mmBOE) mainly reported in Libya, Nigeria, Angola, Italy and Norway due to contractual revisions, development activities and field performances; (iii) divestments (down by 4 mmBOE) in Nigeria; and (iv) reclassification to proved developed reserves (down by 217 mmBOE).

During 2014, Eni converted 217 mmBOE of proved undeveloped reserves to proved developed reserves due to the progress of development activities and production start-ups. The main reclassifications to proved developed reserves related to the following fields/projects: Hadrian South and Nikaitchuq (United States), A-LNG and Sangos (Angola) and Karachaganak (Kazakhstan).

In 2014, capital expenditure amounted to approximately euro 2.3 billion and was made to progress the development of proved undeveloped reserves.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 1 BBOE of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (approximately 0.5 BBOE), which will be progressively reclassified to proved developed as a result of hooking-up new producing wells which are currently being drilled and plant capacity expansion as part of the completion of the sanctioned Phase 1 of the global development plan of the Kashagan field (the so-called Experimental Program); (ii) certain Libyan gas fields (0.4 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields which are expected to be put in production over the next several years; and (iii) the Goliat project in Norway and other minor projects where development activities are progressing. See also our discussion under the "Risk factors" section about risks associated with oil and gas development projects on page 6.

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 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 331 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria and Norway.

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 will account for approximately 77% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2014.

> Oil and gas production, production prices and production costs

The matters regarding future production, additions to reserves and related production costs and estimated reserves discussed below and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni’s important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni’s production operations.

In 2014, oil and natural gas production available for sale averaged 1,517 KBOE/d (1,537 KBOE/d in 2013) declined by 1.3% from 2013. On a homogeneous basis i.e. excluding the impact of the divestment of Eni’s interest in Siberian assets (29 KBOE/d, or 11 mmBOE in 2013), hydrocarbon production for the full year 2014 was up by 0.6%.

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The main production increases were reported in the United Kingdom, Algeria, the United States and Angola. These additions more than offset mature fields’ declines. New fields’ start-ups and production ramp-ups at fields started up in 2013 contributed 126 KBOE/d of production.

Liquids production (828 KBBL/d) was barely unchanged from 2013 (down by 0.6%) with major increases reported in: (i) the United Kingdom due to the ramp-up of the Jasmine field (Eni’s interest 33%); (ii) Algeria with the ramp-up of the El Merk field (Eni’s interest 12.25%); (iii) the United States due to ramp-ups following development activities and optimization of operated projects of Nikaitchuq (Eni 100%), Pegasus (Eni 58%) and Appaloosa (Eni 100%); and (iv) Angola with the start-up of the West Hub project (Eni operator with a 35% interest). These increases were offset by mature field decline and other factors, including unplanned facility downtime in the United Kingdom, Norway and the United States.

Natural gas production (3,782 mmCF/d) reported a slight increase from 2013, excluding the impact of the divestment of Eni’s interest in Siberian assets (up by 1.3%). Mature fields’ declines were more than offset by the contribution of new fields’ start-ups and ramp-ups.

Oil and gas production sold amounted to 549.5 mmBOE. The 4.3 mmBOE difference over production on an available-for-sale basis (553.8 mmBOE) reflected mainly changes in inventories and other factors. Approximately 62% of liquids production sold (299.8 mmBBL) was destined to Eni’s Refining & Marketing segment (of which 23% was processed in Eni’s refineries). About 27% of natural gas production sold (1,371 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 averaged), by final product marketed of liquids and natural gas by geographical area of each of the last three fiscal years.

2012 Production available for sale (a) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

Hydrocarbons production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (KBOE/d) |  | 184 |  | 171 |  | 556 |  | 326 |  | 98 |  | 106 |  | 122 |  | 35 |  | 1,598
|  | (mmBOE) |  | 67 |  | 63 |  | 203 |  | 119 |  | 36 |  | 39 |  | 45 |  | 13 |  | 585
Eni share of equity-accounted entities |  | (KBOE/d) |  |  |  |  |  | 5 |  | 2 |  |  |  | 15 |  | 11 |  |  |  | 33
|  | (mmBOE) |  |  |  |  |  | 2 |  | 1 |  |  |  | 5 |  | 4 |  |  |  | 12
Liquids production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (KBBL/d) |  | 63 |  | 95 |  | 267 |  | 245 |  | 61 |  | 41 |  | 72 |  | 18 |  | 862
|  | (mmBBL) |  | 23 |  | 35 |  | 98 |  | 90 |  | 22 |  | 15 |  | 26 |  | 7 |  | 316
Eni share of equity-accounted entities |  | (KBBL/d) |  |  |  |  |  | 4 |  | 2 |  |  |  | 3 |  | 11 |  |  |  | 20
|  | (mmBBL) |  |  |  |  |  | 1 |  | 1 |  |  |  | 1 |  | 4 |  |  |  | 7
Natural gas production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (mmCF/d) |  | 667 |  | 421 |  | 1,589 |  | 444 |  | 202 |  | 355 |  | 273 |  | 96 |  | 4,047
|  | (BCF) |  | 244 |  | 154 |  | 582 |  | 162 |  | 74 |  | 130 |  | 100 |  | 35 |  | 1,481
Eni share of equity-accounted entities |  | (mmCF/d) |  |  |  |  |  | 3 |  |  |  |  |  | 68 |  |  |  |  |  | 71
|  | (BCF) |  |  |  |  |  | 1 |  |  |  |  |  | 25 |  |  |  |  |  | 26

(a) |  | It excludes production volumes of natural gas consumed in operations. Said volumes were 383 mmCF/d, or 25.5 mmBOE.

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2013 Production available for sale (a) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

Hydrocarbons production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (KBOE/d) |  | 179 |  | 149 |  | 523 |  | 305 |  | 96 |  | 101 |  | 104 |  | 29 |  | 1,486
|  | (mmBOE) |  | 65 |  | 54 |  | 191 |  | 111 |  | 35 |  | 36 |  | 38 |  | 11 |  | 541
Eni share of equity-accounted entities |  | (KBOE/d) |  |  |  |  |  | 5 |  | 2 |  |  |  | 34 |  | 10 |  |  |  | 51
|  | (mmBOE) |  |  |  |  |  | 2 |  | 1 |  |  |  | 13 |  | 4 |  |  |  | 20
Liquids production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (KBBL/d) |  | 71 |  | 77 |  | 248 |  | 242 |  | 61 |  | 43 |  | 61 |  | 10 |  | 813
|  | (mmBBL) |  | 26 |  | 28 |  | 91 |  | 88 |  | 22 |  | 16 |  | 22 |  | 4 |  | 297
Eni share of equity-accounted entities |  | (KBBL/d) |  |  |  |  |  | 4 |  |  |  |  |  | 6 |  | 10 |  |  |  | 20
|  | (mmBBL) |  |  |  |  |  | 1 |  |  |  |  |  | 2 |  | 4 |  |  |  | 7
Natural gas production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (mmCF/d) |  | 593 |  | 395 |  | 1,510 |  | 349 |  | 195 |  | 322 |  | 234 |  | 105 |  | 3,703
|  | (BCF) |  | 217 |  | 144 |  | 551 |  | 127 |  | 71 |  | 118 |  | 85 |  | 38 |  | 1,351
Eni share of equity-accounted entities |  | (mmCF/d) |  |  |  |  |  | 4 |  | 7 |  |  |  | 154 |  |  |  |  |  | 165
|  | (BCF) |  |  |  |  |  | 2 |  | 3 |  |  |  | 56 |  |  |  |  |  | 61

(a) |  | It excludes production volumes of natural gas consumed in operations. Said volumes were 451 mmCF/d, or 30 mmBOE.

2014 Production available for sale (a) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

Hydrocarbons production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (KBOE/d) |  | 171 |  | 184 |  | 528 |  | 305 |  | 85 |  | 87 |  | 112 |  | 25 |  | 1,497
|  | (mmBOE) |  | 63 |  | 67 |  | 193 |  | 111 |  | 31 |  | 31 |  | 41 |  | 9 |  | 546
Eni share of equity-accounted entities |  | (KBOE/d) |  |  |  |  |  | 4 |  | 2 |  |  |  | 4 |  | 10 |  |  |  | 20
|  | (mmBOE) |  |  |  |  |  | 1 |  | 1 |  |  |  | 2 |  | 4 |  |  |  | 8
Liquids production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (KBBL/d) |  | 73 |  | 93 |  | 249 |  | 230 |  | 52 |  | 36 |  | 74 |  | 6 |  | 813
|  | (mmBBL) |  | 27 |  | 34 |  | 91 |  | 84 |  | 19 |  | 13 |  | 27 |  | 2 |  | 297
Eni share of equity-accounted entities |  | (KBBL/d) |  |  |  |  |  | 4 |  |  |  |  |  | 1 |  | 10 |  |  |  | 15
|  | (mmBBL) |  |  |  |  |  | 1 |  |  |  |  |  |  |  | 4 |  |  |  | 5
Natural gas production |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni consolidated subsidiaries |  | (mmCF/d) |  | 541 |  | 498 |  | 1,533 |  | 411 |  | 181 |  | 279 |  | 205 |  | 106 |  | 3,754
|  | (BCF) |  | 198 |  | 182 |  | 559 |  | 150 |  | 66 |  | 102 |  | 75 |  | 39 |  | 1,371
Eni share of equity-accounted entities |  | (mmCF/d) |  |  |  |  |  | 3 |  | 7 |  |  |  | 18 |  |  |  |  |  | 28
|  | (BCF) |  |  |  |  |  | 1 |  | 3 |  |  |  | 6 |  |  |  |  |  | 10

(a) |  | It excludes production volumes of natural gas consumed in operations. Said volumes were 442 mmCF/d, or 29.4 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 78 KBOE/d, 67 KBOE/d and 78 KBOE/d in 2014, 2013 and 2012, 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, as well as 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.

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AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and condensates, per BBL |  | 100.52 |  | 100.67 |  | 103.63 |  | 108.34 |  | 102.25 |  | 103.44 |  | 85.94 |  | 102.06 |  | 103.06
Natural gas, per KCF |  | 10.68 |  | 10.13 |  | 8.13 |  | 2.16 |  | 0.67 |  | 5.94 |  | 2.90 |  | 7.73 |  | 7.14
Average production cost, per BOE |  | 11.60 |  | 13.43 |  | 6.28 |  | 18.65 |  | 6.73 |  | 8.37 |  | 10.46 |  | 13.23 |  | 10.82
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and condensates, per BBL |  |  |  | 93.11 |  | 17.93 |  | 112.28 |  |  |  | 40.36 |  | 93.45 |  |  |  | 77.94
Natural gas, per KCF |  |  |  | 11.64 |  | 4.91 |  |  |  |  |  | 6.17 |  |  |  |  |  | 6.16
Average production cost, per BOE |  |  |  | 30.10 |  | 10.35 |  | 10.60 |  |  |  | 4.37 |  | 46.01 |  |  |  | 20.21
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and condensates, per BBL |  | 98.50 |  | 98.97 |  | 100.42 |  | 105.13 |  | 99.37 |  | 99.69 |  | 85.27 |  | 98.72 |  | 100.20
Natural gas, per KCF |  | 11.65 |  | 10.62 |  | 7.96 |  | 2.16 |  | 0.64 |  | 5.83 |  | 3.37 |  | 7.80 |  | 7.41
Average production cost, per BOE |  | 14.58 |  | 17.49 |  | 6.72 |  | 19.60 |  | 7.23 |  | 9.32 |  | 12.08 |  | 18.17 |  | 12.19
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and condensates, per BBL |  |  |  |  |  | 17.96 |  |  |  |  |  | 33.87 |  | 93.32 |  |  |  | 64.92
Natural gas, per KCF |  |  |  |  |  | 6.29 |  |  |  |  |  | 3.49 |  |  |  |  |  | 4.00
Average production cost, per BOE |  |  |  |  |  | 11.87 |  |  |  |  |  | 3.48 |  | 50.57 |  |  |  | 16.68
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and condensates, per BBL |  | 87.80 |  | 88.80 |  | 88.99 |  | 93.45 |  | 91.86 |  | 77.99 |  | 79.13 |  | 91.61 |  | 88.90
Natural gas, per KCF |  | 8.74 |  | 8.49 |  | 8.08 |  | 2.12 |  | 0.62 |  | 6.18 |  | 3.96 |  | 7.46 |  | 6.83
Average production cost, per BOE |  | 15.19 |  | 13.61 |  | 6.79 |  | 18.88 |  | 8.94 |  | 10.70 |  | 11.75 |  | 20.14 |  | 12.00
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and condensates, per BBL |  |  |  |  |  | 17.94 |  |  |  |  |  | 65.90 |  | 81.48 |  |  |  | 70.56
Natural gas, per KCF |  |  |  |  |  | 6.08 |  |  |  |  |  | 15.64 |  |  |  |  |  | 14.13
Average production cost, per BOE |  |  |  |  |  | 12.50 |  |  |  |  |  | 9.79 |  | 42.27 |  |  |  | 26.18

> Development activities

In 2014, a total of 440 development wells were drilled (191 of which represented Eni’s share) as compared to 463 development wells drilled in 2013 (187.2 of which represented Eni’s share) and 351 development wells drilled in 2012 (163.6 of which represented Eni’s share). The drilling of 142 wells (46.5 of which represented Eni’s share) is currently underway.

The table below summarizes the number of the Company’s net interests 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, 2014. 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 Dec. 31,

|  | 2012 |  | 2013 |  | 2014 |  | 2014

(units) |  | Productive |  | Dry |  | Productive |  | Dry |  | Productive |  | Dry |  | Gross |  | Net

Italy |  | 18.0 |  | 1.0 |  | 7.4 |  | 1.0 |  | 12.5 |  |  |  | 5.0 |  | 4.6
Rest of Europe |  | 2.9 |  | 0.6 |  | 6.3 |  |  |  | 9.8 |  | 1.0 |  | 36.0 |  | 7.9
North Africa |  | 46.0 |  | 1.6 |  | 61.6 |  | 3.3 |  | 54.5 |  | 1.0 |  | 15.0 |  | 7.4
Sub-Saharan Africa |  | 27.4 |  | 0.3 |  | 26.3 |  | 1.2 |  | 31.6 |  |  |  | 23.0 |  | 7.5
Kazakhstan |  | 1.4 |  |  |  | 0.3 |  |  |  | 1.5 |  |  |  | 22.0 |  | 3.9
Rest of Asia |  | 41.2 |  | 0.1 |  | 61.7 |  | 4.3 |  | 54.2 |  | 1.6 |  | 19.0 |  | 8.2
Americas |  | 23.1 |  |  |  | 13.8 |  |  |  | 22.1 |  | 0.7 |  | 20.0 |  | 6.5
Australia and Oceania |  |  |  |  |  |  |  |  |  | 0.1 |  | 0.4 |  | 2.0 |  | 0.5
Total including equity-accounted entities |  | 160.0 |  | 3.6 |  | 177.4 |  | 9.8 |  | 186.3 |  | 4.7 |  | 142.0 |  | 46.5

> Exploration activities

In 2014, a total of 44 new exploratory wells were drilled (25.8 of which represented Eni’s share), as compared to 53 exploratory wells drilled in 2013 (27.8 of which represented Eni’s share) and 60 exploratory wells drilled in 2012 (34.1 of which represented Eni’s share).

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The overall commercial success rate was 31.3% (38.0% net to Eni) as compared to 36.9% (38.5% net to Eni) and 40% (40.8% net to Eni) in 2013 and 2012, 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, 2014. 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)

|  | 2012 |  | 2013 |  | 2014 |  | 2014

(units) |  | Productive |  | Dry |  | Productive |  | Dry |  | Productive |  | Dry |  | Gross |  | Net

Italy |  | 1.0 |  |  |  |  |  |  |  |  |  | 0.6 |  | 4.0 |  | 2.8
Rest of Europe |  | 1.0 |  | 1.0 |  |  |  | 3.4 |  |  |  | 4.3 |  | 12.0 |  | 3.3
North Africa |  | 6.3 |  | 11.3 |  | 4.9 |  | 5.4 |  | 3.5 |  | 4.3 |  | 13.0 |  | 10.3
Sub-Saharan Africa |  | 4.5 |  | 5.1 |  | 3.2 |  | 6.6 |  | 7.3 |  | 7.3 |  | 49.0 |  | 16.9
Kazakhstan |  |  |  | 0.8 |  |  |  | 0.4 |  |  |  |  |  | 6.0 |  | 1.1
Rest of Asia |  | 0.5 |  | 0.6 |  | 4.3 |  | 2.7 |  | 1.3 |  | 4.3 |  | 12.0 |  | 5.0
Americas |  |  |  | 0.1 |  | 0.2 |  | 1.2 |  | 2.0 |  | 1.4 |  | 4.0 |  | 2.5
Australia and Oceania |  |  |  | 0.4 |  |  |  | 0.5 |  |  |  | 0.9 |  | 1.0 |  | 0.3
Total including equity-accounted entities |  | 13.3 |  | 19.3 |  | 12.6 |  | 20.2 |  | 14.1 |  | 23.1 |  | 101.0 |  | 42.2

(1) |  | Includes temporary suspended wells pending further evaluation.

> Oil and gas properties, operations and acreage

In 2014, Eni performed its operations in 40 countries located in five continents. As of December 31, 2014, Eni’s mineral right portfolio consisted of 938 exclusive or shared rights of exploration and development activities for a total acreage of 334,739 square kilometers net to Eni of which developed acreage of 40,771 square kilometers and undeveloped acreage of 293,968 square kilometers net to Eni. In 2014, changes in total net acreage mainly derived from: (i) new leases mainly in South Africa, Indonesia, Vietnam, Myanmar, Portugal, China, Egypt, Greenland, Australia and Kenya for a total acreage of approximately 76,000 square kilometers; (ii) interest increase in Indonesia and Ireland for a total acreage of approximately 2,100 square kilometers; (iii) the total relinquishment of licenses mainly in Togo, Pakistan, Australia, Poland, Democratic Republic of Congo, covering an acreage of approximately 12,000 square kilometers; and (iv) partial relinquishment or interest reduction in Indonesia, Norway, Congo and Angola for approximately 6,000 square kilometers.

In addition, Eni has been granted three prospection permits in Algeria for a net acreage of approximately 23,000 square kilometers.

The table below provides certain information about the Company’s oil and 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, 2014. A gross acreage is one in which Eni owns a working interest.

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| December 31, 2013 |  | December 31, 2014

|  | 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 |  | 37,938 |  | 265 |  | 15,883 |  | 53,444 |  | 69,327 |  | 10,948 |  | 33,894 |  | 44,842
Italy |  | 17,282 |  | 151 |  | 10,712 |  | 10,751 |  | 21,463 |  | 8,989 |  | 8,308 |  | 17,297
Rest of Europe |  | 20,656 |  | 114 |  | 5,171 |  | 42,693 |  | 47,864 |  | 1,959 |  | 25,586 |  | 27,545
Croatia |  | 987 |  | 2 |  | 1,975 |  |  |  | 1,975 |  | 987 |  |  |  | 987
Cyprus |  | 10,018 |  | 3 |  |  |  | 12,523 |  | 12,523 |  |  |  | 10,018 |  | 10,018
Greenland |  | 920 |  | 2 |  |  |  | 4,890 |  | 4,890 |  |  |  | 1,909 |  | 1,909
Norway |  | 3,779 |  | 56 |  | 2,255 |  | 9,149 |  | 11,404 |  | 345 |  | 3,327 |  | 3,672
Poland |  | 969 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Portugal |  |  |  | 3 |  |  |  | 9,099 |  | 9,099 |  |  |  | 6,370 |  | 6,370
United Kingdom |  | 638 |  | 35 |  | 941 |  | 343 |  | 1,284 |  | 627 |  | 117 |  | 744
Other countries |  | 3,345 |  | 13 |  |  |  | 6,689 |  | 6,689 |  |  |  | 3,845 |  | 3,845
AFRICA |  | 137,096 |  | 282 |  | 66,114 |  | 263,572 |  | 329,686 |  | 20,032 |  | 139,309 |  | 159,341
North Africa |  | 20,412 |  | 117 |  | 32,559 |  | 15,675 |  | 48,234 |  | 14,144 |  | 7,549 |  | 21,693
Algeria |  | 1,179 |  | 42 |  | 3,222 |  | 187 |  | 3,409 |  | 1,148 |  | 31 |  | 1,179
Egypt |  | 3,665 |  | 54 |  | 4,926 |  | 6,800 |  | 11,726 |  | 1,772 |  | 3,174 |  | 4,946
Libya |  | 13,294 |  | 10 |  | 17,947 |  | 8,688 |  | 26,635 |  | 8,950 |  | 4,344 |  | 13,294
Tunisia |  | 2,274 |  | 11 |  | 6,464 |  |  |  | 6,464 |  | 2,274 |  |  |  | 2,274
Sub-Saharan Africa |  | 116,684 |  | 165 |  | 33,555 |  | 247,897 |  | 281,452 |  | 5,888 |  | 131,760 |  | 137,648
Angola |  | 4,443 |  | 72 |  | 6,555 |  | 14,605 |  | 21,160 |  | 813 |  | 3,514 |  | 4,327
Congo |  | 3,125 |  | 28 |  | 1,714 |  | 2,649 |  | 4,363 |  | 921 |  | 1,962 |  | 2,883
Democratic Republic of Congo |  | 263 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gabon |  | 7,615 |  | 6 |  |  |  | 7,615 |  | 7,615 |  |  |  | 7,615 |  | 7,615
Ghana |  | 1,664 |  | 3 |  |  |  | 4,676 |  | 4,676 |  |  |  | 1,664 |  | 1,664
Kenya |  | 38,930 |  | 7 |  |  |  | 61,363 |  | 61,363 |  |  |  | 40,426 |  | 40,426
Liberia |  | 1,841 |  | 3 |  |  |  | 7,365 |  | 7,365 |  |  |  | 1,841 |  | 1,841
Mozambique |  | 5,103 |  | 1 |  |  |  | 10,207 |  | 10,207 |  |  |  | 5,103 |  | 5,103
Nigeria |  | 7,646 |  | 40 |  | 25,286 |  | 10,837 |  | 36,123 |  | 4,154 |  | 3,484 |  | 7,638
South Africa |  |  |  | 1 |  |  |  | 82,117 |  | 82,117 |  |  |  | 32,847 |  | 32,847
Togo |  | 6,192 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other countries |  | 39,862 |  | 4 |  |  |  | 46,463 |  | 46,463 |  |  |  | 33,304 |  | 33,304
ASIA |  | 79,314 |  | 71 |  | 17,556 |  | 199,150 |  | 216,706 |  | 5,809 |  | 103,428 |  | 109,237
Kazakhstan |  | 869 |  | 6 |  | 2,391 |  | 2,542 |  | 4,933 |  | 442 |  | 427 |  | 869
Rest of Asia |  | 78,445 |  | 65 |  | 15,165 |  | 196,608 |  | 211,773 |  | 5,367 |  | 103,001 |  | 108,368
China |  | 5,149 |  | 8 |  | 77 |  | 7,056 |  | 7,133 |  | 19 |  | 7,056 |  | 7,075
India |  | 6,167 |  | 11 |  | 206 |  | 16,546 |  | 16,752 |  | 109 |  | 6,058 |  | 6,167
Indonesia |  | 19,209 |  | 14 |  | 3,218 |  | 31,608 |  | 34,826 |  | 1,217 |  | 25,031 |  | 26,248
Iran |  | 820 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Iraq |  | 446 |  | 1 |  | 1,074 |  |  |  | 1,074 |  | 446 |  |  |  | 446
Myanmar |  |  |  | 2 |  |  |  | 7,850 |  | 7,850 |  |  |  | 7,065 |  | 7,065
Pakistan |  | 10,335 |  | 17 |  | 10,390 |  | 15,249 |  | 25,639 |  | 3,396 |  | 6,071 |  | 9,467
Russia |  | 20,862 |  | 3 |  |  |  | 62,592 |  | 62,592 |  |  |  | 20,862 |  | 20,862
Timor Leste |  | 1,230 |  | 1 |  |  |  | 1,538 |  | 1,538 |  |  |  | 1,230 |  | 1,230
Turkmenistan |  | 200 |  | 1 |  | 200 |  |  |  | 200 |  | 180 |  |  |  | 180
Vietnam |  | 10,783 |  | 6 |  |  |  | 39,569 |  | 39,569 |  |  |  | 26,384 |  | 26,384
Other countries |  | 3,244 |  | 1 |  |  |  | 14,600 |  | 14,600 |  |  |  | 3,244 |  | 3,244
AMERICAS |  | 8,286 |  | 306 |  | 5,064 |  | 11,746 |  | 16,810 |  | 3,273 |  | 4,670 |  | 7,943
Ecuador |  | 1,985 |  | 1 |  | 1,985 |  |  |  | 1,985 |  | 1,985 |  |  |  | 1,985
Trinidad & Tobago |  | 66 |  | 1 |  | 382 |  |  |  | 382 |  | 66 |  |  |  | 66
United States |  | 3,843 |  | 290 |  | 1,895 |  | 4,197 |  | 6,092 |  | 954 |  | 2,546 |  | 3,500
Venezuela |  | 1,066 |  | 6 |  | 802 |  | 2,002 |  | 2,804 |  | 268 |  | 798 |  | 1,066
Other countries |  | 1,326 |  | 8 |  |  |  | 5,547 |  | 5,547 |  |  |  | 1,326 |  | 1,326
AUSTRALIA AND OCEANIA |  | 13,622 |  | 14 |  | 1,140 |  | 21,679 |  | 22,819 |  | 709 |  | 12,667 |  | 13,376
Australia |  | 13,622 |  | 14 |  | 1,140 |  | 21,679 |  | 22,819 |  | 709 |  | 12,667 |  | 13,376
Total |  | 276,256 |  | 938 |  | 105,757 |  | 549,591 |  | 655,348 |  | 40,771 |  | 293,968 |  | 334,739

(a) |  | Square kilometers.
(b) |  | Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.

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, 2014. 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 bore hole are counted as one well. Productive wells are producing wells and

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wells capable of production. The total number of oil and natural gas productive wells is 8,777 (3,518.1 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, 2014 (a)

|  | Oil wells |  | Natural gas wells

(units) |  | Gross |  | Net |  | Gross |  | Net

Italy |  | 241.0 |  | 195.1 |  | 615.0 |  | 532.4
Rest of Europe |  | 354.0 |  | 60.6 |  | 188.0 |  | 102.9
North Africa |  | 1,710.0 |  | 907.0 |  | 210.0 |  | 89.0
Sub-Saharan Africa |  | 2,950.0 |  | 589.8 |  | 341.0 |  | 25.7
Kazakhstan |  | 149.0 |  | 41.1 |  |  |  |
Rest of Asia |  | 475.0 |  | 363.0 |  | 956.0 |  | 364.9
Americas |  | 201.0 |  | 112.0 |  | 366.0 |  | 127.5
Australia and Oceania |  | 7.0 |  | 3.8 |  | 14.0 |  | 3.3
Total including equity-accounted entities |  | 6,087.0 |  | 2,272.4 |  | 2,690.0 |  | 1,245.7

(a) |  | Multiple completion wells included above: approximately 2,234 (799.1 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 2014, Eni’s oil and gas production amounted to 171 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic and Ionian Sea, 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 (54 operated onshore and 64 operated offshore) and exploration licenses (12 onshore and 9 offshore).

The Adriatic and Ionian Seas represent Eni’s main production area, accounting for 46% of Eni’s domestic production in 2014. Main operated fields are Barbara, Annamaria, Angela-Angelina, Porto Garibaldi, Cervia, Bonaccia, Luna and Hera Lacinia.

Eni is the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region in Southern Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano oil center. In 2014, the Val d’Agri concession produced 40% of Eni’s production in Italy.

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Eni operates 12 production concessions onshore and 3 offshore Sicily. The main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2014 accounted for approximately 11% of Eni’s production in Italy.

Development activities concerned: (i) the construction of a new gas treatment unit to improve the environmental performance of the treatment centre at the Val d’Agri concession; and (ii) the completion of development activities to achieve the start-up of the Fauzia and Elettra fields located in the Adriatic Sea.

In the medium term, management expects to achieve stable production level driven by continuing ramp-up at the Val d’Agri fields, new field projects and production optimization activities offsetting mature field declines.

> Rest of Europe

Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the United Kingdom. In 2014, 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 2014, Eni’s production of natural gas averaged 36 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula.

Exploration and production activities in Croatia are regulated by PSAs.

During 2014, production start-up of a new offshore Ika JZ field was achieved.

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

Norway. Eni has been operating in Norway since 1965. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 109 KBOE/d in 2014.

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

Eni currently holds interests in 10 production areas in the Norwegian Sea. The principal producing fields are Åsgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.17%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2014 accounted for 74% 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 2014 produced approximately 24 KBOE/d net to Eni and accounted for 21% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.

Eni is currently performing exploration and development activities in the Barents Sea. 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). The license expires in 2042. Start-up is expected in the second half of 2015, with a production plateau at approximately 65 KBOE/d net to Eni in 2016.

Development activities progressed to: (i) maintain and optimize production at the Ekofisk field by installing a new platform, drilling of infilling wells, upgrading of existing facilities and water injection optimization; and (ii) optimize production activities at the Midgard (Eni’s interest 14.9%) and Mikkel fields.

In January 2015, Eni was awarded: (i) the operatorship and a 40% interest in the PL 806 license located in the Barents Sea; and (ii) a 13.12% interest in the PL 044C license located in the North Sea.

Exploration activities yielded positive results with the oil and gas Drivis discovery made at the offshore license PL 532 (Eni 30%). The discovery will be put into production with the recent oil and gas discoveries of Skrugard, Havis and Skavl by means of the development of the integrated Johan Castberg Hub.

United Kingdom. Eni has been present in the United Kingdom since 1964. Eni’s activities are carried out in the British section of the North Sea, the Irish Sea and Atlantic Ocean. In 2014, Eni’s net production of oil and gas averaged 68 KBOE/d. Exploration and production activities in the United Kingdom are regulated by concession contracts.

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During the year Eni was awarded the operatorship of the 22/19c (Eni’s interest 50%), 22/19e (Eni’s interest 57.14%) and 30/1b (Eni’s interest 100%) exploration blocks in the North Sea. In April 2014, Eni completed the acquisition of the Liverpool Bay assets (Eni’s interest 100%). 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%), Jade (Eni’s interest 7%) and MacCulloch (Eni’s interest 40%), which in 2014 accounted for 66% of Eni’s production in the United Kingdom. Development activities mainly concerned: (i) production start-up of the West Franklin field (Eni’s interest 21.87%) with the completion of the Phase 2 development program by means of the installation of production platform and pipeline connection to the treatment facility in the area; and (ii) production ramp-up of the Jasmine project with the completion of commissioning and start-up of 4 additional production wells. Exploration activities yielded positive results with the Romeo North discovery, already linked to the production platform of the Jade field. |  |

> North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2014, North Africa accounted for 35% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2014, Eni’s oil and gas production averaged 93 KBOE/d.

|  | Operated and participated 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) blocks 403 (Eni’s interest 50%); (v) block 405b (Eni’s interest 75%); and (vi) block 212 (Eni’s interest 22.38%) with discoveries already made. In addition Eni holds interest in the non-operated block 404 and block 208 with a 12.25% stake. Exploration and production activities in Algeria are regulated by 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 20% of Eni’s production in Algeria in 2014. Production in blocks 401a/402a comes mainly from the ROD/SFNE and satellite fields and accounted for approximately 14% of Eni’s production in Algeria in 2014. The main fields in block 403 are BRN, BRW and BRSW which accounted for approximately 11% of Eni’s production in Algeria in 2014.

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The main fields in block 404 are HBN and HBNS and satellites which accounted for approximately 25% of Eni’s production in Algeria in 2014. Production in block 405b comes mainly from MLE-CAFC project and accounted for approximately 15% of Eni’s production in the Country in 2014. Development and optimization activities progressed at the MLE-CAFC project. Activities include an additional oil phase with start-up expected in 2017, targeting a production plateau of approximately 33 KBOE/d net to Eni. The El-Merk field is the main production project in the block 208 and accounted for approximately 15% of Eni’s production in Algeria in 2014. Production ramp-up was completed in the year with a production plateau target of approximately 18 KBOE/d net to Eni. Eni was granted three prospection permits in the Timimoun and Oued Mya areas, in Southern onshore Algeria. The agreements expire in two years and cover a total acreage of 46,837 square kilometers. The program includes studies and drilling of prospection wells to assess the mineral potential. Egypt. Eni has been present in Egypt since 1954. In 2014, Eni’s share of production in this Country amounted to 195 KBOE/d and accounted for 13% 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 Meleiha (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%) and Ras el Barr (Eni’s interest 50%, non operated), located offshore the Nile Delta. In 2014, production from these large concessions accounted for approximately 94% of Eni’s production in Egypt. |  |

Exploration and production activities in Egypt are regulated by PSAs.

In March 2015, Eni and the Egyptian Ministry of Petroleum and Mineral Resources signed a framework agreement to develop the oil and gas resources in the Country with an estimated investment of $5 billion at 100%. The investments, which will be utilized through the realization of projects to be implemented in the next 4 years, are directed to the development of 200 mm/BBL of oil and 1.3 TCF of gas.

In 2014, Eni was awarded: (i) the operatorship of the South-West Meleiha onshore exploration licenses (Eni’s interest 100%), nearby the Meleiha concession, and the Block 9 (Eni’s interest 100%) and Block 8 (Eni’s interest 50%) located in the deep offshore of the Mediterranean Sea. The closing was achieved in the early 2015 with the ratification of the relevant concession agreements; and (ii) the Shorouk concession (Eni’s interest 100%) in the deep offshore of the Mediterranean Sea.

In August 2014, the DEKA project (Eni operator with a 50% interest) started up with a production of approximately 64 mmCF/d of gas and 800 BBL/d of associated condensates. Produced gas is being processed at the onshore El Gamil plant. Peak production of approximately 230 mmCF/d net to Eni is expected by the first quarter of 2015.

Development activities concerned: (i) infilling activities at the Belayim, Ha’py (Eni’s interest 50%), El Temsah and Pourt Fouad (Eni’s interest 100%) fields to optimize the mineral potential recovery factor; and (ii) start-up of the END Phase 3 sub-sea project (Eni’s interest 50%).

Exploration activities yielded positive results with: (i) the oil discovery ARM-14 in the Abu Rudeis license (Eni’s interest 100%) in the Gulf of Suez. The discovery was linked to the nearby production facilities; and (ii) the oil discovery West Deep in the Meleiha concession (Eni’s interest 76%) that flowed at approximately 2 KBBL/d in test production.

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Libya. Eni started operations in Libya in 1959. The internal situation in Libya continues to represent an issue to Eni’s management. Following the internal conflict of 2011 and the fall of the regime, which forced the Company to shut down almost all its producing facilities including gas exports for a period of about 8 months, a period of social and political instability began which turned into disorders, strikes, protests and a resurgence of the internal conflict. These events jeopardized Eni’s ability to perform its industrial activity in safety, forcing the Company to interrupt its operations on certain occasions as precautionary measure. These events were fairly frequent in 2013 and sporadic in 2014. In 2014, Eni’s facilities in Libya produced on average 233 KBOE/d, registering a small increase compared to 2013. 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 oilfield (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 of four onshore blocks in the Kufra area (186/1, 2, 3 & 4) and 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 contracts (EPSA). The licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil and gas properties, respectively.

Looking forward, management is prudently assuming a production level in line with 2014.

Exploration activities yielded positive results with the B1-16/4 well in the Bahr Essalam South prospects in the offshore Area D that flowed at approximately 35 mmCF/d of natural gas and over 600 BBL/d of condensates in test production.

Tunisia. Eni has been present in Tunisia since 1961. In 2014, Eni’s production amounted to 12 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.

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In 2014, Sub-Saharan Africa accounted for 20% of Eni’s total worldwide production of oil and natural gas.

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Angola. Eni has been present in Angola since 1980. In 2014, Eni’s production averaged 76 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 35% interest) where the West Hub project started up in 2014 and other development projects are underway. 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; and (iv) 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 Lianzi Development Area (Block 14K/A IMI Unit Area - Eni’s interest 10%), Block 35/11 (Eni operator with a 30% interest) and in Block 3/05-A (Eni’s interest 12%), onshore Cabinda North (Eni’s interest 15%) and the Open Areas of Block 2 awarded to the Gas Project (Eni’s interest 20%). Exploration and production activities in Angola are regulated by concessions and PSAs. In November 2014, Eni signed with the national oil company Sonangol a strategic agreement on future co-operation activities. In particular, the agreement includes the studies to analyze the potential of the non-associated gas present in the Lower Congo Basin and offshore Angola. The project scope is to analyze the different options both internationally and in the domestic market, also in order to sustain the local economy. In addition, the companies will asses possible projects on the mid-downstream business to be carried out in Angola. |  |

In December 2014, first oil was achieved at the West Hub development project in Block 15/06 in the deep offshore. This first Eni-operated producing project in the Country is currently producing 45 KBOE/d through the N’Goma FPSO, with a production ramp-up expected to reach a plateau up to 100 KBOE/d in the coming months. The start-up was achieved in 44 months following the announcement of the commercial discovery. The N’Goma FPSO is currently producing from the Sangos discovery; future production will leverage the progressive hooking up of the Block’s discoveries.

The main development activities performed in the year concerned: (i) the Mafumeira Sul field (Eni’s interest 9.8%) with start-up expected in 2016; (ii) the Lianzi project in the Block 14K/A Imi Unit Area (Eni’s interest 10%), with start-up expected in the second half of 2015 and production plateau of 35 KBOE/d; and (iii) the Kizomba satellites Phase 2 project (Eni’s interest 20%). The project provides to put into production three additional discoveries that will be linked to the existing FPSO. Start-up is expected in 2015, with a production plateau of 70 KBOE /d in 2016.

Exploration activities yielded positive results with: (i) the Ochigufu 1 NFW discovery in the deep water of the Block 15/06. In January 2015, Eni obtained from the Angolan Authorities a three-year extension of the exploration period of the above mentioned block; and (ii) the appraisal of the Pinda FM discovery in the Block 0 (Eni’s interest 9.8%).

In the medium term, management expects to increase Eni’s production to approximately 150 KBOE/d reflecting additions from ongoing development projects.

Congo. Eni has been present in Congo since 1968. In 2014, production averaged 100 KBOE/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore.

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

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|  | Other relevant producing areas are a 35% interest in the Pointe-Noire Grand Fond, PEX and Likouala permits. Exploration and production activities in Congo are regulated by production sharing agreements. In July 2014, a cooperation agreement was signed with the relevant authorities and ratified by law to extend existing oil permits and to develop new initiatives in the Country’s coastal basin, which extends from onshore Mayombe to frontage deep waters. At the end of December 2014 was achieved the start-up of the recent Nené Marine discovery in block Marine XII just 8 months after obtaining the production permit. The early production phase is yielding 7,500 BOE/d and the fast-track development of the field has leveraged on the synergies with the front-end loading and the infrastructures of the fields located in the area. The full-field development will take place in several stages and will include the installation of production platforms and the drilling of approximately 30 wells, with a plateau of over 120 KBOE/d. Development of the Litchendjili sanctioned project progressed in the Marine XII Block. The project provides for the installation of a production platform, the construction of transport facilities and onshore treatment plant. Start-up is expected in the second half of 2015 with a peak production of 12 KBOE/d net to Eni. Exploration activities yielded positive results in the Marine XII offshore Block (Eni operator with a 65% interest) with: (i) the Nené Marine 3 appraisal well confirming the oil and gas mineral potential of the area; and (ii) the Minsala Marine oil discovery.

In the medium term, management expects to increase Eni’s production in Congo, with a level of approximately 120 KBOE/d in 2018.

Ghana. Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni’s interest 47.22%) and Offshore Keta Contract Area (Eni’s interest 35%) exploration permits.

In January 2015, Eni and the relevant authorities of the Country sanctioned the Offshore Cape Three Points integrated oil and gas project. First oil is expected in 2017, first gas in 2018 and production is expected to peak at 80 KBOE/d.

Mozambique. Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 Block (Eni operator with a 50% interest) located in the offshore Rovuma Basin. The exploration period expires in 2015, and a term of 30 years is awarded in respect of any approved Development and Production Area.

In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by another oil company. In 2012, Eni made the Coral discovery which falls entirely in Area 4.

Exploration activities for the year yielded positive results with the appraisal gas wells Agulha 2 and Coral 4 DIR, confirming the extension of their respective discoveries.

The Company is planning to develop as first target the Coral discovery and a portion of the Mamba straddling resources. As part of the Mamba plan, based on the enactment of a law decree which defines the fiscal and contractual regime applicable to onshore liquefaction projects, Eni expects to obtain the necessary authorizations to develop and produce up to 12 TCF from the straddling reservoir via an independent industrial plan which needs to be coordinated with the operator of Area 1.

An Unitization Agreement for the straddling resources of Mamba has to be agreed among concessionaries of the straddling reservoirs and submitted to the Mozambique Government within six months dating back to the enactment of the special law on onshore projects which occurred in December 2014.

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The Coral project scheme comprises construction of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG - FLNG) fed by subsea wells. The development plan was formally submitted to the local authorities at the end of 2014. The FID is expected in the second half of 2015. The award of the relevant EPCIC contracts for the construction, installation and commissioning of the floating unit is expected by the end of 2015. Production start-up is expected for the end of 2019.

The development plan of the first stage of the Mamba project contemplates construction and commissioning of two onshore LNG trains and the drilling of 16 subsea wells, with start-up in 2022. The scheduled activities comprise: (i) the submission of the Declaration of Commerciality to the Government by the third quarter of 2015; (ii) the filing of the development plan by the end of 2015; and (iii) the finalization of the commercial agreements and the project financing by the first quarter of 2016. The FID is expected in 2016-2017.

In October 2014, Eni signed with the South Korean company KOGAS a cooperation agreement for joint development opportunities in the upstream and LNG areas, in particular in the Area 4 in Mozambique.

Nigeria. Eni has been present in Nigeria since 1962. In 2014, Eni’s oil and gas production averaged 130 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 21 onshore blocks and in 5 conventional offshore blocks.

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

Exploration and production activities in Nigeria are regulated mainly by production sharing agreements and concession contracts, as well as service contracts, in two blocks, where Eni acts as contractor for state-owned company.

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In the year production start-up was achieved at the Bonga NW field in the OML 118 Block with the drilling and completion of 4 production and 2 injection wells.

Development activities progressed at the OML 28 Block (Eni’s interest 5%) with: (i) the drilling campaign within the integrated oil and natural gas project in the Gbaran-Ubie area. The development plan provides for the supply of natural gas to the Bonny liquefaction plant by means of the construction of a Central Processing Facility (CPF) with a treatment capacity of approximately 1 BCF/d of gas and 120 KBBL/d of liquids; and (ii) the development plan of the Forkados-Yokri field including the drilling of 24 producing wells, the upgrading of existing flow stations and the construction of transport facilities is expected to start-up by 2015.

Eni holds a 10.4% interest in the Nigeria LNG Ltd which runs the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. The seventh unit is being engineered as it is in the planning phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 BCF/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an overall amount of 2,825 mmCF/d (268 mmCF/d net to Eni corresponding to approximately 49 KBOE/d). LNG production is sold under long-term contracts and exported to European, Asian and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.

In the medium term, management expects to increase Eni’s production in Nigeria to approximately 150 KBOE/d.

> 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 2014, 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 NCSPSA. The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field which was discovered in the Northern section of the contractual area in the year 2000 over an 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.

The participating interest in the NCSPSA has been redefined, effective as of January 1, 2008, in line with an agreement signed in October 2008 with Kazakh Authorities which proportionally diluted the participating interest of the international companies by transferring a 10% stake in the project to the Kazakh national oil company, KazMunaiGas. In addition to Eni, the partners of the consortium are the Kazakh national oil company, KazMunaiGas, 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%.

Under the operating model agreed in 2008, Agip Kazakhstan North Caspian Operating Co NV (AKCO), a wholly-owned affiliate of Eni, was assigned the responsibility of executing the development of Phase 1 of the project (the so-called "Experimental Program") acting as agent of the operator North Caspian Operating Co BV (NCOC) owned by all the partners of the Consortium.

On May 23, 2012, the Consortium partners and the Authority of the Republic of Kazakhstan signed an agreement to amend the sanctioned development plan at the Experimental Program of the Kashagan field (Amendment 4) which included an update to the project schedule, a revision of investment estimates and a settlement agreement of all pending claims relating to recoverable costs and other tax matters. The amendment also included a commercial framework to supply a share of the natural gas produced from Kashagan to the domestic market and an agreement whereby the international partners of the Consortium shall finance the share of project cost to be borne by the Kazakh KMG partner, in excess to the amounts sanctioned in the original budget costs (Amendment 3).

In 2014, the Consortium agreed a new setup of the operating model to execute the development of the project, targeting to streamline decision-making process, to increase efficiency in operations and to reduce costs. This new operating model provides that a company, participated by the seven partners of the consortium, acts as the sole operator of all exploration, development and production activities at the Kashagan field. As part of this process, in October 2014 the shareholding in AKCO NV (Eni’s interest 100%) was transferred to NCOC BV. The activities needed to set up the new operating model will be completed by the first half of 2015.

In December 2014, the Consortium and the Kazakh Government signed an agreement which settled a number of pending issues relating to financial, environmental and operational matters.

During the course of 2014, the Consortium performed an assessment of the technical issues which forced the operator to shut down the production at the Kashagan field soon after the production start-up with the effective

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completion of Phase 1 of the development plan (the Experimental Program). The issue regarded a gas leak at a support pipeline. The findings of the assessment confirmed the necessity to fully replace the damaged pipelines. The Consortium recently finalized the contracts for the replacement of both oil and gas lines. The Consortium expects to complete the installation works in the second half of 2016 with production re-start by the end of 2016. The planned production rate will be achieved during 2017.

The Phase 1 is targeting an initial production capacity of 180 KBBL/d; when a second offshore treatment train comes online and compression facilities for gas reinjection are operational production capacity will ramp up to 370 KBBL/d. The partners are planning to 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, 2014, Eni’s proved reserves booked for the Kashagan field amounted to 580 mmBOE, barely unchanged compared to 2013. The major part of these reserves are classified proved undeveloped. See the discussion on "Proved Undeveloped Reserves" section.

As of December 31, 2013, Eni’s proved reserves booked for the Kashagan field amounted to 565 mmBOE, barely unchanged from 2012.

As of December 31, 2012, Eni’s proved reserves booked at the Kashagan field amounted to 568 mmBOE, recording an increase compared to 2011 reflecting the settlement agreement signed with Kazakh Authority whereby Eni will be able to produce and market volumes of natural gas from Kashagan.

As of December 31, 2014, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $8.5 billion (euro 7.0 billion at the EUR/USD exchange rate of December 31, 2014). This capitalized amount included: (i) $6.2 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $2.3 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years. As of December 31, 2013, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $8.2 billion (euro 5.9 billion at the EUR/USD exchange rate of December 31, 2013). This capitalized amount included: (i) $6.1 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $2.1 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years. Karachaganak. Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture. On June 28, 2012, the international Contracting Companies of the Final Production Sharing Agreement (FPSA) of the giant Karachaganak gas-condensate field and the Republic of Kazakhstan closed a settlement agreement of all pending claims relating to the recovery of costs incurred to develop the field and certain tax matters. Eni’s interest in the Karachaganak project is 29.25%. |  |

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In 2014, production of the Karachaganak field averaged 242 KBBL/d of liquids (52 net to Eni) and 842 mmCF/d of natural gas (181 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 50%) 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 90% 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 pipeline. The remaining volumes of non-stabilized liquid production (approximately 16 KBBL/d) are marketed at the Russian terminal in Orenburg.

The expansion project is currently being assessed by the Consortium by means of the installation, in stages, of gas treatment plants and re-injection facilities to support liquids production plateau and increase gas marketable volumes. Phase-one development to increase injection and treatment capacity of natural gas are under economical and technical assessment. Further development projects to support liquids production plateau are under study.

As of December 31, 2014, Eni’s proved reserves booked for the Karachaganak field amounted to 489 mmBOE, barely unchanged compared to 2013.

As of December 31, 2013, Eni’s proved reserves booked for the Karachaganak field amounted to 470 mmBOE, barely unchanged from 2012.

As of December 31, 2012, Eni’s proved reserves booked for the Karachaganak field amounted to 473 mmBOE, reporting a slight decrease from 2011 deriving mainly from the divestment of Eni’s stake in the project, partly offset by upwards revisions.

> Rest of Asia

In 2014, Eni’s operations in the rest of Asia accounted for 6% 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 2014, Eni’s production amounted to 4 KBOE/d.

Exploration and production activities in China are regulated by PSAs.

In 2014, hydrocarbons were produced from the offshore Blocks 16/08 through 3 platforms connected to an FPSO. Production comes mainly from the HZ25-4 field (Eni’s interest 49%). In June 2014, Eni signed with CNOOC the PSC for exploration activity of the Block 50/34, located in the shallow water of the South China Sea. Indonesia. Eni has been present in Indonesia since 2001. In 2014, Eni’s production mainly composed of gas, amounted to 13 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. Main ongoing activities to feed the Bontang plant concerned: (i) the Jangkrik field (Eni operator with an 55% interest) in the Kalimantan offshore. The project includes drilling of production wells linked to a Floating Production Unit for gas and condensate treatment, as well as construction of a transportation facility. Start-up is expected in 2017; and (ii) the Bangka project (Eni’s interest 20%) in the Eastern Kalimantan, with start-up expected in 2016. Exploration activities yielded positive results with a gas discovery through the Merakes 1 NFW exploration well in the East Sepinggan offshore block (Eni operator with an |  |

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85% interest). This discovery is located in proximity of the operated field of Jangkrik, and will supply additional gas volumes to the Bontang LNG plant. Iran. Eni has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the NIOC between 1999 and 2001, and no other exploration and development contracts have been entered into since then. All above mentioned projects have been completed or substantially completed. The formal hand over of operations to local partners at the Darquain project was completed in the course of 2014, marking termination of Eni’s direct operations in the Country. Going forward, Eni’s involvements will consist of finalizing the reimbursement of its past investments. In 2014, Eni’s contractual reimbursements were equivalent to a production of 1 KBOE/d, lower than 1% of the Group’s worldwide production. Eni believes that its activities in Iran are marginal to the Group’s results of operations and cash flow. For further information on this matter, see "Item 3 – Risk factors". 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 oilfield. 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 2014, production of the Zubair field averaged 21 KBBL/d net to Eni. In 2014, phase one of the Rehabilitation Plan of the Zubair field progressed. The project includes the construction of an oil treatment plant for a capacity of 300 KBBL/d, the revamping of existing treatment facilities and the drilling of production and water injection wells. In March 2014, the national oil company South Oil Company sanctioned the Enhanced Redevelopment Plan to achieve a production plateau of 850 KBBL/d. The main contracts to build new facilities were awarded in the first half of 2014. Pakistan. Eni has been present in Pakistan since 2000. In 2014, Eni’s production mainly composed of gas amounted to 43 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), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2013 accounted for 75% of Eni’s production in Pakistan. Russia. The drilling exploration program was halted due to the sanctions enacted by European Union and the United States. Eni is closely monitoring developments of |  |

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the situation and has required all relevant authorizations to continue the exploration activities in compliance with the current sanction regime against Russia. 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. In 2014, Eni’s production averaged 9 KBOE/d.

Exploration and production activities in Turkmenistan are regulated by PSA.

In November 2014, Eni and the State Agency for Management and Use of Hydrocarbon Resources signed an addendum to the production sharing agreement which extends the duration of the PSA to 2032. The agreement also establishes the transfer of a 10% stake out of the contractor share to the State oil company Turkmenneft (Eni retains a 90% interest stake).

In addition, Eni and Turkmen State Agency signed a Memorandum of Understanding to evaluate the extension of Eni’s activities also in the Turkmenistan’s offshore section of the Caspian Sea.

Production derives mainly from the Burun oilfield. 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 own consumption and gas lift system. The remaining amount is delivered to the national oil company Turkmenneft, via national grid.

Development activities include: (i) a program to mitigate the natural field production decline; and (ii) the completion of the revamping of the treatment oil plant at the Burun field in order to increase treatment capacity.

> Americas

In 2014, Eni’s operations in America area accounted for 8% 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 2014, Eni’s production averaged 12 KBBL/d.

Exploration and production activities in Ecuador are regulated by a service contract that expires in 2023.

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

In the year, the following projects were sanctioned: (i) Villano field Phase VI (infilling), with a production start-up expected in 2016; and (ii) Oglan discovery development, with start-up expected in 2017.

Exploration activities yielded positive results with the Oglan-2 exploration well in Block 10, located near the processing facilities of the Villano field.

Trinidad & Tobago. Eni has been present in Trinidad & Tobago since 1970. In 2014, Eni’s production averaged 60 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 & 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 in the United States, as well as alternative destinations on a spot basis.

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 2014, Eni’s oil and gas production was 88 KBOE/d, mainly from the Gulf of Mexico and Alaska fields.

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

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Eni holds interests in 188 exploration and production blocks in the Gulf of Mexico of which 122 are operated by Eni.

Eni was awarded the operatorship of exploration licenses MC246 and MC290 (Eni’s interest 100%) in the Gulf of Mexico and in the Leon Valley (Western Texas) with a 50% interest for exploring and developing an area with shale oil reservoirs.

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%), Medusa (Eni’s interest 25%) and Thunder Hawk (Eni’s interest 25%) fields.

Production start-up was achieved at the St. Malo (Eni’s interest 1.25%) and Lucius (Eni 8.5%) fields, the latter started up in January 2015. The start-up of Hadrian South (Eni’s interest 30%) is achieved in March 2015. In the Greater Hadrian Area (Lucius and Hadrian South fields) Eni plans to achieve an expected net production peak of 22 KBOE/d.

Development activities concerned: (i) the Heidelberg project (Eni’s interest 12.5%) in the deep offshore of the Gulf of Mexico. Activities include the drilling of 5 production wells and the installation of a production platform. Start-up is expected at the end of 2016 with a production of 9 KBOE/d net to Eni; (ii) the drilling of development wells at the operated Devils Tower and Pegasus fields, as well as non-operated Europa and K2 (Eni’s interest 13.39%) fields; and (iii) the development of shale gas reserves in the Alliance area (Eni’s interest 27.5%) with start-up of additional 21 production wells.

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 99 exploration and development blocks in Alaska, with interests ranging from 10 to 100%; Eni is the operator in 46 of these blocks.

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Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) with a 2014 overall net production of approximately 21 KBBL/d.

During 2014, drilling activities progressed at the Nikaitchuq and Oooguruk fields.

In June 2014, the Nikaitchuq field achieved the production milestone of 25 KBOE/d.

Exploration activities yielded positive results with the Stallings 1H and Mitchell 1H exploratory wells, under the agreement with Quicksilver Resources signed at the end of 2013 providing for joint evaluation, exploration and development of shale oil reservoirs in the Southern part of the Delaware Basin in West Texas. The wells were already connected to existing production facilities with an initial flow of 1,500 BBL/d.

Venezuela. Eni has been present in Venezuela since 1998. In 2014, Eni’s production averaged 10 KBBL/d.

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

Exploration and production of oilfields 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).

Eni’s production comes from the Corocoro field (Eni’s interest 26%), in the Gulfo de Paria, and the Junin 5 field (Eni’s interest 40%), located in the Orinoco Oil Belt which contains 35 BBBL of certified heavy oil in place.

Drilling activities progressed at the Junin 5 field with the drilling of 22 wells. The early production of the first phase started up in 2013 with a target plateau of 75 KBBL/d. The full field development phase includes a long-term production plateau of 240 KBBL/d.

Ongoing development activities progressed at the Perla gas field in the Cardon IV Block (Eni’s interest 50%), located in the Gulf of Venezuela. The early production start-up is expected by the second quarter of 2015 with a target production of approximately 450 mmCF/d. The full project includes the utilization of 4 existing wells, the drilling of 17 additional wells and the installation of production platforms linked by pipelines to an onshore treatment plant. Production ramp-up is expected in 2017 with a target of approximately 800 mmCF/d. The development plan targets a long-term production plateau of approximately 1,200 mmCF/d from 2020.

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 this region area are conducted mainly in Australia. In 2014, the area of Australia and Oceania accounted for 2% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2001. In 2014, Eni’s production of oil and natural gas averaged 25 KBOE/d. Activities are focused on conventional and deep offshore fields.

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%), JPDA 03-13 (Eni’s interest 10.99%) and JPDA 06-105 (Eni operator with a 40% interest). In the appraisal and development phase Eni holds interests in NT/P68 (Eni’s interest 50%) and NT/RL7 (Eni’s interest 32.5%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA.

Ongoing development activities concerned: (i) Phase 3 project of Bayu Undan field in the JPDA 03-13 Block in order to increase liquids and LNG production; and (ii) drilling development activities at the Kitan producing field in the JPDA 06-105 Block in order to increase liquids production.

> Capital expenditures

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

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> 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. Disclosure responsive to this requirement is presented under "Item 3 – Political considerations – Risks associated with our presence in sanction targets" and below in this section.

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. We do not believe that any of the transactions or activities listed below violated U.S. sanctions also considering the waiver that we were granted by relevant U.S. Authorities, including the U.S. Department of State, in relation to certain Iran-related activities. For more information please refer to "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets".

As described in more detail under "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets", in 2014, Eni carried out support activities and services in respect of certain oilfields in Iran pursuant to certain legacy Service Contracts. Eni’s operating expenses pursuant to those contracts in 2014 amounted to approximately $1 million. In addition, in connection with its remaining Iranian operations, in 2014, Eni paid approximately $3 million for social security, withholding tax, corporate tax and rental tax.

In 2014, Eni’s production in Iran averaged 1 KBOE/d, and is negligible in comparison with Eni Group’s total production for the year. We booked revenues of $26 million in 2014 in connection with our share of equity production and we reported a net loss of $16 million at our Iranian operations. As of the balance sheet date Eni had outstanding trade receivables amounting to $76 million towards Iranian oil national companies which were recorded in connection with revenues recognized in 2014 and in previous reporting periods. In 2014, we collected cash payments for a total of $275 million. Those revenues and trade receivables related to the recovery of the costs incurred by Eni in its performance of petroleum projects, mainly pertaining to the ongoing Darquain project as disclosed under "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets". We had no payables towards Iranian national oil companies as of the balance sheet date. We had a payable amounting to $23 million relating to health and social security insurance due to the Iranian Social Security Organization, which will be settled upon termination of our oil projects.

Eni Exploration & Production projects in Iran are currently in the cost recovery phase. Therefore, Eni has ceased making any further investment in the Country and is not planning to make additional capital expenditures in Iran in future years.

Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply and marketing. This segment also includes the activities of electricity generation. In 2014, Eni’s worldwide sales of natural gas amounted to 89.17 BCM, including 3.06 BCM of gas sales made directly by Eni’s Exploration & Production segment. Sales in Italy amounted to 34.04 BCM, while sales in European markets were 46.22 BCM that included 4.01 BCM of gas sold to certain importers to Italy.

In the Gas & Power segment we expect a weak outlook for natural gas sales and prices due to structural headwinds in the industry as we forecast demand stagnation, oversupplies and strong competition across all of our main markets in Europe, including Italy. Management does not expect any improvements in this scenario in the next four-year plan. Management expects gas sales to be flat to down over the next four years and gas prices to continue falling.

Going forward we believe that reduced sales opportunities and continued pricing competition will be caused by weaker-than-anticipated demand growth. This is expected to be further exacerbated by macroeconomic uncertainties and the current downturn in the thermoelectric sector which will be penalized by the competition from coal which is cheaper than gas in firing power plants and the development of renewable sources of energy (photovoltaic, solar to name the most important). The absolute level of gas consumption in Europe contracted by approximately 12% in the time span from 2008 to 2013 and in 2014 gas consumption fell dramatically by 12% in Italy and in Europe. According to our projections gas consumption will return back to 2013 levels sometime in 2020. Against this backdrop, European markets remains well supplied thanks to the fast development of liquid hubs where operators can trade spot gas. In 2013, approximately 62% of gas volumes supplied were traded at continental hubs. These trends will drive continuing

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competition and pricing pressure, which are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses whereby wholesaler 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 backdrop, Eni’s main focus is on profitability and sustainable cash flow generation, according to the following guidelines: (i) alignment of the supply portfolio to market conditions starting from 2016, leveraging on further renegotiations; (ii) the full streamlining of operations and optimization of logistic costs; and (iii) development and growth in the value added segments, in particular in the retail segment, developing the client base also through the sale of extra-commodity products, as well as in the LNG segment, leveraging on the marketing opportunities in premium markets and upstream integration.

> Supply of natural gas

In 2014, Eni’s consolidated subsidiaries supplied 82.91 BCM of natural gas, down by 2.76 BCM, or 3.2% from 2013. Gas volumes supplied outside Italy (75.99 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 92% of total supplies, down by 2.53 BCM, or 3.2% compared to the previous year, due to lower volumes purchased in Russia (down 2.91 BCM), Algeria (down 1.80 BCM), Norway (down 0.73 BCM) and the United Kingdom (down 0.40 BCM), partly offset by higher volumes purchased in Libya (up 0.88 BCM) and the Netherlands (up 0.40 BCM). Supplies in Italy (6.92 BCM) registered a slight decrease from 2013 (down 0.23 BCM) due to mature fields’ decline. In 2014, main gas volumes from equity production derived from: (i) Italian gas fields (5.6 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.1 BCM); (iii) Libyan fields (2 BCM); (iv) the United States (0.5 BCM); and (v) other European areas (Croatia with 0.3 BCM). Considering also direct sales of the Exploration & Production Division and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 16 BCM representing 18% 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 |  | 2012 |  | 2013 |  | 2014

|  | (BCM)

Italy |  | 7.55 |  |  | 7.15 |  |  | 6.92 |
Outside Italy |  | 79.14 |  |  | 78.52 |  |  | 75.99 |
Russia |  | 19.83 |  |  | 29.59 |  |  | 26.68 |
Algeria (including LNG) |  | 14.45 |  |  | 9.31 |  |  | 7.51 |
Libya |  | 6.55 |  |  | 5.78 |  |  | 6.66 |
the Netherlands |  | 11.97 |  |  | 13.06 |  |  | 13.46 |
Norway |  | 12.13 |  |  | 9.16 |  |  | 8.43 |
the United Kingdom |  | 3.20 |  |  | 3.04 |  |  | 2.64 |
Hungary |  | 0.61 |  |  | 0.48 |  |  | 0.38 |
Qatar (LNG) |  | 2.88 |  |  | 2.89 |  |  | 2.98 |
Other supplies of natural gas |  | 5.43 |  |  | 3.63 |  |  | 5.56 |
Other supplies of LNG |  | 2.09 |  |  | 1.58 |  |  | 1.69 |
Total supplies of subsidiaries |  | 86.69 |  |  | 85.67 |  |  | 82.91 |
Withdrawals from (input to) storage |  | (1.35 | ) |  | (0.58 | ) |  | (0.20 | )
Network losses, measurement differences and other changes |  | (0.28 | ) |  | (0.31 | ) |  | (0.25 | )
Volumes available for sale of Eni’s subsidiaries |  | 85.06 |  |  | 84.78 |  |  | 82.46 |
Volumes available for sale of Eni’s affiliates |  | 7.53 |  |  | 5.78 |  |  | 3.65 |
E&P volumes |  | 2.73 |  |  | 2.61 |  |  | 3.06 |
Total volumes available for sale |  | 95.32 |  |  | 93.17 |  |  | 89.17 |

> Sales of natural gas

In 2014, natural gas sales amounted to 89.17 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 4 BCM, or 4.3% from the previous year. Sales in Italy decreased to 34.04 BCM, down by 5.1%. Lower sales were reported in the industrial, residential and thermoelectric segments due to decreased consumption, unusual winter weather conditions and a further deterioration of the trading environment for electricity sales reflecting higher use of hydroelectric and renewable sources, as well as lower demand. These negative trends were partially offset by higher spot volumes. Sales in Europe of 42.21 BCM decreased by 1.1% driven mainly by lower volumes marketed in Germany-Austria, France and the United Kingdom due to competitive pressure, partially offset by higher sales in Benelux and the Iberian Peninsula. Direct sales of Exploration & Production in Northern Europe and the United States

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(3.06 BCM) increased by 0.45 BCM due to higher volumes sold in the North Sea. Sales to importers to Italy decreased by 14.1% compared to the previous year, due to lower availability of Libyan output and lower sales to Extra European markets (down 20.4%) driven by lower volumes marketed in the United States and Argentina.

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

Natural gas sales by entity |  | 2012 |  | 2013 |  | 2014

|  | (BCM)

Total sales of subsidiaries |  | 84.30 |  | 83.60 |  | 81.73
Italy (including own consumption) |  | 34.66 |  | 35.76 |  | 34.04
Rest of Europe |  | 44.57 |  | 42.30 |  | 43.07
Outside Europe |  | 5.07 |  | 5.54 |  | 4.62
Total sales of Eni’s affiliates (Eni’s share) |  | 8.29 |  | 6.96 |  | 4.38
Italy |  | 0.12 |  | 0.10 |  |
Rest of Europe |  | 6.45 |  | 5.05 |  | 3.15
Outside Europe |  | 1.72 |  | 1.81 |  | 1.23
Total sales of G&P |  | 92.59 |  | 90.56 |  | 86.11
E&P in Europe and in the Gulf of Mexico (a) |  | 2.73 |  | 2.61 |  | 3.06
Worldwide gas sales |  | 95.32 |  | 93.17 |  | 89.17

(a) |  | E&P sales include volumes marketed by the Exploration & Production Division in Europe (2.06, 2.08 and 2.60 BCM in 2012, 2013 and 2014, respectively) and in the Gulf of Mexico (0.67, 0.53 and 0.46 BCM in 2012, 2013 and 2014, respectively).

Natural gas sales by market |  | 2012 |  | 2013 |  | 2014

|  | (BCM)

ITALY |  | 34.78 |  | 35.86 |  | 34.04
Wholesalers |  | 4.65 |  | 4.58 |  | 4.05
Italian gas exchange and spot markets |  | 7.52 |  | 10.68 |  | 11.96
Industries |  | 6.93 |  | 6.07 |  | 4.93
Medium-sized enterprises and services |  | 0.81 |  | 1.12 |  | 1.60
Power generation |  | 2.55 |  | 2.11 |  | 1.42
Residential |  | 5.89 |  | 5.37 |  | 4.46
Own consumption |  | 6.43 |  | 5.93 |  | 5.62
INTERNATIONAL SALES |  | 60.54 |  | 57.31 |  | 55.13
Rest of Europe |  | 51.02 |  | 47.35 |  | 46.22
Importers in Italy |  | 2.73 |  | 4.67 |  | 4.01
European markets |  | 48.29 |  | 42.68 |  | 42.21
Iberian Peninsula |  | 6.29 |  | 4.90 |  | 5.31
Germany-Austria |  | 7.78 |  | 8.31 |  | 7.44
Benelux |  | 10.31 |  | 8.68 |  | 10.36
Hungary |  | 2.02 |  | 1.84 |  | 1.55
UK/Northern Europe |  | 4.75 |  | 3.51 |  | 2.94
Turkey |  | 7.22 |  | 6.73 |  | 7.12
France |  | 8.36 |  | 7.73 |  | 7.05
Other |  | 1.56 |  | 0.98 |  | 0.44
Extra European markets |  | 6.79 |  | 7.35 |  | 5.85
E&P in Europe and in the Gulf of Mexico |  | 2.73 |  | 2.61 |  | 3.06
WORLDWIDE GAS SALES |  | 95.32 |  | 93.17 |  | 89.17

> European markets

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

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, in the retail and middle market and its significant exposure to spot markets in Western Europe. In 2014, sales in Benelux were mainly directed to industrial companies, power generation and wholesalers and amounted to 10.36 BCM (8.68 BCM in 2013), up by 1.68 BCM, or 19.4%, due to higher spot sales. In 2012, Eni launched its brand in the business and retail gas and power market in Belgium. The Eni brand replaced that of local operators acquired in the past few years with the aim of consolidating its leadership in the market.

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France. Eni sells natural gas to industrial clients, wholesalers and power generation, 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 2014, sales in France amounted to 7.05 BCM (7.73 BCM in 2013), a decrease of 0.68 BCM, or 8.8%, from a year ago. In 2013, Eni launched its brand in France, replacing those of the local operators acquired in the past few years with the aim of becoming one of the major retail operators in the Country.

Germany-Austria. Eni operates in Germany-Austria through Gas & Power branches. In 2014, Eni divested its 50% stake in EnBW Eni Verwaltungsgesellschaft (EEV), a joint venture which controls the companies Gasversorgung Süddeutschland (GVS) and Terranets BW operating in the gas marketing and transport, to the partner EnBW. Currently, sales in this market are ensured by Eni’s direct sales force. In 2014, total sales in Germany-Austria amounted to 7.44 BCM, a decrease of 0.87 BCM, or 10.5%.

Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and through Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2014, UFG gas sales amounted to 3.92 BCM (1.96 BCM Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) re-gasification plants (42.5% and 18.9%, respectively). In 2014, total sales in the Iberian Peninsula amounted to 5.31 BCM, an increase of 0.41 BCM, or 8.4%.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2014, sales amounted to 7.12 BCM, an increase of 0.39 BCM, or 5.8% from a year ago.

United Kingdom. Eni through its subsidiary ETS markets in the United Kingdom the equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). In 2014, sales amounted to 2.94 BCM, a decrease of 16.2% from a year ago.

> The LNG business

Eni is implementing its fully-integrated worldwide commercial LNG Strategy leveraging on Eni’s:

• |  | technological and operational involvement in all phases of the LNG value chain: provide feed gas, liquefaction, shipping, re-gasification and sales both through direct activities and interests in joint ventures;
• |  | portfolio of long-term LNG supply contracts mainly from Qatar, Algeria and Nigeria;
• |  | medium-term LNG sales contracts with buyers all over the world; and
• |  | LNG portfolio management and operations activities targeting value creation by optimizing Eni’s supply and sales portfolio in close operation with Eni’s trading activities and Eni’s European pipeline gas businesses.

Eni’s LNG development strategy is based upon Eni’s world scale gas reserves in Mozambique combined with the existing LNG activities in Nigeria, Angola, Australia, Trinidad & Tobago and Indonesia.

In 2014, Eni could successfully continue its value creation in both the Atlantic and Pacific Basin LNG markets notwithstanding the context of a European Gas Market still impacted by the economic downturn and oversupply and structural modifications caused by the shale gas development in the U.S. market.

However, the significant drop in oil prices from which the gas prices in markets in the Pacific Basin and South America are derived and which has not been reflected in spot gas prices in Europe has substantially reduced the potential optimization margin by the end of 2014 and 2015.

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LNG sales |  | 2012 |  | 2013 |  | 2014

|  | (BCM)

G&P sales |  | 10.5 |  | 8.4 |  | 8.9
Rest of Europe |  | 7.6 |  | 4.6 |  | 5.0
Extra European markets |  | 2.9 |  | 3.8 |  | 3.9
E&P sales |  | 4.1 |  | 4.0 |  | 4.4
Liquefaction plants: |  |  |  |  |  |
- Soyo (Angola) |  |  |  | 0.1 |  | 0.1
- Bontang (Indonesia) |  | 0.6 |  | 0.5 |  | 0.5
- Point Fortin (Trinidad & Tobago) |  | 0.5 |  | 0.6 |  | 0.6
- Bonny (Nigeria) |  | 2.7 |  | 2.4 |  | 2.8
- Darwin (Australia) |  | 0.3 |  | 0.4 |  | 0.4
|  | 14.6 |  | 12.4 |  | 13.3

> Electricity sales and power generation

> Electricity sales

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, at industrial sites and on the Italian Stock Exchange for electricity. 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 2014, power sales (33.58 TWh) were directed to the free market (74%), the Italian Power Exchange (14%), industrial sites (9%) and others (3%). Compared with 2013, electricity sales were down by 4.2%, due to lower sales to large clients and wholesalers partially offset by higher volumes traded on the Italian Power Exchange.

Power availability |  | 2012 |  | 2013 |  | 2014

|  | (TWh)

Power generation sold |  | 23.58 |  | 21.38 |  | 19.55
Trading of electricity (a) |  | 19.00 |  | 13.67 |  | 14.03
|  | 42.58 |  | 35.05 |  | 33.58
Power sales by market |  |  |  |  |  |
Free market (a) |  | 31.84 |  | 28.73 |  | 24.86
Italian Exchange for electricity |  | 6.10 |  | 1.96 |  | 4.71
Industrial plants |  | 3.30 |  | 3.31 |  | 3.17
Other (a) |  | 1.34 |  | 1.05 |  | 0.84
|  | 42.58 |  | 35.05 |  | 33.58

(a) |  | Include positive and negative imbalances.

> Power generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Mantova, Brindisi, Ferrara and Bolgiano. In 2014, power generation was 19.55 TWh, down by 1.83 TWh, or 8.6% from 2013, mainly due to lower production at Ravenna and Brindisi plants due to decreasing demand. As of December 31, 2014, installed operational capacity was 4.9 GW (4.8 GW as of December 31, 2013). Electricity trading reported a slight increase (up 2.6% to 14.03 TWh) due to higher purchases on the spot market.

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Site |  | Total installed capacity in 2014 (a) (MW) |  | Technology |  | Fuel

Brindisi |  | 1.3 |  | CCGT |  | gas
Ferrera Erbognone |  | 1.0 |  | CCGT |  | gas/syngas
Livorno |  | 0.2 |  | Power station |  | gas/fuel oil
Mantova |  | 0.9 |  | CCGT |  | gas
Ravenna |  | 1.0 |  | CCGT |  | gas
Ferrara (b) |  | 0.8 |  | CCGT |  | gas
Bolgiano |  | 0.1 |  | Power station |  | gas
|  | 5.3 |  |  |  |

(a) |  | Capacity available after completion of dismantling of obsolete plants.
(b) |  | Eni’s share of capacity.

Power generation |  | 2012 |  | 2013 |  | 2014

Purchases |  |  |  |  |  |  |  |
Natural gas |  | (mmCM) |  | 4,792 |  | 4,295 |  | 4,074
Other fuels |  | (ktoe) |  | 462 |  | 449 |  | 338
- of which steam cracking |  |  |  | 98 |  | 99 |  | 104
Production |  |  |  |  |  |  |  |
Electricity |  | (TWh) |  | 23.58 |  | 21.38 |  | 19.55
Steam |  | (ktonnes) |  | 12,603 |  | 9,907 |  | 9,010
Installed generation capacity |  | (GW) |  | 5.3 |  | 4.8 |  | 4.9

> 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 transport activities are provided in the table below.

International transport infrastructure

Route |  | Lines |  | Total length |  | Diameter |  | Transport capacity (1) |  | Transit capacity (2) |  | Compression stations
|  | (units) |  | (km) |  | (inch) |  | (BCM/y) |  | (BCM/y) |  | (No.)

TTPC (Oued Saf Saf-Cap Bon) |  | 2 lines of km 370 |  | 740 |  | 48 |  | 34.0 |  | 33.2 |  | 5
TMPC (Cap Bon-Mazara del Vallo) |  | 5 lines of km 155 |  | 775 |  | 20/26 |  | 33.5 |  | 33.5 |  |
GreenStream (Mellitah-Gela) |  | 1 line of km 520 |  | 520 |  | 32 |  | 8.0 |  | 8.0 |  | 1
Blue Stream (Beregovaya-Samsun) |  | 2 lines of km 387 |  | 774 |  | 24 |  | 16.0 |  | 16.0 |  | 1

(1) | i | Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(2) | i | The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.

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> 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 33.2 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.

> The South Stream project

In December 2014, Eni divested its 20% stake in South Stream Transport BV to Gazprom. The company is engaged in the economic feasibility, procurement and construction of the offshore section of the South Stream pipeline. Pursuant to the shareholders’ agreement, Eni exercised a put option of its stake whereby the Company will recover the capital invested to date in the project, determined in accordance with existing agreements.

> Capital expenditures

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

Refining & Marketing

Eni’s Refining & Marketing segment engages in the supply of crude oil, refining and marketing of refined products, trading and shipping of crude oil and refined products primarily in Italy and in Central-Eastern Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company’s operations are fully integrated through refining, supply, trading, logistics and marketing so as to maximize cost efficiencies and effectiveness of operations.

For the next four years, the priority of our Refining & Marketing segment is to return to profitability in the context of weak fundamentals of the European refining market, affected by weak demand, structural overcapacity and competitive pressure from streams of cheaper products from Asia, Russia and the United States. Eni intends to reduce its exposure to the refining segment and implement a number of restructuring initiatives, as well as cost efficiencies and process optimization. The reduction of refining exposure, up to 50% (base 2012) will be achieved through the reconversion of productive processes and adoption of production cycles based on feedstock derived from agriculture and other renewable sources, as well as initiatives which are designed to restructure or shut down unprofitable production lines. As part of this strategy we shut down the obsolete, gasoline-designed refinery at Venice and started up the production of green diesel and we also signed a framework agreement with Italian Authorities and stakeholders for the restructuring of the loss-making Gela refinery which was shut down and will undergo an upgrading initiative to produce bio-fuels. We also signed a preliminary agreement for the divestment of our interest in a refinery located in the Czech Republic. We believe that those actions will significantly reduce our breakeven in the refining business going forward. The refineries in the Eni circuit are in a better position to face competition and will be further strengthened in order to enhance their flexibility and efficiency. In the marketing segment, the strategy is focused on simplifying the commercial offer, the launch of a new loyalty campaign, the operating efficiency, as well as the reorganization of commercial network and the closure of marginal sale points. The main economic and financial targets of the Refining & Marketing segment are the achievement of the break even level of adjusted operating profit and return to the positive cash flow from 2015.

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The matters regarding future plans discussed in this section and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward looking statements. Such risks and uncertainties include difficulties in obtaining approvals from relevant Antitrust Authorities and developments in the relevant market.

> Supply

In 2014, a total of 70.14 mmtonnes of crude were purchased by the Refining & Marketing segment (65.96 mmtonnes in 2013), of which 27.47 mmtonnes from Eni’s Exploration & Production segment, 25.60 mmtonnes on the spot market and 17.07 mmtonnes were purchased under long-term supply contracts with producing countries. The subdivision by geographic area was as follows: approximately 35% of crude purchased in 2014 came from Russia, 18% from West Africa, 11% from the North Sea, 8% from the Middle East, 7% from North Africa, 6% from Italy and 15% from other areas. In 2014, a total of 49.99 mmtonnes of crude purchased were marketed, up by 6.03 mmtonnes or 13.7% from 2013. In addition, 4.94 mmtonnes of intermediate products were purchased (5.31 mmtonnes in 2013) to be used as feedstock in conversion plants and 20.87 mmtonnes of refined products (17.79 mmtonnes in 2013) were purchased to be sold on markets outside Italy (16.13 mmtonnes) and on the Italian market (4.74 mmtonnes) as a complement to available production.

> Refining

In 2014, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 30.8 mmtonnes (equal to 617 KBBL/d) and a conversion index of 51%. Conversion index is a measure of refinery complexity. The higher the index, the wider the spectrum of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies which the Company generally expects to achieve as certain qualities of crude (particularly the heavy ones) may trade at discount with reference to the light crude Brent benchmark. Eni’s five 100% owned refineries have balanced capacity of 20.2 mmtonnes (equal to 404 KBBL/d), with a 54% conversion index. In 2014, Eni’s refineries throughputs in Italy and outside Italy was 25.03 mmtonnes.

The table below sets forth certain statistics regarding Eni’s refineries as of December 31, 2014.

Refining system in 2014

|  | Ownership share (%) |  | Distillation capacity (total) (KBBL/d) |  | Distillation capacity (Eni’s share) (KBBL/d) |  | Primary balanced refining capacity (1)(Eni’s share) (KBBL/d) |  | Conversion index (%) |  | Fluid catalytic cracking - FCC (KBBL/d) |  | Residue conversion (KBBL/d) |  | Go-Finer/ Mild Hydro- cracking/ (KBBL/d) |  | Mild Hydro- cracking/ Hydro- cracking (KBBL/d) |  | Visbreaking/ thermal cracking (KBBL/d) |  | Coking (KBBL/d) |  | Distillation capacity utilization rate (Eni’s share) (%) |  | Balanced refining capacity utilization rate (Eni’s share) (%)

Wholly-owned refineries |  |  |  | 449 |  | 449 |  | 404 |  | 54 |  | 34 |  | 35 |  | 0 |  | 66 |  | 67 |  | 0 |  | 72 |  | 78
Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sannazzaro |  | 100 |  | 223 |  | 223 |  | 200 |  | 70 |  | 34 |  | 13 |  |  |  | 51 |  | 29 |  |  |  | 75 |  | 83
Gela |  | 100 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Taranto |  | 100 |  | 120 |  | 120 |  | 120 |  | 56 |  |  |  | 22 |  |  |  | 15 |  | 38 |  |  |  | 62 |  | 62
Livorno |  | 100 |  | 106 |  | 106 |  | 84 |  | 11 |  |  |  |  |  |  |  |  |  |  |  |  |  | 71 |  | 90
Porto Marghera |  | 100 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Partially-owned refineries (2) |  |  |  | 874 |  | 245 |  | 213 |  | 47 |  | 167 |  | 25 |  |  |  | 99 |  | 27 |  |  |  | 85 |  | 88
Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Milazzo |  | 50 |  | 248 |  | 124 |  | 100 |  | 60 |  | 45 |  | 25 |  |  |  | 32 |  |  |  |  |  | 80 |  | 85
Germany |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Vohburg/Neustadt (Bayernoil) |  | 20 |  | 215 |  | 43 |  | 41 |  | 36 |  | 49 |  |  |  |  |  | 43 |  |  |  |  |  | 91 |  | 91
Schwedt |  | 8.33 |  | 231 |  | 19 |  | 19 |  | 42 |  | 49 |  |  |  |  |  |  |  | 27 |  |  |  | 102 |  | 102
Czech Republic |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Kralupy and Litvinov (Céska Rafinérská) |  | 32.4 |  | 180 |  | 58 |  | 53 |  | 30 |  | 24 |  |  |  |  |  | 24 |  |  |  |  |  | 87 |  | 87
Total refineries |  |  |  | 1,323 |  | 694 |  | 617 |  | 51 |  | 201 |  | 60 |  | 0 |  | 165 |  | 94 |  | 0 |  | 75 |  | 82

(1) |  | Actual production capacity: Venice working as "Green Refinery", Gela shutdown in HUB crudes asset.
(2) |  | Capacity of conversion plant is 100%.

> Italy

Eni’s refining system in Italy is composed of five wholly-owned refineries and a 50% share in the Milazzo refinery in Sicily. Eni’s refineries in Italy operate and plan in order to maximize asset value according to the markets and the integration with Eni’s other activities.

Sannazzaro refinery has balanced refining capacity of 200 KBBL/d and a conversion index of 70.2%. Management believes that this site is one of the most efficient refineries in Europe. Located in the Po Valley, it mainly supplies markets in North-Western Italy and Switzerland. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the

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Central Europe pipeline, which links the Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulphurization units. Conversion is obtained through a fluid catalytic cracker (FCC), two hydrocrackers (HdC), the last unit entered into operations in June 2009, which enable middle distillate conversion and a visbreaking thermal conversion unit with a gasification facility loaded with heavy residue from visbreaking unit (tar) to produce syn-gas to feed the nearby EniPower power plant at Ferrera Erbognone. In 2013, the Eni Slurry Technology (EST) project was started up. The conversion plant with a 23 KBBL/d capacity is designed to process extra heavy crude with high sulphur content increasing yields in middle distillates and reducing that of fuel oil. Eni is also developing an upgrading of its conversion technology called Slurry Dual Catalyst (an evolution of EST), which is based on a combination of two nano-catalysts and aims at increasing productivity and improving product quality, reducing expenditure and operating costs. A further project underway is the proprietary process for hydrogen production, Hydrogen SCT-CPO (Short Contact Time-Catalytic Partial Oxidation). This reforming technology transforms gaseous and liquid hydrocarbons (also derived from bio-mass) into synthetic gas (carbon monoxide and hydrogen) at competitive costs.

Taranto refinery has balanced refining capacity of 120 KBBL/d and a conversion index of 56%. This refinery process most of oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2014 a total of 2.91 mmtonnes of this oil were processed). It principally produces fuels for automotive use and residential heating purposes for the Southern Italian markets. The complexity is achieved through a Residue Hydroconversion Unit (RHU)-Hydrocracking process and a "Two Stage" Visbreaking-Thermal Cracking unit.

Gela refinery is located on the Southern coast of Sicily. In November 2014, Eni defined with the Ministry for Economic Development, the Region of Sicily and interested stakeholders a plan to restore the profitability of the plant through its reconversion into a bio-refinery. The reconversion will follow the model adopted for the Venice green refinery, where green diesel is produced from raw vegetable materials by using the proprietary EcofiningTM technology. The agreement also defines terms for building a modern logistic hub and new initiatives in the upstream sector in Sicily, including offshore. Eni will also perform environmental remediation and cleanup activities and institute the Safety Competence Center (SCC), a center of excellence in the security field.

Livorno refinery, with balanced refining capacity of 84 KBBL/d and a conversion index of 11.4%, manufactures mainly gasoline, fuel oil for bunkering and lubricant bases. Besides its primary distillation plants, this refinery contains two lubricant manufacturing lines. Its infrastructures including highways, railways and pipeline connecting the site with the local harbor and with the Florence storage sites through two pipelines optimizing intake, handling and distribution of products.

Porto Marghera bio-refinery. The process of reconversion of the traditional plant to bio-refinery was completed in June 2014 with the start-up of operations. The green diesel is produced from refined vegetable oil utilizing the proprietary EcofiningTM technology. The production will fulfill half of the Eni’s annual requirement of green diesel, thus ensuring new perspectives for the industrial site of Venice and allowing economic and environmental benefits.

> Outside Italy

In Germany, Eni’s share in the Schwedt refinery is 8.3% and 20% in Bayernoil, an integrated industrial hub that includes Vohburg and Neustadt refineries. Eni’s refining capacity in Germany is approximately 60 KBBL/d mainly to supply Eni’s distribution network in Bavaria and Eastern Germany.

In the Czech Republic, Eni owns a share of 32.4% in the Céska Rafinerska that includes two refineries, Kralupy and Litvinov. Eni’s refining capacity amounts to about 53 KBBL/d to supply Eastern Europe networks.

In May 2014, Eni signed a preliminary agreement for the divestment of its interest in the Ceská Rafinérská and of the marketing activities of fuels located in Czech Republic, Slovakia and Romania which are supplied by the above mentioned refinery. The closing of the transaction is still pending. Eni plans to continue the marketing of lubricants in the wholesale segment in Czech Republic, Slovakia and Romania.

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Table below sets forth Eni’s products availability figures for the periods indicated.

Availability of refined products |  | 2012 |  | 2013 |  | 2014

|  | (mmtonnes)

ITALY |  |  |  |  |  |  |  |  |
Refinery throughputs |  |  |  |  |  |  |  |  |
At wholly-owned refineries |  | 20.84 |  |  | 18.99 |  |  | 16.24 |
Less input on account of third parties |  | (0.47 | ) |  | (0.57 | ) |  | (0.58 | )
At affiliated refineries |  | 4.52 |  |  | 4.14 |  |  | 4.26 |
Refinery throughputs on own account |  | 24.89 |  |  | 22.56 |  |  | 19.92 |
Consumption and losses |  | (1.34 | ) |  | (1.23 | ) |  | (1.33 | )
Products available for sale |  | 23.55 |  |  | 21.33 |  |  | 18.59 |
Purchases of refined products and change in inventories |  | 3.35 |  |  | 4.42 |  |  | 5.38 |
Products transferred to operations outside Italy |  | (2.36 | ) |  | (1.85 | ) |  | (0.64 | )
Consumption for power generation |  | (0.75 | ) |  | (0.55 | ) |  | (0.57 | )
Sales of products |  | 23.79 |  |  | 23.35 |  |  | 22.76 |
OUTSIDE ITALY |  |  |  |  |  |  |  |  |
Refinery throughputs on own account |  | 5.12 |  |  | 4.82 |  |  | 5.11 |
Consumption and losses |  | (0.23 | ) |  | (0.22 | ) |  | (0.21 | )
Products available for sale |  | 4.89 |  |  | 4.60 |  |  | 4.90 |
Purchases of finished products and change in inventories |  | 17.29 |  |  | 13.69 |  |  | 16.11 |
Products transferred from Italian operations |  | 2.36 |  |  | 1.85 |  |  | 0.64 |
Sales of products |  | 24.54 |  |  | 20.14 |  |  | 21.65 |
Refinery throughputs on own account |  | 30.01 |  |  | 27.38 |  |  | 25.03 |
of which: refinery throughputs of equity crude on own account |  | 6.39 |  |  | 5.93 |  |  | 5.81 |
Total sales of refined products |  | 48.33 |  |  | 43.49 |  |  | 44.41 |
Crude oil sales |  | 36.56 |  |  | 43.96 |  |  | 49.99 |
TOTAL SALES |  | 84.89 |  |  | 87.45 |  |  | 94.39 |

In 2014, refining throughputs were 25.03 mmtonnes, down by 2.35 mmtonnes, or 8.6% from 2013. In Italy, processed volumes decreased by 11.7% from 2013, mainly due to the unfavorable refinery scenario registered in the first part of the year, as well as the shutdown of the Gela and Venice refineries. A slight increase was registered in processed volumes at Milazzo plant (up 3%). Outside Italy, Eni’s refining throughputs (5.11 mmtonnes) increased by 6% (up approximately 300 ktonnes) mainly in the Czech Republic at Kralupy refinery, which in 2013 was object of to the planned shutdown.

Total throughputs in wholly-owned refineries were 16.24 mmtonnes, down by 2.75 mmtonnes (down 14.5%) from 2013 determining a refinery utilization rate of 78%.

Approximately 25.2% of processed crude was supplied by Eni’s Exploration & Production segment, representing a 1.6 percentage point increase from 2013 (23.7%).

> Logistics

Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 18 directly managed storage sites and a network of petroleum product pipelines for products sale and storage of LPG and crude. Eni’s logistic model is based on a hub structure covering five main areas. These hubs monitor and centralize product flows in order to lower collection and delivery costs. Eni holds five partnerships with major Italian operators located in the Vado Ligure-Genoa (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) sites, they reduce logistic costs, and increase efficiency.

Eni operates in oil and refined products transport: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through an owned pipeline network extending approximately 1,462-kilometer long.

Secondary distribution to retail and wholesale markets is carried out through outsourcing to little tanker owners and represent leading market positions in their own geographical area.

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> Marketing

Eni markets a wide range of refined petroleum products, primarily in Italy, through an extensive 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 |  | 2012 |  | 2013 |  | 2014

|  | (mmtonnes)

Italy |  |  |  |  |  |
Retail |  | 7.83 |  | 6.64 |  | 6.14
Wholesale |  | 8.62 |  | 8.37 |  | 7.57
|  | 16.45 |  | 15.01 |  | 13.71
Petrochemicals |  | 1.26 |  | 1.32 |  | 0.97
Other sales |  | 6.08 |  | 7.01 |  | 8.08
|  | 23.79 |  | 23.34 |  | 22.76
Outside Italy |  |  |  |  |  |
Retail |  | 3.04 |  | 3.05 |  | 3.07
Wholesale |  | 4.38 |  | 4.66 |  | 5.03
|  | 7.42 |  | 7.71 |  | 8.10
Other sales |  | 17.12 |  | 12.44 |  | 13.55
|  | 24.54 |  | 20.15 |  | 21.65
TOTAL SALES |  | 48.33 |  | 43.49 |  | 44.41

In 2014, sales volumes of refined products (44.41 mmtonnes) increased by 0.92 mmtonnes from 2013, up 2.1%, due mainly to higher volumes sold to oil companies and traders outside Italy.

> Retail sales in Italy

In 2014, retail sales in Italy of 6.14 mmtonnes decreased by approximately 0.50 mmtonnes, or by 7.5% compared to 2013, driven by lower consumption of all products amidst weak demand and competitive pressures. Average gasoline and gasoil throughput (1,534 kliters) decreased by approximately 124 kliters from 2013. Eni’s retail market share for 2013 was 25.5%, down by two percentage points from 2013.

At December 31, 2014, Eni’s retail network in Italy consisted of 4,592 service stations, 170 stations less compared to December 31, 2013 (4,762 service stations), resulting from the negative balance of the closing of service stations with low throughput (97 units), lack of renewal of two motorway concessions and a negative balance of acquisitions/releases of lease concessions (71 units).

> Retail sales in the rest of Europe

Eni’s strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany and Austria leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities and to divest from the marginal area with weak growth prospects.

In 2014, retail sales of refined products marketed in the rest of Europe (3.07 mmtonnes) were essentially stable (up 0.7%). Higher volumes marketed in Germany and Austria were offset by lower sales in France and in the Czech Republic.

At December 31, 2014, Eni’s retail network in the rest of Europe consisted of 1,628 service stations, with an increase of 4 units from December 31, 2013 (1,624 service stations). The network evolution was as follows: (i) the closing of 15 low throughput service stations mainly in France; (ii) the positive balance of acquisitions/releases of lease concessions (10 units), in particular in Germany and Switzerland; (iii) the purchase of 8 service stations, mainly in Germany; and (iv) the opening of 1 new outlet. Average throughput (2,258 kliters) decreased by 64 kliters compared to a year ago (2,322 kliters in 2013).

In May 2014, Eni signed a preliminary agreement for the divestment of the marketing activities of fuels located in Czech Republic, Slovakia and Romania, the closing of the transaction is still pending.

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The key markets of Eni’s presence are: Austria with a 12.1% market share, Hungary with 11.9%, Czech Republic with 8.9%, Slovakia with 9.5%, Switzerland with 7.3% and Germany with a 3.2% on national base. These market shares were calculated by Eni based on public data on national consumption and Eni’s sales volumes. Non-oil activities in the rest of Europe are present in 944 service stations (Eni owned network), of which 323 are in Germany, 184 in Austria and 94 in France, with a virtually complete of owned stations.

> Other businesses

> Wholesale

Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and 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. Along with traditional products provided with the Eni’s high quality standards, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. 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 2014, sales volumes on wholesale markets in Italy (7.57 mmtonnes) declined by approximately 800 ktonnes, down 9.6%, mainly due to lower sales of all products, in particular gasoil for heating reflecting the mild climate registered in the period, as well as fuel oil and bunkering due to declining demand. Average market share in 2014 was 26.7% (28.8% in 2013). Supplies to the petrochemical industry (0.97 mmtonnes) decreased from 2013 (down 354 ktonnes) due to lower feedstock supplies. Wholesale sales in the Rest of Europe of approximately 4.60 mmtonnes increased by 8.7% from 2013 due to increased sales in Czech Republic, Hungary and France. Other sales (21.63 mmtonnes) increased by 2.18 mmtonnes, or 11.2%, mainly due to higher sales to the other oil companies.

Eni also markets jet fuel directly at 51 airports, of which 30 are in Italy. In 2014, these sales amounted to 2.1 mmtonnes (of which 1.6 mmtonnes are in Italy). Eni is also active in the international market of bunkering, marketing marine fuel, mainly in 115 ports, of which 65 are in Italy. In 2014, marine fuel sales were 1.38 mmtonnes (1.26 mmtonnes in Italy).

> LPG

In Italy, Eni is leader in LPG production, marketing and sale with 590 ktonnes sold for heating and automotive use equal to a 20% market share. An additional 289 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. LPG activities in Italy are supported by direct production, availability from 5 bottling plants and 1 owned storage site, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna.

Outside Italy, LPG sales in 2014 amounted to 549 ktonnes of which 410 ktonnes in Ecuador where LPG market share is around 37.9%.

> Lubricants

Eni operates six (owned and co-owned) blending plants, in Italy, Europe, North and South America and the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of 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. Base oils are manufactured primarily at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero. In 2014, retail and wholesale sales in Italy amounted to 90 ktonnes with a 23.4% market share. Eni also sold approximately 3 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 100 ktonnes, of these about 92% were registered in Europe.

> Oxygenates

Eni, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 1 mmtonnes/y of oxygenates, mainly ethers (approximately 2.9% of world demand) and methanol (approximately 0.1% of world demand). About 81% of

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oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and the remaining 19% is bought and resold. Eni distributes bio-ETBE in the Italian market in compliance with the new legislation indicating minimum content of bio-fuels. Bio-ETBE like MTBE is an octane booster gained a relevant position in the formulation of gasoline in European Union, because it is produced from ethanol from agricultural crops and qualified as bio-component in European directive on bio-fuels. In Italy from January 2014, the mandatory minimum content of bio-components in the fuels has been kept constant to 4.5 and Eni covered this bio-regulation request through the blending of Bio ETBE and bio-diesel of 1st and 2nd generation (FAME and Green Diesel from Porto Marghera site).

> Capital expenditures

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

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. We face structural headwinds in our legacy basic petrochemical and plastic 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".

Against this backdrop, our priority is the economic and financial sustainability of our Chemical segment in the medium and long term. The break-even at operating profit and operating cash flow is expected to be achieved starting from 2016. This target will be driven by performing and completing the following strategic guidelines: (i) downsizing our installed capacity in commoditized and loss-making businesses through the reconversions of inefficient units and plant shutdown and/or divestment and consolidation of the other businesses; (ii) refocusing our chemical portfolio on high value-added productions (i.e. specialties) also through the development of green chemistry; and (iii) upgrading of our production platform by means of the internationalization of the business to serve global clients and markets featured by high demand growth, also through strategic alliances with industrial partners. This strategy achieved significant results in 2014 thanks to the restructuring of our loss-making sites in Sardinia through the conversion of the Porto Torres plant into a green chemistry unit and the divestment of our Sarroch business line to the adjacent refinery operated by a third party. We also signed a framework agreement with relevant Italian Authorities and stakeholders for the shutdown of the Porto Marghera cracker and its reconversion into a business for the production of green specialties. We believe that going forward these actions will reduce our breakeven in this segment.

In 2014, sales of chemical products amounted to 3,463 ktonnes, down by 322 ktonnes, or 8.5% from 2013, mainly due to the weakness of demand. The steepest declines were registered in olefins (down by 19%) and aromatics (down by 14%) following the shutdown of cracking and aromatics site of Porto Marghera occurred in the end of February. Polymers sales were barely unchanged from 2013.

Chemical production amounted to 5,283 ktonnes, with a decrease of 534 ktonnes, or 9.2% from 2013. This was mainly due to a decrease in intermediates (down 14%) due to the Porto Marghera cracker shutdown and elastomers (down 8%) due to lower demand. Lower decreases were registered in styrene (down by 4%). These reductions were partly offset by higher production of polyethylene (up by 2%) due to a partial recovery in sales volumes from the depressed levels registered in 2013. The main decreases in production were registered at Porto Marghera (down by 85%) due to the standstill of cracking and aromatics lines from the end of February 2014 until the end of the year and Sarroch (down by 23%) due to the lower production as a result of the challenging competitive environment. Priolo and Dunkerque crackers registered an increase in production, since they were fully operating to compensate the lower production at Porto Marghera site. Outside Italy, the rubber and latex plant of Hythe was definitely closed at the end of March. Nominal capacity of plants declined from the previous year due to rationalization measures, with an average plant utilization rate calculated on nominal capacity of 71.3% (65.3% in 2013).

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

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (ktonnes)

Intermediates |  | 3,595 |  |  | 3,462 |  |  | 2,972 |
Polymers |  | 2,495 |  |  | 2,355 |  |  | 2,311 |
Total production |  | 6,090 |  |  | 5,817 |  |  | 5,283 |
Consumption and losses |  | (2,545 | ) |  | (2,394 | ) |  | (2,292 | )
Purchases and change in inventories |  | 408 |  |  | 362 |  |  | 472 |
|  | 3,953 |  |  | 3,785 |  |  | 3,463 |

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

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Intermediates |  | 3,050 |  | 2,709 |  | 2,310
Polymers |  | 3,188 |  | 2,933 |  | 2,800
Other revenues |  | 180 |  | 217 |  | 174
Total revenues |  | 6,418 |  | 5,859 |  | 5,284

> Intermediates

Intermediates revenues (euro 2,310 million) decreased by euro 399 million from 2013 (down by 14.7%) reflecting the shutdown of Porto Marghera cracker, with an effect on sold volumes of aromatics and derivatives. Lower butadiene sales (down by 31%) and xylene (down by 34%) were attributable to market weakness and production overcapacity in Europe. Average unit prices decreased by 2%, with aromatics price lowered by 7% (in particular xylene prices decreased by 15% due to demand weakness), olefins prices by 1% due to lower ethylene and butadiene prices, almost completely offset by higher prices of propylene.

Intermediates production (2,972 ktonnes) registered a decrease from the last year (down by 490 ktonnes or 14.2%) due to reductions in olefins (down 11%) and in aromatics (down 31%) driven by the shutdown of Porto Marghera plant from February until the end of the year, as well as lower productions in Sarroch plant. In addition, derivatives productions decreased by 10% due to disruptions and maintenance standstills registered in the second part of the year.

> Polymers

Polymers revenues (euro 2,800 million) decreased by euro 133 million, or by 4.5% from 2013 due to average unit prices and volumes of elastomers decreasing by 8% and 5%, respectively, driven by continuing weakness of automotive sectored demand and low price of Asian producers. These negatives were further exacerbated by the decrease of average styrenics prices (down 4%) and sold volumes down by 4%, also due to new import flows coming from North Africa. Polyethylene prices were barely unchanged.

Polymers production (2,311 ktonnes) decreased by 1.9% from 2013, mainly in elastomers segment (down 8%), due to the definitive closing of Hythe with lower production of lattices and SBR rubbers, and of BR rubbers due to declining demand. Styrene productions decreased by 4% with lower volumes of styrol (down by 5%) due to the planned shutdown of the second half of 2014 and compact polystyrene (down by 6%), partly offset by higher productions of ABS/San (up by 11%) for short-term production rescheduling. Polyethylene sales increased by 2%, due to higher production at Brindisi site (HDPE up by 5%) due to the planned standstill of olefin production lines, and Eva in the Oberhausen site (up by 53%).

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> Capital expenditures

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

Engineering & Construction

Eni engages in engineering, construction and drilling both offshore and onshore for the oil&gas industry through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 42.91%), and Saipem’s controlled entities. We believe that Saipem is well positioned in the market for services to the oil industry, particularly in executing large, complex EPC contracts for the construction of offshore and onshore facilities and systems to develop hydrocarbons reserves, as well as LNG, refining and petrochemical plants, pipeline laying and offshore and onshore drilling services. 2014 was characterized by the return to profitability of the Engineering & Construction segment with a the reduction of net debt and significant results in terms of new orders. The Company has a large and diversified order backlog with good exposure to ultra-deep water projects, laying of trunk line in extreme conditions, large and complex onshore projects, where we retain competitive advantages in terms of availability of technologically advanced vessels and contractor competences.

Orders acquired amounted to euro 17,971 million as of December 31, 2014 (euro 10,062 million as of December 31, 2013), of these projects to be carried out outside Italy represented 97%, while orders from Eni companies amounted to 8% of the total. Order backlog amounted to euro 22,147 million at December 31, 2014 (euro 17,065 million at December 31, 2013), of these projects to be carried out outside Italy represented 97%, while orders from Eni companies amounted to 11% of the total.

|  | 2012 |  | 2013 |  | 2014

Orders acquired |  | (euro million) |  | 13,391 |  | 10,062 |  | 17,971
Offshore Engineering & Construction |  |  |  | 7,477 |  | 5,581 |  | 10,043
Onshore Engineering & Construction |  |  |  | 3,972 |  | 2,193 |  | 6,354
Offshore Drilling |  |  |  | 1,025 |  | 1,401 |  | 722
Onshore Drilling |  |  |  | 917 |  | 887 |  | 852
Originated by Eni companies |  | (%) |  | 5 |  | 15 |  | 8
To be carried out outside Italy |  | (%) |  | 96 |  | 95 |  | 97
Order backlog and breakdown by business |  | (euro million) |  | 19,739 |  | 17,065 |  | 22,147
Offshore Engineering & Construction |  |  |  | 8,721 |  | 8,320 |  | 11,161
Onshore Engineering & Construction |  |  |  | 6,701 |  | 4,114 |  | 6,703
Offshore Drilling |  |  |  | 3,238 |  | 3,390 |  | 2,920
Onshore Drilling |  |  |  | 1,079 |  | 1,241 |  | 1,363
Originated by Eni companies |  | (%) |  | 13 |  | 13 |  | 11
To be carried out outside Italy |  | (%) |  | 91 |  | 95 |  | 97

> Offshore Engineering & Construction

Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPCI oriented business model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies (NOCs). Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage, integrating in its own business model the direct management of construction process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet.

Saipem’s offshore construction fleet is made up 34 vessels and a large number of robotized vehicles able to perform advanced sub-sea operations. Its major vessels are: (i) the Saipem 7000 semi-submersible dynamically positioned vessel, with 14 ktonnes of lift capacity, capable to lay pipelines using the J-lay technique to the maximum depth of 3,000 meters; (ii) the Field Development Ship for the development of underwater fields in dynamic positioning, provided with cranes lifting up to 600 tonnes and a system for J-lay pipe laying to a depth of 2,000 meters; (iii) the Castoro 6 semi-submersible vessel, capable of laying pipes in waters up to 1,000 meters deep; (iv) the Saipem 3000 self-propelled dynamically positioned derrick crane ship, capable of laying flexible pipes and umbilicals in deep waters and of lifting structures weighing up to 2,200 tonnes; and (v) the Semac semi-submersible vessel used for large

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diameter underwater pipe laying. The fleet also includes remotely operated vehicles (ROV), highly sophisticated and advanced underwater robots capable of performing complex interventions in deep waters.

The most significant orders awarded in 2014 in Offshore Engineering & Construction were: (i) an EPCI contract on behalf of Total concerning conversion of the two FPSO units, with an oil capacity of 115,000 BBL/d and a storage capacity of 1.7 mmBOE. The two converted FPSO units will be utilized to support the development of Kaombo field, located in Block 32 offshore Angola; (ii) a transportation and installation contract on behalf of BP for the Phase 2 of the Shah Deniz field development, offshore Azerbaijan; and (iii) an EPCI contract on behalf of Pemex, in Mexico, for the development of the Lakach field. The scope of work of the contract involves the engineering, procurement, construction and installation of the system connecting the offshore field with the onshore gas conditioning plant.

> Onshore Engineering & Construction

In the Onshore Engineering & Construction business, Saipem is one of the largest operators on turnkey contract base at a worldwide level in the oil&gas segment Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness through the technological excellence of its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the medium term, underpinning upward trends in the oil service market, Saipem will be focused on taking advantage of the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of Middle-East, Caspian Sea, Northern and Western Africa and Russia.

The most significant orders awarded in 2014 in Onshore Engineering & Construction were: (i) contracts on behalf of Saudi Aramco relating to the Integrated Gasification Combined Cycle project (Jazan) as a part of the activities related to the construction of the largest power plant in the world to be located near the namesake city of Jizan. Furthermore, Saudi Aramco awarded to Saipem an EPC contract for the Loops 4 & 5 of the Shedgum-Yanbu’ Gas Pipeline; (ii) a contract on behalf of Saudi Aramco relating to the expansion of the onshore production centers at the Khurais, Mazajili and Abu Jifan fields in Saudi Arabia. The construction of new facilities will allow to process additional 500,000 BBL/d from the above mentioned fields; and (iii) a contract in the Caspian Region regarding engineering, fabrication and pre-commissioning activities, as well as the load-out of pipe racks.

> Offshore Drilling

Saipem is the only engineering and construction contractor that also provides also offshore and onshore drilling services to oil companies. In the Offshore Drilling segment Saipem mainly operates in West Africa, the North Sea, Mediterranean Sea and the Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum depth of 9,200 meters. In parallel, investments are ongoing to renew and to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients’ needs and purchase of support equipment).

Saipem’s Offshore Drilling fleet consists of 17 vessels fully equipped for its primary operations and some drilling plants installed on board of fixed offshore platforms. Its major vessels are: the Saipem 12000 and Saipem 10000, designed to explore and develop hydrocarbon reservoirs operating in excess of 3,600 and 3,000-meter water depth, respectively in full dynamic positioning. Other relevant vessels are Scarabeo 8 and 9, sixth generation semi-submersible rigs able to operate at depths of 3,000 and 3,600-meter water depth, respectively. Average utilization of drilling vessels in 2014 stood at 100% (100% in 2013).

The most significant orders awarded in 2014 in Offshore Drilling were: (i) a contract for the lease of the semi-submersible rig Scarabeo 7, for the drilling of twelve wells, to be carried out by the first quarter of 2017, for Eni Muara Bakau BV in Indonesia; (ii) a one-year extension of the contract on behalf of Saudi Aramco for the lease of the jack-up Perro Negro 7, for operations in Saudi Arabia; and (iii) a two-year extension of the contract on behalf of NDC (National Drilling Company) for the lease of the jack-up Perro Negro 2 for operations in the Persian Gulf starting in January 2015.

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> Onshore Drilling

Saipem operates in this area as a main contractor for the major international oil companies and NOCs executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In this area Saipem can leverage its knowledge of the market, long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments.

Average utilization of rigs in 2014 stood at 96.5% (96.0% in 2013). The 98 rigs (in addition to 2 rigs under completion) owned by Saipem at year end were located as follows: 28 in Venezuela, 19 in Peru, 25 in Saudi Arabia, 7 in Colombia, 4 in Kazakhstan, 4 in Bolivia, 3 in Ecuador, 1 in Chile, 1 in Congo, 2 in Italy, 1 in Ukraine, 1 in Tunisia, 1 in Turkmenistan and 1 in Mauritania and Saipem also used rigs owned by third parties (5 in Peru, 1 in Chile and 1 in Congo).

The most significant orders awarded in 2014 in Onshore Drilling were: (i) for various clients in Latin America (mainly in Venezuela and Peru), new contracts for the lease of 31 rigs; and (ii) a one-year extension of the charter for operations in Saudi Arabia, on behalf of Saudi Aramco, for three rigs already operating in the Country plus the award of a five year contract for a further three rigs.

> Capital expenditures

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

Corporate and Other activities

These activities include the following businesses:

• |  | the "Other activities" segment comprises results of operations of Eni’s subsidiary 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, legal affairs, international affairs and corporate research and development functions. Through Eni’s subsidiaries Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance Ltd, 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.

> 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.

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Research and development

Technology research and development (R&D) and continuous innovation are key factors in successfully implementing Eni’s business strategies as they support mid and long-term competitive 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 hydrocarbon resources, with increasing role of frontier oil&gas basins;
• |  | need of a more efficient exploitation of conventional fossil sources and of viable solutions for energy production from renewable and lower greenhouse gas emission sources; 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:

• |  | strengthening technological leadership in exploration by continuously developing proprietary tools;
• |  | 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;
• |  | increasing capability to exploit frontier regions (water deeper than 3,000 meters, as well as Arctic regions);
• |  | defining and pursuing new research activities aimed at monetizing stranded and low value gas;
• |  | further development of Eni’s Green Refinery process with innovative solution for the conversion of conventional refineries into bio-refineries, and of formulations of innovative fuels, lubricants and bitumen based on 2nd generation and waste biomass;
• |  | commitment to the transfer to pilot and industrial scale of relevant results obtained from research and development with particular care in the downstream and renewable business;
• |  | development of innovative processes for the production of high performance polymers, elastomers and other chemicals form renewable feed stocks; and
• |  | development of innovative environmental technologies for in situ monitoring and remediation.

In 2014, Eni filed 84 patent applications (59 in 2013), 49 of these coming from Eni, 14 from Versalis, 20 from Saipem and 1 from Syndial.

In 2014, Eni’s overall expenditure in R&D amounted to euro 186 million which were almost entirely expensed as incurred (euro 197 million in 2013 and euro 211 million in 2012).

At December 31, 2014, a total of 961 persons were employed in research and development activities.

> Exploration & Production

• Clean Sea. The robotic proprietary technology is based on the use of AUVs (Autonomous Underwater Vehicles) able to move around installations around without physical connection with the surface minimal logistical support and in harsh offshore scenarios (e.g. Arctic). During 2014, the first two field campaigns were carried out: a demonstration of Clean Sea technology capability in monitoring the trunk line of Kashagan and an environmental monitoring in the Strait of Sicily near Perla and Prezioso platforms and along the sea-line to the Gela plant.

• e-cube™ (Eni Containment of Underwater Blow Out Events). The proprietary device is designed to contain and capture spills caused by any subsea blowout when a capping system is not a viable solution. A prototype was successfully tested at sea in 2014 with a simulation of a blowout with water and gas, confirming its ability to collect and convey to the surface the fluids leaving a subsea well.

• 3D virtual and augmented reality display. This technology allows to conduct simulations on real plants both on stream or still in phase of construction, in order to perform training of plant operators and increasing safety and improving efficiency of operations. In 2014, a new 3D room was set-up and commissioned in the R&D laboratories in San Donato Milanese.

• e-dva™ (Eni Depth Velocity Analysis). The discoveries of Nené Marine and Minsala was supported by the application of proprietary technologies for seismic imaging e-dva™ which have been running in the High Performance Computing system in the Green Data Center in Ferrera Erbognone since 2014. These technologies improved the image of the exploratory targets laying below a thick layer of salt.

• e-vpms™ (Eni Vibroacoustic Pipeline Monitoring System). The proprietary technology allows a remote and continuous detection of third-party intrusions and leaks in fluid-filled pipelines. In 2014, the technology successfully installed in 2013 in Akri-Kwale pipe (17 km crossing the Niger River), was fine-tuned and handed over to NAOC.

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• Chemical EOR. The polymer EOR pilot plant with injection capacity of 1,000 BBL/d in Aghar field (Egypt Western Desert) was started. The pilot, operating throughout 2014 and 2015, has to confirm the increase in the recovery factor in line with the pilot sector area simulations.

> Refining & Marketing

• Green Refinery. In the summer of 2014 the Green Refinery project was completed converting the Venice Refinery into a bio-refinery, which is the world’s first case. A pillar of this project was the Ecofining technology, developed by Eni in partnership with UOP (Honeywell).

• Green diesel. In 2014, diesel fuel with extremely high concentration (50%) of bio-mass derived components (Green Diesel produced by the Eni/UOP’s Ecofining process) was produced for Italian Navy and NATO ships. Different concentrations of Green Diesel were also successfully mixed in regular and top quality diesel fuels.

• e-vpms™ (Eni Vibroacoustic Pipeline Monitoring System; see Exploration & Production for the description of the technology). In 2014, the technology successfully installed in the 113-km long Gaeta-Pomezia pipe, allowed to locate in real time the numerous fraudulent attacks which took place, greatly reducing the fuel spills.

> Versalis

• High value chemicals from vegetable oils. In February 2014, Versalis signed a partnership with Elevance Renewable Sciences Inc aimed at the development and industrialization of an innovative technology for the production of chemicals from plant oils. This joint venture is part of the project to upgrade the Versalis Porto Marghera plant into a world-scale industrial plant which will integrate bio feedstocks and fossil ones into Versalis innovative products, namely high added value such as: personal care, detergents and bio-lubricants.

• Bio-oilfield chemicals. Versalis is developing new green products for oilfield operations and is strongly committed to develop and commercialize additives for high performance drilling fluids from renewable sources. In this scenario Versalis signed a partnership with Solazyme – a company producing oil from renewable sources and bioproducts – for developing and commercializing green additives globally.

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 Ltd, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market.

Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni uses insurance companies who it believes are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.1 billion for offshore events and $1.5 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 billion for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment and FPSOs used by the Exploration & Production segment for developing offshore fields; $500 million for time charters.

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

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could have a material impact on our results, liquidity prospects, share price and reputation. See "Item 3 – Risk factors – Risk associated with the exploration & 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 and gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, these laws and regulations require the 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, limit or prohibit drilling activities on certain protected areas, provide for measures to be taken to protect health and safety at workplace and health of communities that could be affected by the Company’s activities, and impose criminal or civil liabilities for pollution resulting from oil, natural gas, refining and petrochemical operations. 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 greenhouse gases (GHG) in the atmosphere and cope with climate change and water quality of discharges, as well as availability.

A brief description of major environmental, health and safety laws impacting Eni’s activities located in Italy and European Union is outlined below.

> Italy

The majority of Italian environmental legislation is contained in the Environmental Code approved by Legislative Decree No. 152 of April 3, 2006 (as amended) (Environmental Code). The Environmental Code has been subject to a number of amendments in the last year, including in relation to the extraction of fossil fuels and waste provisions. The Environmental Code sets up the basic rules for environmental protection regulating: the Environmental Impact Assessment (EIAs), the Integrated Prevention and Pollution Control (IPPC), procedures for Strategic Environment Assessment, soil and water protection, air pollution and reduction of emissions, waste management and remediation of contaminated sites, environmental liability and sustainable development. The Environmental Code requires that reclamation and remediation activities be performed on the basis of a site-specific risk-based approach to determine objectives of reclamation and remediation projects, cost-effective analysis to evaluate remediation solutions, and criteria for waste classification. Moreover the Law No. 116 of August 11, 2014 "Conversion in law, with modifications of Legislative Decree No. 91 of June 24, 2014" (so-called Decreto Competitività) was published in the Official Gazette of the Italian Republic (Official Gazette No. 192 dated August 20, 2014 - Ordinary Appendix No. 72). The law introduces numerous news in the environmental protection (in particular in the air quality, new standards for marine waters and waste) and energy efficiency.

Legislative Decree No. 231 of June 8, 2001, as amended by Legislative Decree No. 121 of July 7, 2011, which provides for monetary sanctions for legal entities in cases of criminal offences concerning the environment. This decree introduced into Italian law the liability of legal entities in relation to the crimes committed by employees against the environment.

On April 11, 2014, the Decree of March 3, 2014, No. 46 implementing Industrial Emission Directive (IED) entered into force. The Decree updates permit conditions, control system and environmental sanctions for the industrial activities with a major pollution potential, including, for example, chemical installations, smelting operations and power generation facilities. For these activities, an operator must obtain an IPPC permit.

In November 2014, the Ministerial Decree dated November 13, 2014, No. 272 of the Minister for the Environment entered into force. The Decree defines the minimum requirements for the baseline report which must be presented by the operator in the case the given activity involves the use, production or release of relevant hazardous substances and including the possibility of soil and groundwater contamination at the site of the installation.

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On July 19, 2014, with the publication of Decree No. 102/2014, Italy implemented the EU Directive No. 2012/27/EU on energy efficiency. This Decree defines a set of measures for promoting and improvement energy efficiency to follow the Italian national target of energy savings. Moreover, the Decree identifies some management tools, including the Energy Audit and the Energy Management Systems. The air emissions regime is set out in Part V of the Environmental Code. Moreover, the Decree No. 155/2010 adopted in the Italian law the European prescriptions on ambient air quality, established by the Directive No. 2008/50/EC. Its main innovation is the definition of monitoring criteria and emission limits for fine particulate substances (PM 2.5), to be achieved by January 1, 2015. On August 27, 2014, Legislative Decree No. 112 of July 16, 2014 implementing Directive No. 2012/33/CE on emissions from maritime transport entered into force. The Directive sets the new limits for the sulphur content in the maritime fuels.

The Law Decree No. 133 issued September 12, 2014 introduces some important changes in the procedure for site remediation. This procedure could be simplified, following the Law Decree No. 91/2014, that introduces a new Article 242-bis in the Environmental Code, if the operator chooses to reduce the soil contamination below the Contamination Threshold Concentration (CSC).

As an EU member state, Italy is taking part in the EU Emission Trading Scheme (ETS) and is in the third phase of the compliance system. Phase III of the ETS commenced in 2013 and will operate until 2020. During this period approximately half of Phase III EU Allowances (EUAs) will be sold through regular auctions on exchanges such as ICE Futures Europe, in accordance with Commission Regulation (EU) No. 1031/2010 (the "Auctioning Regulation"). Italy has regulated the Emission Trading System by Legislative Decree No. 30 of March 13, 2013, transposing requirements of Directive No. 2009/29/EC (amending Directive No. 2003/87/EC to extend the Community trading system of CO2 emission). The cited Decree replaces the former Decree No. 216/2006.

The Decree of the Ministry of the Development No. 116 on refunding allowances to the plants of new entrants of the II Phase of EU-ETS was published in the Official Gazette of the Italian Republic on May 21, 2014.

The legislative framework on SISTRI, an automated tracking system of hazardous waste, was updated by Ministerial Decree April 24, 2014, which provided new rules about intermodal transport and communication with the administration service of SISTRI. While SISTRI obligation are currently mandatory, the sanctions, according to Decree No. 192/2014 and Law No. 11/2015, shall be applied only from January 1, 2016, except the ones for obligations about signing up and payment of annual contributions, which enter in force by April 1, 2015. Legislative Decree No. 81/2008 concerned the protection of health and safety in the workplace and was designed to regulate the work environments, equipments and individual protection devices, physical 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.

Italian local authorities are appealing more often to Health Impact Assessment (HIA) and are integrating this procedure with Environmental Impact Assessment and Strategic Impact Assessment (SIA). During 2012, a strong correlation has been observed between health issues and environmental aspects. Various HIA, SIA and EIA methodologies are being developed as a unique regulation (e.g. "Cervellera Law" in Puglia Region). In August 2013, has been published in the official journal, April 24, 2013 Decree establishing the methodological criteria for preparing the reports of health damage assessment (VDS) in implementation of Decree ILVA (Law Decree No. 207/2012 converted Law No. 231/2012). Eni is involved in an internal multidisciplinary project on health and environmental assessment of plants impacts:

• |  | clear policies;
• |  | an ethical code;
• |  | endorsement of international conventions and principles;
• |  | guidelines and procedures; and
• |  | sharing of knowledge.

> European Union

On June 21, 2012, the Commission adopted two Regulations on monitoring and reporting of GHG emissions and on verification and accreditation of verifiers under the EU Emissions Trading System. Both Regulations form part of the set of implementing rules for the third trading period of the EU ETS and entered in force in January 2013.

On July 20, 2012, Regulation EU No. 530/2012 on the accelerated phasing-in of double-hull or equivalent design requirements for single-hull oil tankers entered in force. The new Regulation prohibits the transport to or from EU ports of heavy grades of oil in single-hull oil tankers as decided by the Marpol Convention 73/78.

On April 14, 2014, a new Environmental Impact Assessment Directive 2014/52/EU (EIA Directive) entered into force. The EIA Directive should simplify the rules for assessing the potential effects of projects on the environment and

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boarders scope of the EIA covering new issues such as climate change, biodiversity, resource efficiency and risks prevention.

On May 6, 2014, the Commission published on the Official Journal C 136 "Guidance concerning baseline reports under Article 22(2) of Directive 2010/75/EU on industrial emissions". The baseline report contains information on the contamination conditions of the soil and the groundwater. The document represents the key tool for a comparison with the state of contamination upon definitive cessation of activities.

On July 31, 2014, the European Commission Regulation No. 749/2014 of June 30, 2014 entered into force. The regulation decides information on structure, format, submission processes and review of information reported by Member States pursuant to Regulation (EU) No. 525/2013 of the European Parliament and of the Council.

In October 2014, the European Commission has adopted a list of sectors and subsectors which are deemed to be exposed to a significant risk of carbon leakage, for the period 2015 to 2019. The decision, Regulation No. 746/2014 has entered into force the January 1, 2015. Industry sectors and sub-sectors deemed to be exposed to a significant risk of "carbon leakage" receive a higher share of free allowances because they face competition from industries in third countries which are not subject to comparable greenhouse gas emissions restrictions.

On July 23, 2014, the European Commission published the Communication COM(2014)520 "Energy Efficiency and its contribution to energy security and the 2030 Framework for climate and energy policy". In its communication, the Commission assesses whether the EU is on track to reach its 2020 target to increase energy efficiency by 20% and proposes a new energy saving target of 30% by 2030.

By June 1, 2015, the Decision 2014/955/EU shall substitute the Decision 2000/532/CE and the Regulation 1357/2014/EU shall set new rules for the classification of hazardous waste, rewriting the annex III of the European Directive on Wastes (2008/98/EC). The Regulation 1357/2014/EU aims to get the classification of wastes closer to the classification of hazardous substances (CLP regulation), requiring significant efforts in order to assess (and review, if necessary) the classification of the wastes which are currently produced in the industrial processes.

The original F-gas Regulation (Regulation No. 842/2006) was replaced by a new Regulation (No. 517/2014) adopted in 2014 which applies from January 1, 2015. A new Regulation strengthens the existing measures and introduces a number of far-reaching changes. By 2030, it will cut 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 greenhouse gas emissions by 80-95% of 1990 levels by 2050.

On January 22, 2014, following the stakeholders’ responses to the public consultation on Green Paper, the European Commission adopted the White Paper on a policy framework for climate and energy "COM(2014) 15" in the period from 2020 to 2030. The current proposal contains a GHG domestic reduction target of -40% versus 1990 level, an objective of increasing the share of renewable energy to at least 27% of the EU’s energy consumption by 2030 and qualitative targets on energy efficiency. In the same package the European Commission proposes to establish (beginning in 2021) a so-called Market Stability Reserve "COM(2014) 20" on the Emission Trading Scheme, to address the surplus that has built up in recent years.

On January 25, 2014, in the context of Emission Trading Scheme, Regulation No. 176/2014 was adopted, which postpones the auctioning of 900 million allowances until 2019-2020. In 2014, the total European auction volume was reduced by 400 million allowances, in 2015 by 300 million, and in 2016 by 200 million. This short-term measure is aimed at rebalancing the supply and the demand of the European carbon market. This measure was made possible after the amendment of the ETS Directive approved in December 2013 (Decision No. 1359/2013/EU), which clarifies that the timing of allowances auctions may be changed to ensure the orderly functioning of the carbon market.

The Directive is a game-changer for energy distributors or all retail energy sales companies, which are now required to achieve 1.5% energy savings every year among their final clients. The Directive is in the process of being enacted in Italy.

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

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band of a substance and the classification of a substance; next and last deadline is 2018. Eni recognizes the importance of the Regulation CE 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 that regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspects 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.

On November 28, 2014, the decision of the European Commission establishing new Best Available Techniques (BAT) conclusions for the refining of mineral oil and gas the gas was published in the Official Journal of the European Union No. 307. The BAT conclusions were revised accordingly to Article 75 of the Industrial Emissions Directive (IED) 2010/75/EU which regulates emissions to air, water and soil of about 50,000 industrial installations across the EU. BAT conclusions are the technical basis for national authorities in EU countries to set permit conditions for producers in the relevant field, as stipulated by the IED Directive. Best available techniques conclusions aim at achieving a high level of protection of the environment under economically and technically viable conditions. BAT cover both the technology used and the way in which the installation is designed, built, maintained, operated and decommissioned. A specific look into the emission levels and other environmental performance of several techniques is also included. Compared to the previous BREF adopted in 2003, the BAT conclusions include emission levels of various individual metal compounds to water; set stricter levels for total suspended solids emissions to water; distinguish emissions to air of NOx and SO2 depending on the combustion mode of the fluid catalytic cracking process; set emission standards for non-methane volatile organic compounds (NMVOC) and benzene for storage and handling processes. The BAT conclusions also include the use of integrated emission management to achieve a cost-effective overall reduction of NOx and SO2 from several process and combustion units.

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 and 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.

At the European level 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 and gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas.
• |  | Independent national competent authorities, responsible for the safety of installations, are in charge 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 applies 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 need 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.

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• |  | Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and national authorities.
• |  | 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 required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.

We believe that Eni operations are currently in compliance with all those regulations in each European country whose 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 hydrocarbons 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. Member States have to transpose and implement the Directive by June 1, 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 is starting the initial activities aimed at guaranteeing the compliance of its own industrial sites.

> HSE activity for the year 2014

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 industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations.

In 2014, 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 341 (down from 2013 because of amalgamations of different site certificates into a single certificate), of which 113 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), 11 certifications according to the ISO 50001 standard (certification for an energy management system) and 119 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

In 2014, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to euro 1,269 million, down 12.2% from 2013.

Environment. In 2014, Eni incurred total expenditures of euro 686.5 million for the protection of the environment (with a reduction of 6.4% with respect to 2013). Current environmental expenses amounted to euro 516.9 million, up by 5.4% from 2013, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure decreased by 30.3% and mainly related to energy efficiency and climate change (particularly flaring down), air protection and spill prevention. Eni expects to continue incurring amount of capital environmental expenditures and current expenses in line with or above 2014 levels in future years.

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Safety. Eni is committed to safeguarding the safety of our employees, contractors and all people living in the areas where our activities are conducted and our assets located. In 2014, the new legislation didn’t have significant impact on the procedures already in place for safety in the workplace.

The improvement and dissemination of safety culture throughout all levels of the Company’s organization continued in 2014. This is one of the foundations of Eni’s safety strategy, through a large communication campaign, launched in 2012, with the target of improving the safety culture and to make it accepted and familiar for all employees/workers in the specific field of safety in the workplace. The campaign will span over three years involving progressively the enterprise top management, the managers of operating sites and all the Eni’s employees. Moreover, in 2013, Eni has continued its safety roadshow initiative, a series of meetings of the Company’s top management with the industrial sites personnel (employees and contractors), dedicated to the sharing of the Company’s safety targets and commitment, focusing also on the HSE aspects of the new process of qualification of vendors. In 2013, Eni has conceived an initiative aimed at issuing work permits in electronic form for standardizing and improving the related risk assessment process. The initiative will consist of implementing by 2014 the project on three pilot sites, with a gradual extension of the project to the other Eni sites in the course of the following years.

Results of efforts to achieve a better safety in all activities has brought an improvement of Eni workforce lost time injury frequency rate to 0.30 and of the severity rate to 0.014, decreasing by 13.1% and by 3% from 2013, respectively. The total recordable injury rate (0.89) decreased by 14.7% compared to 2013.

As to emergency preparedness, Eni has joint the Oil Spill Response Joint Industry Project (OSR-JIP) launched in December 2011 by International Association of Oil&Gas Producers (OGP) and International Petroleum Industry Environmental Conservation Association (IPIECA). This JIP will execute, over a three-year period, the outstanding recommendations from the report produced by the Global Industry Response Group (GIRG) set up after the Macondo accident. The existence of a JIP makes it easier for national administrations, intergovernmental organizations and willing third parties to participate in the studies and therefore to build their confidence in the results of the commissioned investigations and research. The OSR-JIP carries out specific projects dealing with exercise planning, in situ burning, dispersants advocacy-subsea, efficacy-post spill monitoring, upstream risk assessment and response capability, etc.

Costs incurred in 2014 to support the safety levels of operations and to comply with applicable rules and regulations were euro 361.2 million, down by 9.8% from 2013. Eni expects to continue incurring amounts of expenses for safety which will be in line with 2014 levels in future years.

Health. Eni’s activities for protecting health aim to continuously improve work conditions. We believe that we achieved a good performance in this area due 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 outside Italy also with the support of international health centers capable of guaranteeing a prompt and adequate response to any emergency;
• |  | identification of an effective organization of health centers, in Italy and abroad; and
• |  | training programs for medics and paramedics.

To protect the health and safety of its employees, Eni relies on a network of 413 health care centers located in its main operating areas. A set of international agreements with the best local and international health centers 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 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 2014, Eni incurred total expenses of euro 49.4 million, down by 2.8% from 2013, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health which will be in line or above with 2014 levels in future years.

> Managing GHG emissions

In 2015 the UN negotiations on climate change are expected to deliver a global agreement for the post 2020 regime at the 21st Conference of the Parties (COP21) that will be held in Paris in December 2015. In this context United States

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and China have also reached an agreement on the reduction of the greenhouse gases, and the European Union has defined its Climate and Energy strategy up to 2030. As a major international energy company Eni is involved in this political debate. Furthermore, within 2014 Eni has joined three major voluntary initiatives related to climate change: the "Oil&Gas Climate initiative" (aimed at promoting collaboration on climate issues among Oil&Gas companies), the "Clean Air and Climate initiative" (aimed at reducing methane emissions) and the "zero routine gas flaring at 2030" statement of the World Bank’s "Global Gas Flaring reduction partnership".

Regarding Eni’s own GHG emissions management, with the aim of ensuring a comprehensive, transparent and accurate reporting for GHG emissions, Eni introduced in 2005 its own Protocol for accounting and reporting greenhouse gas emissions (GHG Accounting and Reporting Protocol), integrated by a procedure on reporting and accounting methodologies on indirect emissions scope 3 types update in 2014; both documents are an essential requirement for emissions certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the assessment of progress. Eni GHG Protocol has been updated in 2014 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 2013 equivalent CO2 emissions data (scope 1, 2 and 3 emissions), as submitted to the Carbon Disclosure Project, and obtained the verification statement in accordance with ISO 14063-3.

With the aim of mitigating its impacts on climate change and reduce risks related to climate regulation evolution Eni has been implementing for years actions to diminish the carbon intensity of its operations and promote the use of low emission energy sources such as natural gas. In the downstream Eni has developed meaningful projects aimed at energy saving and emission reductions from its plants. A major project on energy efficiency has been recently started in the upstream too. This activity will integrate the flaring down program that, since early 2000s in Africa has foreseen many projects implemented to reduce GHGs and exploit natural gas associated with the production of liquids and reduce emissions.

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 dioxide emissions. The EU-ETS Directive states that any operator, who produces GHG emissions in excess of the amounts allowed on the base of national allocation plan, is required to acquire allowances on the market to cover the excess emissions or to pay a penalty. On January 1, 2013 the third phase (2013-2020) of EU-ETS has started. In this period the main instrument for allowances allocation is represented by sales auctioning and no more by the historical emissions. During this phase no more free allowances will be given to power plants (exception on few particular cases). Conversely, for all the other industrial sectors, the free allocation has been determined with the adoption of European benchmarks linked to the carbon intensity of each industrial process.

Currently, Eni participates in the ETS scheme with 37 plants in Italy and 7 outside Italy, which collectively represent 45% 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 is 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 (2015-2018), Eni shall 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.

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.

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> 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 and 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 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 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 and gas production profits and activities may be substantially higher than those imposed on other businesses.

> Regulation of the Italian hydrocarbons industry

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

> Exploration & Production

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

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

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 and gas, with no exemptions).

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> 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 has committed itself to build new storage capacity for 4 BCM within five years from the enactment of the Decree; 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 and their consortium (3 BCM) and to gas-fired power plants (1 BCM).

Law Decree of December 23, 2013 converted to 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 future market a volume of natural gas corresponding to 5% of the annual imported volumes. The obligation should be combined with a corresponding buy request 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.

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 users, starting from the second quarter of 2012 updated the indexation mechanism by increasing the weight of spot prices in the indexation of the supply costs of gas. In particular, spot prices have represented a share of 3% and 4% of the cost of gas in the second and third quarter 2012, respectively, and 5% in the period October 2012-March 2013, with the remaining part indexed to the supply cost provided by a panel of oil-linked long-term contracts; 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 a space determined by the Ministry itself, storage capacity is reserved for the offer to industrial sector of an integrated service (international transport, re-gasification and storage) allowing them to supply of natural gas from abroad; and
|  | - |  | every year is determined the space of storage devoted to the needs of modulation assigned with auction procedures.

Based on the principles described above, the Minister of Economic Development and the AEEGSI establish every year the criteria for the allocation of gas storage capacities.

> Negotiation platform for gas trading

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 are entrusted to an independent operator, the Gestore dei Mercati Energetici (GME), an Italian agency. On this platform are traded also volumes of gas corresponding to the legal obligations on part of Italian importers and producers as per Law Decree No. 7/2007. Since December 2010, the GME is also trader’s counterparty in transactions on the spot market for natural gas (divided into day-ahead market and intraday market).

Management believes that these measures have increased 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. This new tariff mechanism negatively affected Eni’s results of operations in the Gas & Power segment in 2014 due to the fact that Eni was unable to pass onto to the residential customers the cost increases in the oil-linked supply contracts still present in its portfolio. The new tariff regime intends 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 has been 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 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 is obliged to refund customers of the difference. Based on this compensation mechanism Eni recognized a gain of euro 60 million in its 2014 results of operations. However, due to the current downturn in crude oil prices, Eni is projecting that the oil-linked index of the procurement costs set by the Authority could determine a loss to Eni up to euro 480 million next year. This contingent liability reflects the fact that the Authority index is not reflective of the current setup of Eni’s portfolio of gas supply costs which due to the renegotiations achieved in 2014 is largely indexed to hub prices and therefore Eni’s procurement costs are not expected to benefit from a fall in oil-linked gas procurement costs. It is still possible that the AEEGSI updates its index of procurement costs to better reflect the status of the gas portfolio of those wholesalers who achieved new pricing terms for their gas supplies. Alternatively, Eni might file an administrative appeal against any deliberations of the AEEGSI on this matter which might possibly lead to unfair results to Eni.

The new tariff regime 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.

Similarly other regulatory authorities in European countries where Eni is present have issued regulations introducing a 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 which required 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 has been 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.

Marketing. Following the enactment of the above mentioned Law Decree No. 1 of January 24, 2012, as converted in Law No. 27 of March 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

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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.

From 2000 onwards, a number of administrative measures have been enacted in Italy with the goal of modernizing and making more efficient the Italian network. A Ministerial Decree of October 31, 2001 established the criteria for the closing down of incompatible stations, 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. 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 have supported competition in the Italian retail market.

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 December 31, 2012, No. 249, enacting Directive No. 2009/119/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 net import, including 10% deduction for minimum operational requirements. Decree No. 249/2012 states that compulsory stocks are determined each year by a decree of the Minister of Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company.

The Legislative Decree No. 249/2012 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 of 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.

Under this regulatory framework, the Italian Central Stockholding Entity ("OCSIT") has been instituted, whose activities and functions have been attributed to Acquirente Unico SpA, an entire state-owned company, under the Italian Ministry of Economic Development control. The main purpose of OCSIT shall be to hold oil stocks within Italian territory.

As of December 31, 2014, Eni owned 5.5 mmtonnes of oil products inventories, of which 4.1 mmtonnes as "compulsory stocks", 1.2 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.2 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (37%), light and medium distillates (40%), refinery feedstocks (16%), fuel oil (4%) and other products (3%) were located throughout the Italian territory both in refineries (75%) and in storage sites (25%).

> 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

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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 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 and 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, 2014, there were 252 fully-consolidated subsidiaries and 51 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. For a list of subsidiaries of the Company, see “Exhibit 8. List of Eni’s fully-consolidated subsidiaries for year 2014”.

Item 4A. UNRESOLVED STAFF COMMENTS

None.

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Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Key Information presented in Item 3 and the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards as issued by the IASB.

This section contains forward-looking statements which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii.

Executive summary

Eni reported net profit from continuing operations attributable to its shareholders of euro 1,291 million for the year ending December 31, 2014, representing a decrease of 75% from 2013, down by euro 3,869 million. The year-on-year comparison is greatly affected by the recognition in 2013 profit of gains of euro 4.86 billion due to the implementation of the disposal program of the Company which related to the divestment of a 20% stake in our exploration lease in Mozambique which comprises a gas discovery, a fair value revaluation of our interest in Artic Russia due to the progress in the divestment to Gazprom whereby Eni ceased to exercise significant influence over the investee by 2013 year end, as well as gains on the divestment of certain oil&gas properties. In 2014, gains on divestments regarded the disposal of an 8% stake in Galp, of our interests in South Stream and in EnBw in the Gas & Power segment, as well as non-strategic assets in Exploration & Production for a total gain of approximately euro 0.2 billion.

Beyond that factor, the 2014 decline was driven by lower revenues in the Exploration & Production segment (down by euro 2,776 million from 2013) due to a decline in oil prices (down by 8.9%), which determined a reduction of euro 4,102 million in the segment operating profit also impacted by higher depreciation, amortization and impairment charges, an inventory write down to align the book value of crude oil and products to their net realizable values (a post-tax charge of euro 1,008 million), and finally the recognition of net, post-tax charges amounting to euro 1,408 million. These charges comprised impairments of oil&gas properties and offshore drilling rigs and vessels reflecting a lower oil price environment in the near to medium term, and a write-off of deferred tax assets of Italian subsidiaries due to the projections of lower future taxable profit and prospective abrogation of the additional income tax for energy companies resulting in the redetermination of the deferred tax assets with a statutory tax rate of 27.5% instead of the previous 34%. These charges were partly offset by a tax gain due to the favorable outcome of a proceeding with Italian Tax Authorities regarding the determination of the taxable basis of the additional income tax called Libyan tax.

These negative trends were partly offset by an improved operating profit reported by the Gas & Power segment (up by euro 3,153 million) which reflected the renegotiation of long-term gas supply contracts and lower impairments, whilst charges were incurred in 2013 amounting to euro 3,946 million post tax.

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The table below sets forth for the reported periods details of certain, identified gains and charges included in net profit. These gains and charges mainly related to inventory holding gains and losses, asset impairments, risk and other provisions, write downs of deferred tax assets, capital and revaluation gains on investments and other tangible assets.

Eni Group | Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Profit (loss) on stock |  | 17 |  |  | (716 | ) |  | (1,460 | )
Environmental charges |  | (63 | ) |  | (205 | ) |  | (179 | )
Impairment losses |  | (3,978 | ) |  | (2,400 | ) |  | (1,531 | )
Net gains on disposal of assets |  | 548 |  |  | 187 |  |  | 28 |
Risk provisions |  | (945 | ) |  | (334 | ) |  | 10 |
Provision for redundancy incentives |  | (64 | ) |  | (270 | ) |  | (9 | )
Fair value gains/losses on commodity derivatives |  | 1 |  |  | (315 | ) |  | 16 |
Fair value gains/losses on currency derivatives and translation effects of trade receivables and payables |  | 80 |  |  | 195 |  |  | (229 | )
Other |  | (271 | ) |  | 96 |  |  | (303 | )
Net (charges) gains in operating profit |  | (4,675 | ) |  | (3,762 | ) |  | (3,657 | )
Capital and revaluation gains on Galp |  | 2,011 |  |  | 98 |  |  | 96 |
Capital gain on 28.75% of Eni East Africa |  |  |  |  | 3,359 |  |  |  |
Revaluation gain on Artic Russia |  |  |  |  | 1,682 |  |  |  |
Capital gain on South Stream |  |  |  |  |  |  |  | 54 |
Other capital gains/write downs on investments |  | (108 | ) |  |  |  |  |  |
Write down of deferred tax assets/recognition of deferred tax liabilities |  | (803 | ) |  | (1,444 | ) |  | (1,045 | )
Tax gain on the tax dispute on Libyan Tax |  |  |  |  |  |  |  | 824 |
Tax effects on the above listed items |  | 848 |  |  | 945 |  |  | 825 |
Other |  | (203 | ) |  | (143 | ) |  | (46 | )
Net (charges) gains in net profit |  | (2,930 | ) |  | 735 |  |  | (2,949 | )
Net (charges) gains attributable to non-controlling interest |  |  |  |  | 5 |  |  | (533 | )
Net (charges) gains attributable to Eni |  | (2,930 | ) |  | 730 |  |  | (2,416 | )

In evaluating the Company’s underlying performance, management also considers a measure of profit that excludes the above listed gains and charges, as well as an inventory holding post-tax loss (for euro 1,008 million and euro 438 million in 2014 and 2013, respectively). On that basis, 2014 net profit would have increased by euro 2,416 million and the comparative 2013 result would have reduced by euro 730 million; on that basis the 2014 performance would decline by 16.3% from 2013. The underlying trends comprised a lowered performance in Exploration & Production driven by lower crude oil prices, which effects were partly offset by improved results recorded by Gas & Power and Saipem which reverted to profit due to contract renegotiations and better execution, whilst the Refining & Marketing and Chemical segments reduced operating losses thanks to a less unfavorable trading environment and restructuring initiatives.

Net cash provided by operating activities from continuing operations amounted to euro 15,110 million for the year ended December 31, 2014 and proceeds from divestments amounted to euro 3,684 million. Those cash inflows funded cash outflows relating to capital expenditures totaling euro 12,240 million and investments (euro 408 million), as well as dividend payments amounting to euro 4,434 million (of which euro 2,020 million relating to the 2014 interim dividend, euro 1,956 million to the balance of the dividend for fiscal year 2013 to Eni’s shareholders and euro 380 million for share repurchases).

Disposals of assets (euro 3,684 million) primarily related to the divestment of Eni’s share in Artic Russia (euro 2,160 million), an 8% interest in Galp Energia (euro 824 million), Eni’s interest in the EnBW Eni joint venture in Germany, as well as the divestment of Eni’s stake in the South Stream project and other minor assets.

As of December 31, 2014, net borrowings amounted to euro 13,685 million, a decrease of euro 1,278 million from December 31, 2013. The decline reflected the surplus cash generated by operating activities and disposals of the year.

In 2014, oil and natural gas production available for sale averaged 1,517 KBOE/d (1,537 KBOE/d in 2013). On a homogeneous basis i.e. excluding the impact of the divestment of Eni’s interest in Artic Russia which produced 29 KBOE/d, or 11 mmBOE in 2013 net to Eni, hydrocarbon production for the full year 2014 was up 0.6%. The main production increases were reported in the United Kingdom, Algeria, the United States and Angola.

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Worldwide gas sales in 2014 amounted to 89.17 BCM, a decrease of 4.00 BCM from 2013, or 4.3% . The decrease was mainly driven by lower sales in Italy which were down by 5.1% to 34.04 BCM due to mild winter weather, weak demand, a downturn in the thermoelectric segment and strong competitive pressures. Lower sales in Italy were reported in the industrial, residential and thermoelectric segments. Sales in Europe of 42.21 BCM decreased by 1.1% driven by lower volumes marketed in Germany/Austria, France and the United Kingdom, partially offset by higher sales in Benelux and the Iberian Peninsula.

In 2014, capital expenditures of continuing operations amounted to euro 12,240 million (euro 12,800 million in 2013) and mainly related to:

• |  | development activities amounting to euro 9,021 million which were deployed mainly in Norway, Angola, Congo, the United States, Italy, Nigeria, Egypt, Indonesia, Kazakhstan and exploratory activities (euro 1,398 million) spent almost entirely outside Italy (98%), primarily in Libya, Mozambique, the United States, Nigeria, Angola, Indonesia, Cyprus, Norway and Gabon;
• |  | upgrading of the fleet used in the Engineering & Construction segment (euro 694 million);
• |  | refining, supply and logistics in Italy and outside Italy (euro 362 million) with projects designed to improve the conversion rate and flexibility of refineries, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 175 million); and
• |  | initiatives to improve flexibility of the combined cycle power plants (euro 98 million).

During the 2015-2018 four-year period, Eni expects to invest approximately euro 48 billion in capital expenditures and exploration projects to implement its growth strategy, based on the assumptions discussed below under "Management’s expectation of operations". This capital budget represents a decrease of 17% from the previous plan which management considered to be appropriate to the current weak oil price environment. We plan to be more selective in exploration projects and to re-schedule certain large development projects, while prioritizing low-intensity projects, sanctioned developments and initiatives to support production plateaus at producing fields. Further expenditure reductions will be sought through the renegotiation of contracts for the supply of oilfield services and other goods related to Exploration & Production activities.

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 completing the turnaround process of our Gas & Power, Refining & Marketing and Chemical segments. We plan to generate additional euro 8 billion of funds through our asset disposal program which will mainly comprise the divestment of participating interest in certain of our exploratory leases.

Finally, we also decided to rebase the dividend and we are planning to pay a floor dividend of euro 0.8 per share for fiscal year 2015 in order to achieve a balance between internal-generated funds, including disposals, and fund requirements for capital expenditures and shareholder remuneration at our price assumption of 55 $/BBL for the Brent benchmark in 2015. From 2016, we intend to assess our progressive distribution policy also taking into account an expected improvement in the oil price scenario.

> Trading environment

|  | 2012 |  | 2013 |  | 2014

Average price of Brent dated crude oil in U.S. dollars (1) |  | 111.58 |  | 108.66 |  | 98.99
Average price of Brent dated crude oil in euro (2) |  | 86.83 |  | 81.82 |  | 74.48
Average EUR/USD exchange rate (3) |  | 1.285 |  | 1.328 |  | 1.329
Standard Eni Refining Margin (SERM) (4) |  | n.a. |  | 2.43 |  | 3.21
Euribor - three-month euro rate % (3) |  | 0.6 |  | 0.2 |  | 0.2

(1) | i | Price per barrel. Source: Platt’s Oilgram.
(2) | i | Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).
(3) | i | Source: ECB.
(4) | i | In USD per barrel 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 price and reflect 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 and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest

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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 2014, the Group faced strong headwinds in any of its reference markets. Oil and gas realizations in dollar terms declined due to a lower Brent crude oil price, down by 8.9% from 2013, and lower gas benchmarks. Eni’s refining margins (Standard Eni Refining Margin - SERM) that gauge the profitability of Eni’s refineries were up by 32.1% from the particularly depressed level of 2013, due to a fall in the cost of crude oil feedstock. However, the European refining business continued to be affected by structural headwinds due to lower demand, overcapacity and increasing competitive pressure from streams of cheaper refined products imported from Russia, Asia and the United States. The European gas market was adversely affected by weak demand, competitive pressures and oversupply. Price competition was tough taking into account minimum off-take obligations provided by gas purchase take-or-pay contracts and reduced sales opportunities. Spot prices in Europe reported a decrease of 22.7% from 2013. Electricity sales reported negative margins due to oversupply and increasing competition from more competitive sources (photovoltaic and coal-fired plants).

In the first quarter of 2015, the downtrend in crude oil prices continued as the price of the Brent benchmark averaged approximately 54 $/BBL, down by approximately 50% compared to the first quarter of 2014. This trend reflected current imbalances in world oil demand and supplies. This will negatively impact Group’s results of operations and cash flow going forward. Refining margins increased to an average of 7.5 $/BBL with reference to the Eni’s indicator, representing an increase of approximately 550% year on year, which will improve our results in the Refining & Marketing segment. The euro vs. U.S. dollar exchange rate decreased by 17% year on year. This trend will improve the Group’s results of operations and operating cash flow.

> Key consolidated financial data

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Net sales from operations from continuing operations |  |  |  | 127,109 |  | 114,697 |  | 109,847
Operating profit from continuing operations |  |  |  | 15,208 |  | 8,888 |  | 7,917
Net profit attributable to Eni from continuing operations |  |  |  | 4,200 |  | 5,160 |  | 1,291
Net profit attributable to Eni from discontinued operations |  |  |  | 3,590 |  |  |  |
Net profit attributable to Eni |  |  |  | 7,790 |  | 5,160 |  | 1,291
Net cash provided by operating activities - Continuing operations |  |  |  | 12,552 |  | 11,026 |  | 15,110
Capital expenditures - Continuing operations |  |  |  | 12,805 |  | 12,800 |  | 12,240
Acquisitions of investments and businesses |  |  |  | 569 |  | 317 |  | 408
Shareholders’ equity including non-controlling interest at year end |  |  |  | 62,417 |  | 61,049 |  | 62,209
Net borrowings at year end (1) |  |  |  | 15,069 |  | 14,963 |  | 13,685
Net profit attributable to Eni basic and diluted from continuing operations |  | (euro per share) |  | 1.16 |  | 1.42 |  | 0.36
Net profit attributable to Eni basic and diluted from discontinued operations |  |  |  | 0.99 |  |  |  |
Net profit attributable to Eni basic and diluted |  |  |  | 2.15 |  | 1.42 |  | 0.36
Dividend per share |  | (euro per share) |  | 1.08 |  | 1.10 |  | 1.12
Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) (1) |  |  |  | 0.24 |  | 0.25 |  | 0.22

(1) |  | For a discussion of the usefulness of 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.

Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, 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 of 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 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, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the oilfield services

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construction and engineering businesses. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates follows.

Oil and gas activities

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be 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. 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 expenses and impairment expense. Depreciation and depletion rates on oil and 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 expense. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and 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 values of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced utilization of the plants and, for oil and 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 global or regional market supply and demand conditions. Similar remarks are valid for 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 the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the book value of an asset with its recoverable amount. The recoverable amount is the greater of fair value net of disposal cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. 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 and gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent 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 other intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets at the cash generating unit level on an annual basis and whenever there is an 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

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on which the Company, directly or indirectly, evaluates the return on the capital expenditures. If the recoverable amount of a cash generating unit is lower than the carrying amount, goodwill attributed 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 assets of the cash generating unit are impaired pro-rata on the basis of their carrying amount for the residual difference, up to the recoverable amount of assets with finite useful lives.

> Decommissioning and restoration liabilities

Obligations to dismantle and remove items of property plant and equipment and restore land or seabed require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded presently in the Consolidated Financial Statements. 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 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 recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors.

> Environmental liabilities

As other oil and gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental costs are recognized when it becomes probable that a liability will be incurred and the liability can be reliably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.

> Employee benefits

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. 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 country by country; (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

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changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved. Differences in the amount of the net defined benefit liability (asset), deriving from the remeasurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Remeasurements are recognized within statement of comprehensive income for defined benefit plans and within profit and loss account for long-term plans.

> Provisions

In addition to environmental liabilities, decommissioning and restoration liabilities and employee benefits, Eni recognizes provisions primarily related to litigations, tax issues and doubtful trade receivables. The estimate of these provisions is based on managerial judgments.

> Revenue recognition

Revenue recognition in the Engineering & Construction segment is based on the stage of completion of a contract as measured on the cost-to-cost basis applied to contractual revenues. Use of the stage of completion method requires estimates of future gross profit on a contract by contract basis. The future gross profit represents the profit remaining after deducting costs attributable to the contract from revenues provided for in the contract. The estimate of future gross profit is based on a complex estimation process that includes identification of risks related to the geographical region where the activity is carried out, market conditions in that region and any assessment that is necessary to estimate with sufficient precision the total future costs, as well as the expected timetable to the end of the contract. Additional revenues, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them.

Revenues from the sale of electricity and gas to retail customers include allocations for the not yet billed supplies, occurred between the date of the last meters reading and the year end. These estimates are based on the difference between the volumes allocated by the grid managers and the billed volumes, as well as on other factors, considered by the management, which can impact on them.

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2012-2014 Group results of operations

> Overview of the profit and loss account for three years ended December 31, 2012, 2013 and 2014

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.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Net sales from operations |  | 127,109 |  |  | 114,697 |  |  | 109,847 |
Other income and revenues (1) |  | 1,548 |  |  | 1,387 |  |  | 1,101 |
Total revenues |  | 128,657 |  |  | 116,084 |  |  | 110,948 |
Operating expenses |  | (99,674 | ) |  | (95,304 | ) |  | (91,677 | )
Other operating (expense) income |  | (158 | ) |  | (71 | ) |  | 145 |
Depreciation, depletion, amortization and impairments |  | (13,617 | ) |  | (11,821 | ) |  | (11,499 | )
OPERATING PROFIT |  | 15,208 |  |  | 8,888 |  |  | 7,917 |
Finance income (expense) |  | (1,371 | ) |  | (1,009 | ) |  | (1,065 | )
Income (expense) from investments |  | 2,789 |  |  | 6,085 |  |  | 490 |
PROFIT BEFORE INCOME TAXES |  | 16,626 |  |  | 13,964 |  |  | 7,342 |
Income taxes |  | (11,679 | ) |  | (9,005 | ) |  | (6,492 | )
Net profit - continuing operations |  | 4,947 |  |  | 4,959 |  |  | 850 |
Net profit - discontinued operations |  | 3,732 |  |  |  |  |  |  |
Net profit |  | 8,679 |  |  | 4,959 |  |  | 850 |
Attributable to: |  |  |  |  |  |  |  |  |
Eni’s shareholders: |  | 7,790 |  |  | 5,160 |  |  | 1,291 |
- continuing operations |  | 4,200 |  |  | 5,160 |  |  | 1,291 |
- discontinued operations |  | 3,590 |  |  |  |  |  |  |
Non-controlling interest: |  | 889 |  |  | (201 | ) |  | (441 | )
- continuing operations |  | 747 |  |  | (201 | ) |  | (441 | )
- discontinued operations |  | 142 |  |  |  |  |  |  |

(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,

|  | 2012 |  | 2013 |  | 2014

|  | (%)

Operating expenses |  | 78.4 |  | 83.1 |  | 83.5
Depreciation, depletion, amortization and impairments |  | 10.7 |  | 10.3 |  | 10.5
OPERATING PROFIT |  | 12.0 |  | 7.7 |  | 7.2

2014 compared to 2013. Net profit attributable to Eni’s shareholders from continuing operations in 2014 was euro 1,291 million, a decrease of euro 3,869 million from 2013, or 75%. The decrease is explained by several factors. First of all in 2013 Eni recognized significant gains on the implementation of its divestment program. We divested a 20% stake in the Area 4 exploration lease in Mozambique where important gas discoveries were made and we recognized an euro 2,994 million gain (net of taxes) and we ceased to exercise significant influence on Artic Russia which operates gas assets in Siberia, leading us to recognize a fair value gain of euro 1,682 million pending the disposal of our interest to Gazprom. The other factors affecting of 2014 results and year on year changes were as follows:

(i) |  | a lower operating profit was recorded in the Exploration & Production segment (down by euro 4,102 million, or 27.6%) which was adversely impacted by declining oil prices and increased charges for depreciation, amortization and impairment, and in the Refining & Marketing segment (down euro 737 million, or 49.4%) due to the recognition of an inventory charge of euro 1,576 million (before tax) which reflected the alignment of inventories of oil and refined products to their lower net realizable values at the end of the reporting period; and

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(ii) |  | a euro 280 million net loss on the fair-valued interests in Galp and Snam which are currently underlying two convertible bonds with embedded options measured at fair value through profit. Particularly, we recognized in the line item net income from investments a loss on our fair-valued interests in Galp and Snam amounting to euro 221 million compared to a gain of euro 158 million in 2013 (down by euro 389 million), which was partly offset by the reduced negative fair value of the options embedded in the relevant convertible bond (a gain of euro 109 million) which was recognized in the line item net financial expense.

These decreases were partly offset by:

(i) |  | a recovery in the Gas & Power operating performance (up euro 3,153 million from 2013) due to the renegotiation of a substantial portion of the long-term gas supply portfolio, including one-off effects related to the purchase costs of volumes supplied in previous reporting periods which were larger than in the full year 2013. The benefits of contract renegotiations helped this segment rebalance its cost position and to recoup part of huge losses incurred in the previous year which were also due to large impairment losses and other charges; and
(ii) |  | lower income taxes (down by euro 2,513 million) mainly due to a reduction of taxable profit in the Exploration & Production segment.

2013 compared to 2012. Net profit attributable to Eni’s shareholders from continuing operations in 2013 was euro 5,160 million, an increase of euro 960 million from 2012, or 22.9%. This increase was financially driven by:

(i) |  | the recognition of gains on the divestment of an interest in the Mozambique exploration project and on the fair-value revaluation of Eni’s stake in the Artic Russia joint venture (an overall gain of approximately euro 6 billion); and
(ii) |  | lower income taxes (down euro 2,674 million compared to 2012 full year) currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to lower taxable profit.

These increases were partly offset by:

(i) |  | a lower operating performance (down by euro 6,320 million, or 41.6% from 2012) which was mainly reported by the Exploration & Production segment reflecting lower production sold impacted by geopolitical issues, as well as by the Engineering & Construction segment due to a worsening trading environment, as well as customer relationship and management issues that began to emerge late in 2012 and fully materialized in the first half of 2013 resulting in a significant revision of margin estimates at certain large contracts for the construction of onshore industrial complexes. Also the Refining & Marketing and Chemical segments reported larger operating losses due to a demand downturn, competitive pressure driven by overcapacity and oversupplies and unprofitable unit margins. The Gas & Power segment reported slightly better results in spite of a continuing deterioration in the trading environment which can be explained by lower impairment losses; and
(ii) |  | the lower operating performance was also affected by the recognition of inventory holding losses in particular in the Gas & Power, Refining & Marketing and Chemical segments (down euro 733 million from a year ago). Further information on inventory holding gains and losses is provided on page 93.

> Discontinued operations

In accordance with IFRS 5, 2012 results of the Italian regulated businesses managed by Snam were reported as discontinued operations until loss of control on the entity which occurred in October 2012, as part of a transaction to divest a 30% interest less one share in Snam to an Italian entity, Cassa Depositi e Prestiti. The divestment took place in accordance with Article 15 of Law Decree No. 1 of January 24, 2012, enacted into Law No. 27 of March 24, 2012 which mandated the ownership unbundling of Snam. Prior year data have been modified accordingly.

In accordance with the guidelines of IFRS 5, assets and liabilities, results of operations and cash flow of the discontinued operations were reported separately from the Group’s continuing operations, including gains on the disposal and the revaluation of the residual interest.

The table below sets forth net profit from discontinued operations for the periods indicated.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Net profit - discontinued operations |  | 3,732 |  |  |  |
attributable to: |  |  |  |  |  |
- Eni |  | 3,590 |  |  |  |
- non-controlling interest |  | 142 |  |  |  |

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In 2012, discontinued operations earned net profit of euro 3,732 million which mainly comprised the capital gain on the divestment of a 30% interest less one share in Snam to Cassa Depositi e Prestiti for euro 2,019 million and a revaluation gain of euro 1,451 million on the residual interest; both gains were subject to a limited tax under current Italian tax rules.

Profit earned by discontinued operations in previous reporting periods reflected the fact that Snam and its subsidiaries derived a large part of their revenues from intercompany transactions which profit margins were eliminated upon consolidation. As a result, the underlying profit or loss earned by the discontinued operations represented only profit or loss earned by the Group on transactions with third parties.

Year-on-year comparability of results from continuing operations in 2013 was affected by the fact that in 2012 Snam margins on intragroup transactions relating to the supply of gas transport and other services have been eliminated upon consolidation, while in 2013 those transactions were accounted as third-party transactions, thus affecting the Group operating costs and profits. This trend did not occurred in 2014.

> Analysis of the line items of the profit and loss account of continuing operations

> a) Total revenues

Eni’s revenues from continuing operations were euro 110,948 million, euro 116,084 million and euro 128,657 million for the year ended December 31, 2014, 2013 and 2012, 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 euro 109,847 million, euro 114,697 million and euro 127,109 million for the year ended December 31, 2014, 2013 and 2012, respectively, and its other income and revenues totaled euro 1,101 million, euro 1,387 million and euro 1,548 million, respectively, in these periods.

> 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,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Exploration & Production |  | 35,874 |  |  | 31,264 |  |  | 28,488 |
Gas & Power |  | 36,198 |  |  | 32,212 |  |  | 28,250 |
Refining & Marketing |  | 62,531 |  |  | 57,238 |  |  | 56,153 |
Chemicals |  | 6,418 |  |  | 5,859 |  |  | 5,284 |
Engineering & Construction |  | 12,799 |  |  | 11,598 |  |  | 12,873 |
Other activities |  | 119 |  |  | 80 |  |  | 78 |
Corporate and financial companies |  | 1,369 |  |  | 1,453 |  |  | 1,378 |
Impact of unrealized intragroup profit elimination (1) |  | (75 | ) |  | 18 |  |  | 54 |
Consolidation adjustment (2) |  | (28,124 | ) |  | (25,025 | ) |  | (22,711 | )
NET SALES FROM OPERATIONS |  | 127,109 |  |  | 114,697 |  |  | 109,847 |

(1) |  | This item mainly concerned intragroup sales of goods, services and capital assets recorded at period end in the assets of the purchasing business segment.
(2) |  | Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The largest intragroup sales are recorded by the Exploration & Production segment. See note 43 to the Consolidated Financial Statements for a breakdown of intragroup sales by segment for the reported years.

2014 compared to 2013. Eni’s net sales from operations (revenues) from continuing operations for 2014 (euro 109,847 million) decreased by euro 4,850 million from 2013 (or down 4.2%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms, decreased sales volumes in the Gas & Power, Refining & Marketing and Chemical segments, partly offset by an increase recorded in the Engineering & Construction segment. Exchange rates movements did not impact reported revenues as the average euro vs. U.S. dollar exchange rate was unchanged year on year.

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Revenues generated by the Exploration & Production segment (euro 28,488 million) decreased by euro 2,776 million (or down 8.9%) due to lower oil and gas realizations in dollar terms (down by 8.9% on average).

Revenues generated by the Gas & Power segment (euro 28,250 million) decreased by euro 3,962 million (or down 12.3%) due to a continued deterioration in selling prices reflecting weak gas demand and increasing competitive pressure. Finally, the segment recorded lower sales volumes which were down by 4.3%.

Revenues generated by the Refining & Marketing segment (euro 56,153 million) decreased by euro 1,085 million (or down 1.9%) mainly reflecting lower average sales prices and lower volumes of refined products (down 480 mmtonnes, or 5%, from 2013) due to lower demand and lower product availability due to refinery downtime as the Venice refinery underwent a plant reconfiguration and the Gela unit was shut down.

Revenues generated by the Chemical segment (euro 5,284 million) decreased by euro 575 million (down 9.8%) from 2013 mainly due to lower commodity prices (down 3%), as well as a decline in volumes sold (down by 8.5%) against the backdrop of continuing weak commodity demand, also reflecting plant restructuring.

Revenues generated by the Engineering & Construction segment (euro 12,873 million) increased by euro 1,275 million, or 11%, as a result of an increase in operating activity in the Offshore Engineering & Construction.

2013 compared to 2012. Eni’s net sales from operations (revenues) from continuing operations for 2013 (euro 114,697 million) decreased by euro 12,412 million from 2012 (or down 9.8%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms, the negative impact of the appreciation of the euro against the U.S. dollar, lower volumes in all business segments and a slowdown in the Engineering & Construction business activity.

Revenues generated by the Exploration & Production segment (euro 31,264 million) decreased by euro 4,610 million (or down 12.9%) due to lower oil and gas realizations in dollar terms (down by 2.1%), the appreciation of the euro against the U.S. dollar and the extraordinary disruptions in Libya and Nigeria, which negatively impacted revenues by approximately the same amounts.

Revenues generated by the Gas & Power segment (euro 32,212 million) decreased by euro 3,986 million (or down 11.0%) due to a continued deterioration in selling prices reflecting a weak gas demand and increasing competitive pressure. Particularly, spot prices at Italian hubs have aligned very rapidly to continental hubs, thus driving a large fall in Eni’s average realizations as spot prices have become the main indexation benchmark of selling prices in short-term supplies to large Italian customers. Revenues were also impacted by the price revisions that were agreed with the Company’s Italian long-term buyers whereby contractual prices were aligned to spot prices. Finally, the segment recorded lower sales volumes to European target markets.

Revenues generated by the Refining & Marketing segment (euro 57,238 million) decreased by euro 5,293 million (or down 8.5%) mainly reflecting lower volumes of refined products (down 4.84 mmtonnes, or 10%, from 2012) and the negative impact of the currency.

Revenues generated by the Chemical segment (euro 5,859 million) decreased by euro 559 million (down 8.7%) from 2012 mainly due to a decline in volumes sold (down by 4.2%) against the backdrop of continuing weak commodity demand, which was impacted by the economic downturn, and declining average sales prices (down by 3.2%).

Revenues generated by the Engineering & Construction segment (euro 11,598 million) decreased by euro 1,201 million, or 9.4%, as a result of a decline in business activities in the segments of Onshore E&C and Offshore E&C.

> b) Operating expenses

The table below sets forth the components of Eni’s operating expenses for the periods indicated.

.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Purchases, services and other |  | 95,034 |  | 90,003 |  | 86,340
Payroll and related costs |  | 4,640 |  | 5,301 |  | 5,337
Operating expenses |  | 99,674 |  | 95,304 |  | 91,677

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2014 compared to 2013. Operating expenses from continuing operations for the year (euro 91,677 million) decreased by euro 3,627 million from 2013, down 3.8%, primarily reflecting lower supply costs of raw materials (gas, refinery and chemical feedstock) due to underlying trends in the energy scenario and gas contract renegotiations. The latter included one-off effects relating to the purchase costs of gas volumes supplied in previous reporting periods which impact was greater than that recorded in 2013.

Purchases, services and other costs included environmental and onerous contracts risk provisions, net of reversal of unused provisions, amounting to euro 171 million (for more information see "Item 18 – note 36 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements"). These charges were lower than in 2013.

Payroll and related costs (euro 5,337 million) were almost unchanged from 2013, up by euro 36 million, or 0.7%, due to a higher average number of employees outside Italy particularly in the Engineering & Construction segment, offset by lower provision for redundancy incentives.

2013 compared to 2012. Operating expenses from continuing operations for the year (euro 95,304 million) decreased by euro 4,370 million from 2012, down 4.4%, primarily reflecting lower supply costs of raw materials due to the appreciation of the euro against the U.S. dollar as the Company purchases of gas, refinery and chemical feedstock are indexed to U.S. dollar-denominated prices of crude oil and products, as well as the benefits of the renegotiations of long-term gas supply contracts, some of which were retroactive to previous reporting periods.

Purchases, services and other costs included environmental and onerous contracts risk provisions, net of reversal of unused provisions, amounting to euro 539 million, a large part of which related to the expected losses of an onerous contract in a re-gasification project (for more information see "Item 18 – note 36 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements"). The reduction reflected also the circumstance that in 2012 a risk provision amounting to euro 945 million was incurred in connection with price revisions at long-term gas purchase contracts relating to gas volumes purchased in previous reporting periods, including the provision relating to the settlement of an arbitration proceeding with GasTerra.

Payroll and related costs (euro 5,301 million) increased by euro 661 million, or 14.2%, from 2012 due to a higher average number of employees outside Italy particularly in the Engineering & Construction segment and higher provision for redundancy incentives (euro 270 million), which included Eni’s cost for 2013-2014 redundancy, pursuant to the provisions of Law No. 223/1991.

> c) Depreciation, depletion, amortization and impairments

The table below sets forth a breakdown of depreciation, depletion, amortization and impairments by business segment for the periods indicated.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Exploration & Production (1) |  | 7,985 |  |  | 7,810 |  |  | 8,473 |
Gas & Power |  | 480 |  |  | 413 |  |  | 334 |
Refining & Marketing |  | 366 |  |  | 345 |  |  | 283 |
Chemicals |  | 90 |  |  | 95 |  |  | 99 |
Engineering & Construction |  | 683 |  |  | 721 |  |  | 737 |
Other activities |  | 1 |  |  | 1 |  |  | 1 |
Corporate and financial companies |  | 65 |  |  | 61 |  |  | 69 |
Impact of unrealized intragroup profit elimination (2) |  | (25 | ) |  | (25 | ) |  | (26 | )
Total depreciation, depletion and amortization |  | 9,645 |  |  | 9,421 |  |  | 9,970 |
Impairments |  | 3,972 |  |  | 2,400 |  |  | 1,529 |
|  | 13,617 |  |  | 11,821 |  |  | 11,499 |

(1) |  | Exploration expenditures of euro 1,589 million, euro 1,736 million and euro 1,835 million are included in these amounts relative to the years 2014, 2013 and 2012, respectively.
(2) |  | This item concerned mainly intragroup sales of goods and capital, recorded at period end in the assets of the purchasing business segment.

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2014 compared to 2013. In 2014, depreciation, depletion and amortization charges (euro 9,970 million) increased by euro 549 million from 2013, or 5.8%, mainly in the Exploration & Production segment (euro 663 million) reflecting the start-up of new fields mainly in the second half of 2013.

In 2014, impairments charges of euro 1,529 million related to: (i) oil&gas properties mainly driven by the impact of a lower price environment in the near to medium term (euro 692 million); (ii) rigs and construction vessels of Saipem reflecting expected reduced utilization rates driven by the outlook of low crude oil prices (euro 420 million); and (iii) the retail networks in the Czech Republic and Slovakia to align their book value to the expected sale price. Investments made for compliance and stay-in-business purposes which were completely written-off as they related to certain cash generating units that were impaired in previous reporting periods and confirmed to lack any prospect of profitability (euro 196 million). Other impairment losses were incurred in the Gas & Power (euro 25 million) and Chemical (euro 96 million) segments at certain marginal lines of business due to lack of profitability.

2013 compared to 2012. In 2013, depreciation, depletion and amortization charges (euro 9,421 million) decreased by euro 224 million from 2012, or 2.3%, mainly in the Exploration & Production segment (euro 175 million) reflecting lower production volumes mainly in Libya and Nigeria and the appreciation of the euro against the U.S. dollar which reduced the reported amounts of the Company subsidiaries which use the U.S. dollar as functional currency. The increase recorded in the Engineering & Construction segment (up euro 38 million, or 5.6%) was due to new vessels and rigs which were brought into operations.

In 2013, impairments charges of euro 2,400 million mainly related to the Gas & Power and the Refining & Marketing segments. In the Gas & Power segment, goodwill and other intangible assets allocated to the gas marketing activity in Europe were impaired for euro 480 million which completely wrote down the carrying amounts of goodwill and other intangibles which were recognized upon the Eni Gas & Power NV (former Distrigas) acquisition in 2008. Power generation plants were impaired for euro 919 million and refineries for euro 633 million. Those impairments losses were driven by a reduced profitability outlook which was impacted by structural headwinds in the gas and petroleum products industries due to weak demand prospects, excess supplies and overcapacity and continued competitive pressure which have resulted in the projections of lower values-in-use than the carrying amounts of the impaired assets. Other impairment losses were incurred at a number of oil&gas properties in the Exploration & Production segment (euro 19 million, net of reversal of previous impairment losses) reflecting mainly downward reserve revisions, as well as marginal lines of business in the Chemical segment (euro 44 million) due to lack of profitability perspectives.

> d) Operating profit by segment

The table below sets forth Eni’s operating profit from continuing operations by business segment for the periods indicated.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Exploration & Production |  | 18,470 |  |  | 14,868 |  |  | 10,766 |
Gas & Power |  | (3,125 | ) |  | (2,967 | ) |  | 186 |
Refining & Marketing |  | (1,264 | ) |  | (1,492 | ) |  | (2,229 | )
Chemicals |  | (681 | ) |  | (725 | ) |  | (704 | )
Engineering & Construction |  | 1,453 |  |  | (98 | ) |  | 18 |
Other activities |  | (300 | ) |  | (337 | ) |  | (272 | )
Corporate and financial companies |  | (341 | ) |  | (399 | ) |  | (246 | )
Impact of unrealized intragroup profit elimination |  | 996 |  |  | 38 |  |  | 398 |
Operating profit |  | 15,208 |  |  | 8,888 |  |  | 7,917 |

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The table below sets forth operating profit 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,

|  | 2012 |  | 2013 |  | 2014

|  | (%)

Exploration & Production |  | 51.5 |  |  | 47.6 |  |  | 37.8 |
Gas & Power |  | (8.6 | ) |  | (9.2 | ) |  | 0.7 |
Refining & Marketing |  | (2.0 | ) |  | (2.6 | ) |  | (4.0 | )
Chemicals |  | (10.6 | ) |  | (12.4 | ) |  | (13.3 | )
Engineering & Construction |  | 11.4 |  |  | (0.8 | ) |  | 0.1 |
Other activities |  | (252.1 | ) |  | (421.3 | ) |  | (348.7 | )
Corporate and financial companies |  | (24.9 | ) |  | (27.5 | ) |  | (17.9 | )
Group |  | 12.0 |  |  | 7.7 |  |  | 7.2 |

Exploration & Production. Operating profit in 2014 amounted to euro 10,766 million, down by euro 4,102 million from 2013, or 27.6%. The decline was principally due to reduced oil and gas realizations in dollar terms (down 8.9% on average), higher depreciation charges taken in connection with the start-up of new fields mainly in the second half of 2013, as well as increased impairment charges (up by euro 673 million) and lower gains in divestments (down by euro 207 million).

In 2014, the Company’s liquids and gas realizations decreased on average by 8.9% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude price decreased by 8.9%). Eni’s average oil realizations decreased on average by 10.8%. Eni’s average gas realizations decreased by 5.4%.

Operating profit in 2013 amounted to euro 14,868 million, down by euro 3,602 million from 2012, or 19.5%. The decline was principally due to lower volumes of sold production which was impacted by extraordinary disruptions mainly in Libya and Nigeria. Also results reported by non-euro subsidiaries were impacted by the appreciation of the euro against the U.S. dollar in the conversion of dollar-denominated results of operations (approximately euro 560 million), as well as lower oil and gas realizations in dollar terms (down by 2.1%, on average).

In 2013, the Company’s liquids and gas realizations decreased on average by 2.1% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude price decreased by 2.6%). Eni’s average oil realizations decreased on average by 3.1%. Eni’s average gas realizations increased by 1.9%.

The operating profit of Exploration & Production segment included the following gains and charges:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

Exploration & Production |  | (euro million)

Impairment losses |  | (550 | ) |  | (19 | ) |  | (692 | )
Risk provisions |  | (7 | ) |  | (7 | ) |  | 5 |
Net gains on disposal of assets |  | 542 |  |  | 283 |  |  | 76 |
Provision for redundancy incentives |  | (6 | ) |  | (52 | ) |  | (24 | )
Fair value gains/losses on commodity derivatives |  | (1 | ) |  | 2 |  |  | 28 |
Fair value gains/losses on currency derivatives and translation effects to management measure of business performance |  | 9 |  |  | 2 |  |  | (6 | )
Equipment write down |  |  |  |  |  |  |  | (121 | )
Other |  | (54 | ) |  | 16 |  |  | (51 | )
|  | (67 | ) |  | 225 |  |  | (785 | )

In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the above mentioned charges, the operating profit would reduce by approximately 21.1% from 2013 (from euro 14,643 million in 2013 to euro 11,551 million in 2014).

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Gas & Power. In 2014, the Gas & Power segment reported an operating profit of euro 186 million, with an improvement of euro 3,153 million from 2013 when this segment reported an operating loss of euro 2,967 million.

The 2014 results were driven by better competitiveness due to the renegotiation of a substantial portion of the long-term gas supply portfolio, including one-off effects related to the purchase costs of volumes supplied in previous reporting periods which were larger than in 2013. The result also reflected a positive contribution of international LNG sales. These positives were partially offset by a continued decline in sale prices of gas and electricity, driven by weak demand and continuing competitive pressure, exacerbated by oversupply and market liquidity, as well as a different tariff regime for supplying gas to the regulated residential market in Italy. Finally, the year-on-year comparison was affected by the circumstance that 2013 results were impacted by extraordinary charges amounting to euro 2,329 million mainly driven by euro 1,685 million of impairment losses (euro 25 million in 2014).

In 2013, the Gas & Power segment reported an operating loss of euro 2,967 million, which reflected impairment losses of euro 1,685 million and unprofitable gas selling margins for the remaining amount, particularly in the Italian market. The Gas & Power operating loss improved by euro 158 million from 2012, when this segment reported an operating loss of euro 3,125 million. The 2012 loss was restated by a positive euro 94 million amount due to the adoption in 2013 of the new accounting standard IFRS 11 whereby Eni recognizes, on a line-by-line basis in the Consolidated Financial Statements, its share of the assets, liabilities and expenses of joint operations incurred jointly with the other partners, along with the Group’s income from the sale of its share of the output and any liabilities and expenses that the Group has incurred in relation to the joint operation. See "Item 18 – note 2 – Principles of consolidation – of the Notes on Consolidated Financial Statements". Prior year data have not been restated.

This business has been negatively affected by structural headwinds in the European gas sector in the latest three fiscal years due to continued deterioration in demand, gas oversupplies and unabated competitive pressure which have impacted selling margins. The modest improvement recorded in 2013 compared to 2012 was due to the recognition of lower asset impairments. These losses were mainly incurred by the Marketing business.

The loss recorded by the Marketing business in 2013 was driven by a demand downturn and escalating competitive pressures fuelled by oversupplies in the marketplace, the effects of which were exacerbated by minimum obligations provided by long-term supply contracts, which impacted our operations both in Italy and outside Italy. Based on these trends, Eni’s gas business in Italy was impacted by plummeting prices realized on short-term selling contracts to large Italian clients because those prices were benchmarked to Italian spot prices which swiftly aligned to continental hubs determining negative margins in comparison with oil-linked supply costs. The decline in spot prices was transferred to long-term selling contracts to certain Italian buyers, whereby Eni had those buyers agreed to revise the contractual price of the suppliers to align to spot prices. Furthermore, Eni’s results were impacted by sharply lower margins in the production and sale of gas-fired electricity due to oversupply and increasing competition from more competitive sources such as coal-fired electricity and renewables. The reduced profitability outlook in this business due to changed underlying fundamentals also resulted in the write down of power plants (euro 919 million); in addition goodwill and other intangibles which were recognized as part of certain business combinations in the gas marketing business were impaired due to a reduced profitability outlook. These negative trends were partly offset by the positive effects of price revisions at certain long-term gas suppliers, some of which were retroactive to the previous reporting period.

The table below sets forth the breakdown of operating profit (loss) by businesses in the Gas & Power segment:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Marketing |  | (3,457 | ) |  | (3,155 | ) |  | 27
International transport |  | 332 |  |  | 188 |  |  | 159
Operating profit of the Gas & Power segment |  | (3,125 | ) |  | (2,967 | ) |  | 186

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The operating profit of the Gas & Power segment included the following gains and charges for the years presented:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

Gas & Power |  | (euro million)

Profit (loss) on stock |  | (163 | ) |  | (191 | ) |  | 119 |
Environmental charges |  | 2 |  |  | 1 |  |  |  |
Impairment losses |  | (2,443 | ) |  | (1,685 | ) |  | (25 | )
Net gains on disposal of assets |  | 3 |  |  | (1 | ) |  |  |
Risk provisions |  | (831 | ) |  | (292 | ) |  | 42 |
Provision for redundancy incentives |  | (5 | ) |  | (10 | ) |  | (11 | )
Fair value gains/losses on commodity derivatives |  |  |  |  | (314 | ) |  | 43 |
Fair value gains/losses on currency derivatives and translation effects of trade receivables and payables |  | 52 |  |  | 186 |  |  | (228 | )
Other |  | (138 | ) |  | (23 | ) |  | (64 | )
|  | (3,523 | ) |  | (2,329 | ) |  | (124 | )

In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Particularly, we enter into commodity and currency derivatives to reduce our exposure to the commodity risk due to different indexation between the purchase cost and the selling price of gas and power or to lock a commercial margin once a sale contract has been signed or it is highly probable, as well as 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 and as such they are not accounted as hedges in accordance to IFRS. Therefore 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. Furthermore, albeit the Group classifies within net financial expense those gains and losses on currency derivatives, as well as on the alignment of trade receivable and payables denominated in dollar into the accounts of euro subsidiaries at the closing rate, we believe that 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. Excluding the above mentioned charges and the inventory evaluation profit of euro 119 million, the operating profit would increase by approximately euro 948 million from 2013 (from an operating loss of euro 638 million in 2013 to an operating profit of euro 310 million in 2014).

We note significant amounts of impairment losses which were recorded both in 2013 and 2012 with euro 1,685 million and euro 2,443 million, respectively. Those impairment losses were recorded at the Company’s cash generating unit European market impacting goodwill and other intangibles which were recognized upon prior-year business combinations and power generation plants. The drivers of those losses were a reduced profitability outlook in the business due to continuing demand weakness, strong competitive pressures and ongoing oversupplies which are expected to hurt the Company’s prices and selling margins for the foreseeable future. Risk provisions presented in the table above mainly related to the expected future losses related to an onerous contract for a LNG re-gasification project due to the fact that the Company and its partner discontinued the project, while in 2012 they related to price revisions on the renegotiation of certain long-term supply contracts with respect to which a contractual time span for price revisions expired in previous periods and within limits of volumes purchased in prior reporting periods, also due to the settlement of arbitration proceedings.

Refining & Marketing. In 2014, the Refining & Marketing segment reported an operating loss of euro 2,229 million, down by euro 737 million, or 49.4%, from 2013 when a loss of euro 1,492 million was incurred. The 2014 loss was impacted by an inventory write down of euro 1,576 million (pre-tax) compared to a loss of euro 221 million in 2013.

The result of this segment reflected structural weaknesses in the European refining industry which was negatively impacted by falling demand for fuels, overcapacity and increasing competition from streams of cheaper refined products coming from Russia, Asia and the United States. These negatives were partly offset by a recovery in refining margins compared with the particularly depressed scenario of 2013, reflecting a fall in oil prices. Eni’s refining margin (Standard Eni Refining Margin - SERM) that gauges the profitability of Eni’s refineries considering Eni’s refinery setup and yields was up by 32.1% from 2013.

In addition, 2014 results were supported by efficiency initiatives, particularly those aimed at reducing refining capacity through plant reconversion (i.e. the start-up of the green refinery project in Venice), cost efficiencies particularly through energy and operating costs and optimizing refinery utilization rates by reducing the throughput of less competitive plants. Marketing results were sustained by the decline in oil prices, despite rising competitive pressure

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and lower consumption in the retail market. The 2014 operating loss in the Refining & Marketing segment was also affected by impairment losses (down by euro 284 million) which were recorded mainly at the retail networks in the Czech Republic and Slovakia to align their book value to the expected sale price, and investments made for compliance and stay-in-business purposes which were completely written-off as they related to certain cash generating units that were impaired in previous reporting periods.

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.

In 2013, the Refining & Marketing segment reported an operating loss of euro 1,492 million, down by euro 228 million, or 18%, from 2012 when a loss of euro 1,264 million was incurred. The 2012 loss was restated by a positive euro 32 million amount due to the adoption in 2013 of the new accounting standard IFRS 11 whereby Eni recognizes, on a line-by-line basis in the Consolidated Financial Statements, its share of the assets, liabilities and expenses of joint operations incurred jointly with the other partners, along with the Group’s income from the sale of its share of the output and any liabilities and expenses that the Group has incurred in relation to the joint operation. See "Item 18 – note 2 – Principles of consolidation – of the Notes on Consolidated Financial Statements". Prior year data have not been restated.

2013 marked the third consecutive year of losses at this business. This negative trend reflected structural weaknesses in the European refining industry which was negatively impacted by falling demand, overcapacity and increasing competition from streams of refined products coming from Russia, Asia and the United States. There were also company-specific issues; particularly the Company was impacted by reduced flows of heavy crudes in the Mediterranean Area which squeezed price differentials between the heavy qualities supplied by Eni’s operations and the Brent market benchmark resulting in sharply lower margins in complex cycles.

In 2013, this negative scenario was partly counteracted by efficiency initiatives, in particular those aimed at reducing energy and operating costs and optimizing refinery utilization rates by reducing the throughput of less competitive plants. Marketing results registered a decline compared to the previous year, due to lower consumption in the retail market. The 2013 operating loss in the Refining & Marketing segment was also affected by material impairment losses (down by euro 633 million) which were recorded at refining plants due to management’s business outlook that points to continuing weak fundamentals and unprofitable margins resulting in the projection of lower future cash flows than the assets carrying amounts. Furthermore, the segment reported an inventory holding loss (stock loss) from 2012, down to euro 221 million from a gain of euro 29 million.

The operating profit of the Refining & Marketing segment included the following gains and charges:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

Refining & Marketing |  | (euro million)

Profit (loss) on stock |  | 29 |  |  | (221 | ) |  | (1,576 | )
Environmental charges |  | (40 | ) |  | (93 | ) |  | (111 | )
Impairment losses |  | (846 | ) |  | (633 | ) |  | (284 | )
Net gains on disposal of assets |  | (5 | ) |  | 9 |  |  | 2 |
Risk provisions |  | (49 | ) |  |  |  |  |  |
Provision for redundancy incentives |  | (19 | ) |  | (91 | ) |  | 6 |
Fair value gains/losses on commodity derivatives |  |  |  |  | (5 | ) |  | (42 | )
Fair value gains/losses on currency derivatives and translation effects to management measure of business performance |  | 8 |  |  | 2 |  |  | 9 |
Other |  | (53 | ) |  | (3 | ) |  | (25 | )
|  | (975 | ) |  | (1,035 | ) |  | (2,021 | )

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In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. We note that losses listed above include material impairment losses of refining plants due to the management’s business outlook that points to continuing weak fundamentals and unprofitable margins resulting in the projection of lower future cash flows. Furthermore, we regard the inventory holding gain or loss as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies. Excluding the above mentioned charges and the inventory evaluation loss, the operating loss would reduce by approximately 55% from 2013 (from an operating loss of euro 457 million in 2013 to an operating loss of euro 208 million in 2014).

Chemicals. In 2014, the Chemical segment reported a slightly lower operating loss, with an improvement of euro 21 million, or 2.9%, compared to 2013 (from a loss of euro 725 million in 2013 to a loss of euro 704 million in 2014). This positive performance was driven by a recovery in margins, mainly in intermediates and polyethylene, against the backdrop of continued weakness in commodity demand and increasing competition from non-EU producers. Results reflected efficiency initiatives and restructuring programs, mainly relating to the start-up of the Porto Torres green chemical project and the shutdown of certain unprofitable production units. Furthermore, the segment reported a lower inventory holding loss (stock loss) from 2013, down to euro 170 million from euro 213 million.

In 2013, the Chemical segment reported a slight deterioration in the operating loss, down by euro 44 million, or 6.5%, compared to 2012 (from a loss of euro 681 million in 2012 to a loss of euro 725 million in 2013). This negative performance was driven by falling commodity demand due to the economic downturn and increasing competition from Asian producers which impacted product margins and sales volumes which remained at depressed levels. Sales volumes decreased by 4.3%. Furthermore, the segment reported a much higher inventory holding loss (stock loss) from 2012, down to euro 213 million from euro 63 million.

The operating profit of the Chemical segment included the following gains and charges:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

Chemicals |  | (euro million)

Profit (loss) on stock |  | (63 | ) |  | (213 | ) |  | (170 | )
Environmental charges |  |  |  |  | (61 | ) |  | (27 | )
Impairment losses |  | (112 | ) |  | (44 | ) |  | (96 | )
Risk provisions |  | (18 | ) |  | (4 | ) |  |  |
Net gains on disposal of assets |  | (1 | ) |  |  |  |  | (45 | )
Provision for redundancy incentives |  | (14 | ) |  | (23 | ) |  |  |
Fair value gains/losses on commodity derivatives |  | (1 | ) |  | 1 |  |  | (4 | )
Fair value gains/losses on currency derivatives and translation effects to management measure of business performance |  | 11 |  |  | 5 |  |  | (4 | )
Other |  |  |  |  |  |  |  | (12 | )
|  | (198 | ) |  | (339 | ) |  | (358 | )

In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the above mentioned charges and the inventory evaluation loss which amounted to euro 170 million in 2014, the operating loss would reduce by approximately 10% from 2013 (from an operating loss of euro 386 million in 2013 to an operating loss of euro 346 million in 2014).

Engineering & Construction. In 2014, the Engineering & Construction segment recorded operating profit of euro 18 million compared to an operating loss of euro 98 million in 2013 (up euro 116 million). This result reflected a difficult competitive environment and lower profitability of certain contracts acquired in previous years. The 2014 result also comprised impairment losses at rigs and construction vessels reflecting expected reduced utilization rates driven by the outlook of low crude prices for a total amount of euro 420 million. The 2013 loss was affected by revision of margin estimates at certain large contracts for the construction of onshore industrial complexes.

In 2013, the Engineering & Construction segment registered sharply lower results recording an operating loss of euro 98 million compared to operating profit of euro 1,453 million recorded in 2012 (down euro 1,551 million). This result reflected a worsening trading environment, as well as customer relationship and management issues that began to emerge late in 2012 and fully materialize in the first half of 2013, resulting in a sharply lower revision of margin estimates at certain large contracts for the construction of onshore industrial complexes, as well as a slowdown in order acquisitions in Onshore and Offshore Engineering & Construction businesses.

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The operating profit of Engineering & Construction segment included the following gains and charges:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

Engineering & Construction |  | (euro million)

Impairment losses |  | (25 | ) |  |  |  |  | (420 | )
Risk provisions |  |  |  |  |  |  |  | (25 | )
Net gains on disposal of assets |  | (3 | ) |  | (107 | ) |  | (2 | )
Provision for redundancy incentives |  | (7 | ) |  | (2 | ) |  | (5 | )
Fair value gains/losses on commodity derivatives |  | 3 |  |  | 1 |  |  | (9 | )
Other |  |  |  |  | 109 |  |  |  |
|  | (32 | ) |  | 1 |  |  | (461 | )

In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the above mentioned charges the operating profit would increase by euro 578 million from 2013 (from an operating loss of euro 99 million in 2013 to an operating profit of euro 479 million in 2014).

Other activities. This reporting segment includes the 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 liquidated in past years.

This subsidiary reported operating losses of euro 272 million for 2014, euro 337 million for 2013 and euro 300 million for 2012. The magnitude of losses was mainly influenced by costs incurred for clean-up and remediation activities which accrue yearly and the recognition of risk provisions mainly related to environmental issues and litigation whose breakdown is provided below. See "Item 4 – Environmental regulation" for further details.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Environmental charges |  | (25 | ) |  | (52 | ) |  | (41 | )
Impairment losses |  | (2 | ) |  | (19 | ) |  | (14 | )
Net gains on disposal of assets |  | 12 |  |  | 3 |  |  | (3 | )
Risk provisions |  | (35 | ) |  | (31 | ) |  | (7 | )
Provision for redundancy incentives |  | (2 | ) |  | (20 | ) |  | 3 |
Other |  | (26 | ) |  | (8 | ) |  | (32 | )
|  | (78 | ) |  | (127 | ) |  | (94 | )

In addition to the above listed charges, losses for the reporting periods presented derived from a marginal line of business that the Company is planning to shut down.

Corporate and financial companies. These activities are mainly cost centers which comprise corporate activities and central treasury departments and financial and other subsidiaries that provide a range of financial and business support services to Group companies, including financing of Eni’s projects worldwide, information technology, legal affairs, corporate secretary, employee selection, training and retention, real estate and other general purpose services.

The aggregate Corporate and financial companies reported an operating loss of euro 246 million in 2014 representing a decrease of euro 153 million, compared to the loss recorded in 2013 (euro 399 million), mainly reflecting the recognition of other risk provisions which were partly offset by the implementation of cost efficiency measures.

The aggregate Corporate and financial companies reported an operating loss of euro 399 million for 2013, representing an increase of euro 58 million, compared to the loss recorded in 2012 (euro 341 million), mainly reflecting the recognition of other risk provisions.

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> e) Net finance expense

The table below sets forth a breakdown of Eni’s net financial expense for the periods indicated:

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Gain (loss) on derivative financial instruments |  | (252 | ) |  | (92 | ) |  | 162 |
Exchange differences, net |  | 131 |  |  | 37 |  |  | (250 | )
Net income from financial activities held for trading |  |  |  |  | 4 |  |  | 24 |
Interest income |  | 28 |  |  | 43 |  |  | 26 |
Finance expense on short and long-term debt |  | (986 | ) |  | (923 | ) |  | (922 | )
Finance expense due to the passage of time |  | (308 | ) |  | (240 | ) |  | (293 | )
Other finance income and expense, net |  | (134 | ) |  | (8 | ) |  | 25 |
|  | (1,521 | ) |  | (1,179 | ) |  | (1,228 | )
Finance expense capitalized |  | 150 |  |  | 170 |  |  | 163 |
|  | (1,371 | ) |  | (1,009 | ) |  | (1,065 | )

2014 compared to 2013. In 2014, net finance expense were euro 1,065 million, up by euro 56 million compared to 2013 reflecting negative change in exchange rate differences amounting to euro 287 million, partly offset by gains on the fair value evaluation on certain derivative instruments (euro 162 million gains in 2014, compared to euro 92 million loss in 2013) which did not meet the formal criteria to be designated as hedges under IFRS mainly related to the exchange rate derivatives (up euro 139 million) and the positive effect of the reduction in the liability relating to the fair-valued options (euro 109 million) that are embedded in the convertible bonds relating to Snam’s and Galp’s shares, due to the closer maturity and because options were out-of-money at the balance sheet date.

2013 compared to 2012. In 2013, net finance expense was euro 1,009 million, down by euro 362 million compared to 2012 reflecting lower finance expense on borrowings (down euro 63 million) due to lower market interests and lower losses recognized in fair value evaluation of certain derivative instruments on interest rates (euro 92 million loss in 2013 compared to euro 252 million loss in 2012) which did not meet the formal criteria to be designated as hedges under IFRS. Negative exchange differences net (down euro 94 million) were partly offset by lower losses on exchange rate derivatives (up euro 160 million). Other finance expense decreased by euro 126 million from 2012 mainly due to the fact that the 2012 results reflected finance charges accrued on amounts due to certain gas suppliers following the definition of contractual price revisions.

> f) Net income from investments

2014 compared to 2013. Net income from investments in 2014 was a net gain of euro 490 million and mainly related to: (i) gains on disposal of investments (euro 163 million) which related to a gain recorded on the sale of an 8% interest in Galp (euro 96 million), as well as gains on the divestment of Eni’s interest in the EnBW Eni joint venture in Germany and of Eni’s stake in the South Stream project; (ii) Eni’s share of profit of entities accounted for under the equity-accounting method (euro 121 million), mainly in the Exploration & Production and Gas & Power segments; and (iii) dividends received from entities accounted for at cost (euro 385 million), relating to Nigeria LNG Ltd (euro 247 million). These gains are further explained in “Item 18 – note 19 – Investments – of the Notes on Consolidated Financial Statements”.

Those gains were partly offset by a fair value loss recorded at interests in Galp and Snam which are underlying the convertible bonds as of December 31, 2014 (for a total loss of euro 221 million compared to profit of euro 158 million in 2013). These interests are valued at fair value through profit in accordance to the fair value option provided by IFRS 39 in order to match the corresponding fair value evaluation of the options embedded in the convertible bonds. The net impact on profit was a negative change year on year of euro 280 million loss due to the opposite change in the negative fair value of options embedded in the convertible bonds.

2013 compared to 2012. Net income from investments in 2013 was a net gain of euro 6,085 million and mainly related to: (i) gains on disposal of assets, in particular the gain recorded on the sale of a 28.57% interest in Eni East Africa, which is the operator of Area 4 in Mozambique, to China National Petroleum Corp (euro 3,359 million), and the fair-value revaluation of Eni’s interest in Artic Russia (euro 1,682 million) due to the fact that joint control was lost over the investee following the satisfaction, before year end, of all conditions precedent to the Sale and Purchase Agreement signed with Gazprom in November 2013. The consideration for the disposal was received in January 2014; (ii) Eni’s share of profit of entities accounted for under the equity-accounting method (euro 222 million), mainly in the Exploration & Production and Gas & Power segments; and (iii) dividends received from entities accounted for at cost

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(euro 400 million), relating to Nigeria LNG Ltd (euro 224 million), Snam SpA (euro 72 million) and Galp Energia SGPS SA (euro 43 million). These gains are further explained in “Item 18 – note 19 – Investments – of the Notes on Consolidated Financial Statements”.

> g) Taxes

2014 compared to 2013. In 2014, income taxes amounted to euro 6,492 million, down by euro 2,513 million compared to 2013, or 27.9%, mainly reflecting lower income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to a declining taxable profit. In addition, there was an extraordinary tax gain of euro 824 million due to the settlement of a tax dispute with the Italian Fiscal Authorities regarding how to determine a tax surcharge of 4% due by the parent company Eni SpA as provided by Law No. 7/2009 (the so-called Libyan tax), since 2009. Particularly, Italian Tax Authorities agreed on excluding EU dividends perceived by the parent company Eni SpA from the determination of the taxable profit for the purpose of this surcharge tax, with retroactive effects. This proceeding is described in "Item 18 – note 36 – Tax disputes – of the Notes on Consolidated Financial Statements".

These declines were partly offset by the write-off of certain deferred tax assets (euro 500 million) due to projections of lower future taxable profit at Italian subsidiaries. Furthermore, euro 476 million of deferred tax assets were cancelled which related to a windfall tax levied on Italian energy companies (the so-called Robin Tax) provided by Article 81 of the Legislative Decree No. 112/2008 which at that time established an increase of 6.5 percentage points of the statutory tax rate on corporate profits for energy companies. Those deferred tax assets were assessed to be no more recoverable as, on February 11, 2015, the Italian Constitutional Court stated the illegitimacy of this tax, thus resulting in the redetermination of the deferred tax assets with a statutory tax rate of 27.5% instead of 34%. For the first time, a sentence states the illegitimacy of a tax rule prospectively, denying any reimbursement right. The effect was considered to be an adjusting event of 2014 results, on the basis of the best review of the matter currently available, considering the recent pronouncement of the sentence.

The Group’s consolidated tax rate increased to 88.4% in 2014 compared to 64.5% in 2013, up 23.9 percentage points. The increase in the Group tax rate was due essentially to the significant divestment and revaluation gains on investments recognized in 2013 which were not subject to taxes. The reported tax rate of 88.4% was higher than the Group statutory tax rate of 33.4%, which corresponds to the Italian tax rate for corporation profit, due to the fact the Group profit before taxation was mainly earned by the Group foreign subsidiaries in the Exploration & Production segment which are taxed at rates that are much higher than the Italian statutory tax rate.

2013 compared to 2012. In 2013, income taxes amounted to euro 9,005 million, down by euro 2,674 million compared to 2012, or 22.9%, mainly reflecting lower income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to a declining taxable profit. The Company recognized a write down of euro 954 million of deferred tax assets to reflect a lower likelihood that certain deferred tax assets of Italian subsidiaries can be recovered in future periods due to an expected reduction in taxable income generated in Italy.

The Group’s consolidated tax rate decreased to 64.5% in 2013 compared to 70.2% in 2012, down 5.7 percentage points. This was mainly due to the recognition of gains which were non-taxable items for tax purposes or subject to a rate lower than the Group statutory tax rate. These gains were mainly recorded on the sale of a 28.57% interest in Eni East Africa SpA and the fair-value revaluation of Eni’s interest in Artic Russia. The reported tax rate of 64.5% was higher than the Group statutory tax rate of 43%, which corresponds to the Italian tax rate for corporation profit, due to the fact the Group profit before taxation was mainly earned by the Group foreign subsidiaries in the Exploration & Production segment which are taxed at rates that are much higher than the Italian statutory tax rate.

> h) Non-controlling interest

2014 compared to 2013. Net loss pertaining to non-controlling interest was euro 441 million and concerned primarily Saipem SpA (euro 345 million).

2013 compared to 2012. Net loss pertaining to non-controlling interest was euro 201 million and concerned primarily Saipem SpA (euro 190 million).

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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 well-balanced financing structure.

The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Net profit - continuing operations |  | 4,947 |  |  | 4,959 |  |  | 850 |
Adjustments to reconcile net profit to net cash provided by operating activities: |  |  |  |  |  |  |  |  |
- amortization and depreciation charges, impairment losses and other non-monetary items |  | 11,501 |  |  | 9,723 |  |  | 12,131 |
- net gains on disposal of assets |  | (875 | ) |  | (3,770 | ) |  | (95 | )
- dividends, interest, taxes and other changes |  | 11,962 |  |  | 9,174 |  |  | 6,655 |
Changes in working capital related to operations |  | (3,281 | ) |  | 456 |  |  | 2,668 |
Dividends received, taxes paid, interest (paid) received during the period |  | (11,702 | ) |  | (9,516 | ) |  | (7,099 | )
Net cash provided by operating activities - continuing operations |  | 12,552 |  |  | 11,026 |  |  | 15,110 |
Net cash provided by operating activities - discontinued operations |  | 15 |  |  |  |  |  |  |
Net cash provided by operating activities |  | 12,567 |  |  | 11,026 |  |  | 15,110 |
Capital expenditures - continuing operations |  | (12,805 | ) |  | (12,800 | ) |  | (12,240 | )
Capital expenditures - discontinued operations |  | (756 | ) |  |  |  |  |  |
Capital expenditures |  | (13,561 | ) |  | (12,800 | ) |  | (12,240 | )
Investments and purchases of consolidated subsidiaries and businesses |  | (569 | ) |  | (317 | ) |  | (408 | )
Disposals |  | 6,025 |  |  | 6,360 |  |  | 3,684 |
Other cash flow related to investing activities (*) |  | (272 | ) |  | (4,224 | ) |  | 21 |
Changes in short and long-term finance debt |  | 5,814 |  |  | 1,715 |  |  | (628 | )
Dividends paid and changes in non-controlling interests and reserves |  | (3,743 | ) |  | (4,225 | ) |  | (4,434 | )
Effect of changes in consolidation and exchange differences |  | (16 | ) |  | (40 | ) |  | 78 |
Change in cash and cash equivalent for the year |  | 6,245 |  |  | (2,505 | ) |  | 1,183 |
Cash and cash equivalent at the beginning of the year |  | 1,691 |  |  | 7,936 |  |  | 5,431 |
Cash and cash equivalent at year end |  | 7,936 |  |  | 5,431 |  |  | 6,614 |

(*) |  | Net cash used in investing activities included investments in certain financial assets (mainly short-term 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. In addition, from 2013 the Company has been maintaining a cash reserve comprised of very liquid investments (mainly sovereign and corporate securities) by investing part of the proceeds from the disposal plan which was executed in 2012 and 2013 and the proceeds from the reimbursement of certain financing receivables towards the former subsidiary Snam which was divested at the end of 2012. These investments are held-for-trading financial assets and are also netted against net borrowings. For more information on their composition see “Item 18 – note 9 – of the Notes on Consolidated Financial Statements”. For the definition of net borrowings, see “Financial Condition” below. Cash flows of such investments were as follows:

|  | (euro million) |  | 2012 |  | 2013 |  | 2014

|  | Financing investments: |  |  |  |  |  |  |  |  |
|  | - securities |  |  |  |  | (5,029 | ) |  | (19 | )
|  | - financing receivables |  | (1,172 | ) |  | (105 | ) |  | (519 | )
|  |  |  | (1,172 | ) |  | (5,134 | ) |  | (538 | )
|  | Disposal of financing investments: |  |  |  |  |  |  |  |  |
|  | - securities |  | 6 |  |  | 28 |  |  | 32 |
|  | - financing receivables |  | 1,087 |  |  | 1,125 |  |  | 92 |
|  |  |  | 1,093 |  |  | 1,153 |  |  | 124 |
|  | Net cash flows from financing activities |  | (79 | ) |  | (3,981 | ) |  | (414 | )

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The table below sets forth the principal components of Eni’s change in net borrowings (1) for the periods indicated.

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Net cash provided by operating activities |  | 12,567 |  |  | 11,026 |  |  | 15,110 |
Capital expenditures |  | (13,561 | ) |  | (12,800 | ) |  | (12,240 | )
Acquisitions of investments and businesses |  | (569 | ) |  | (317 | ) |  | (408 | )
Disposals |  | 6,025 |  |  | 6,360 |  |  | 3,684 |
Other cash flow related to capital expenditures, investments and divestments |  | (193 | ) |  | (243 | ) |  | 435 |
Net borrowings (1) of acquired companies |  | (2 | ) |  | (21 | ) |  | (19 | )
Net borrowings (1) of divested companies |  | 12,446 |  |  | (23 | ) |  |  |
Exchange differences on net borrowings and other changes |  | (345 | ) |  | 349 |  |  | (850 | )
Dividends paid and changes in non-controlling interest and reserves |  | (3,743 | ) |  | (4,225 | ) |  | (4,434 | )
Change in net borrowings (1) |  | 12,625 |  |  | 106 |  |  | 1,278 |
Net borrowings (1) at the beginning of the year |  | 27,694 |  |  | 15,069 |  |  | 14,963 |
Net borrowings (1) at year end |  | 15,069 |  |  | 14,963 |  |  | 13,685 |

(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 2014, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization and impairment charges of tangible and intangible assets (euro 11,499 million). Adjustments to net profit also included gains on disposals (euro 95 million) relating mainly to the divestment of Eni’s stake in Galp and the South Stream project, income taxes (euro 6,492 million) and interest expense (euro 719 million) net of the dividends and interest income accrued in the year as opposed to amounts actually paid.

In 2013, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization and impairment charges of tangible and intangible assets (euro 11,821 million) net of the fair value revaluation of Eni’s interest in Artic Russia amounting to euro 1,682 million and other changes. Adjustments to net profit also included gains on disposals (euro 3,770 million) mainly relating to the Mozambique transaction, income taxes (euro 9,005 million) and interest expenses (euro 711 million) net of the dividends and interest income accrued in the year as opposed to amounts actually paid.

> a) Changes in working capital related to operations

In 2014, changes in working capital generated cash flows amounting to a positive euro 2,668 million as a result of: (i) decreasing inventories (a positive euro 1,524 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); (ii) net cash generated by a positive balance between trade receivables collected and trade payables paid (a net inflow of euro 1,091 million). This was driven by a reduced exposure in the Exploration & Production segment towards certain state-owned oil companies and other local agencies mainly in Egypt where the Company cashed in significant amounts of overdue trade payables thanks to finalization of industrial and commercial agreements with the counterparties. Also the Engineering & Construction segment recorded a reduction in trade receivables; and (iii) a positive inflow related to other current assets and liabilities (up by euro 240 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.

In 2013, changes in working capital generated cash flows amounting to a positive euro 456 million as a result of: (i) decreasing gas and petroleum products inventories (a positive euro 350 million) as a result of destocking oil and products inventories, the effect of which were partly offset by higher contract work in progress in the Engineering & Construction segment albeit of a lower magnitude than in 2012; and (ii) a positive balance of other current assets and liabilities (up by euro 723 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

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long-term customers which were partly offset by payments made to long term, gas suppliers for the lower volumes of gas collected in 2012 with respect to minimum take obligations. Also the Engineering & Construction segment benefited from cash inflows from contract advances; the effects of which were partly offset by net cash absorbed by the balance between trade receivables and payables (down by euro 676 million) due to a deteriorated credit environment, particularly in the Gas & Power segment, which caused a slowdown in the collection of trading receivables; and increased exposure to joint venture partners in the Exploration & Production segment in the execution of capital projects and due to under-lifting with respect to the Company’s own share of production.

> b) Investing activities

| Year ended December 31,

|  | 2012 |  | 2013 |  | 2014

|  | (euro million)

Exploration & Production |  | 10,307 |  |  | 10,475 |  |  | 10,524 |
Gas & Power |  | 213 |  |  | 229 |  |  | 172 |
Refining & Marketing |  | 898 |  |  | 672 |  |  | 537 |
Chemicals |  | 172 |  |  | 314 |  |  | 282 |
Engineering & Construction |  | 1,011 |  |  | 902 |  |  | 694 |
Other activities |  | 14 |  |  | 21 |  |  | 30 |
Corporate and financial companies |  | 152 |  |  | 190 |  |  | 83 |
Impact of unrealized intragroup profit elimination |  | 38 |  |  | (3 | ) |  | (82 | )
Capital expenditures - continuing operations |  | 12,805 |  |  | 12,800 |  |  | 12,240 |
Capital expenditures - discontinued operations |  | 756 |  |  |  |  |  |  |
Capital expenditures |  | 13,561 |  |  | 12,800 |  |  | 12,240 |
Acquisition of investments and businesses |  | 569 |  |  | 317 |  |  | 408 |
|  | 14,130 |  |  | 13,117 |  |  | 12,648 |
Disposals |  | (6,025 | ) |  | (6,360 | ) |  | (3,684 | )

Capital expenditures totaled euro 12,240 million and euro 12,800 million, respectively in 2014 and in 2013.

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 euro 408 million in 2014 and euro 317 million in 2013. In 2014, they comprised the purchase of a small company which markets gas in Italy, the farm-in of an oil property in the United Kingdom and capital expenditures made through joint ventures and associates.

In 2014, disposals amounted to euro 3,684 million and mainly related to: (i) the divestment of Eni’s share in Artic Russia (euro 2,160 million); and (ii) the divestment of an 8% interest in Galp Energia (euro 824 million). Eni’s stake in the South Stream project, as well as other non-strategic assets in the Gas & Power segment.

In 2013, disposals amounted to euro 6,360 million and mainly related to: (i) the divestment of a 28.57% interest in Eni East Africa, currently retaining an interest of 70% in the Area 4 mineral property in Mozambique to China National Petroleum Corp (euro 3,386 million); (ii) the divestment of the 11.69% interest in the share capital of Snam (euro 1,459 million); (iii) the sale of a 8.19% interest in the share capital of Galp (euro 830 million); and (iv) other non-strategic assets in the Exploration & Production segment.

> c) Dividends paid and changes in non-controlling interests and reserves

In 2014, dividends paid and changes in non-controlling interests and reserves (euro 4,434 million) mainly related to: (i) cash dividends to Eni shareholders (euro 4,006 million, of which euro 2,020 million relating to 2014 interim dividend and euro 1,986 million to the balance dividend for fiscal year 2013); (ii) the distribution of dividends to non-controlling interests by other consolidated subsidiaries (euro 49 million); and (iii) share repurchases (euro 380 million).

In 2013, dividends paid and changes in non-controlling interests and reserves (euro 4,225 million) mainly related to: (i) cash dividends to Eni shareholders (euro 3,949 million, which euro 1,993 million relating to 2013 interim dividend and euro 1,956 million to the balance dividend for fiscal year 2012 to Eni’s shareholders); and (ii) the

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distribution of dividends to non-controlling interests by Saipem SpA (euro 170 million) and other consolidated subsidiaries (euro 80 million).

> Financial condition

Management assesses the Group 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. From 2013, the Company has been maintaining a cash reserve comprised of very liquid investments (mainly sovereign and corporate securities which management has selected based on their creditworthiness) by investing part of the proceeds from the disposal plan carried out in 2012 and 2013 and the proceeds from the reimbursement of certain financing receivables towards the former subsidiary Snam which was divested at the end of 2012. Those securities amounted to euro 5,037 million as of end of 2014 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 that of other companies.

The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure.

| As of December 31,

|  | 2012 |  | 2013 |  | 2014

|  | Short-term |  | Long-term |  | Total |  | Short-term |  | Long-term |  | Total |  | Short-term |  | Long-term |  | Total

| (euro million)

Total debt (short-term and long-term debt) |  | 5,047 |  |  | 19,145 |  | 24,192 |  |  | 4,685 |  |  | 20,875 |  | 25,560 |  |  | 6,575 |  |  | 19,316 |  | 25,891 |
Cash and cash equivalents |  | (7,936 | ) |  |  |  | (7,936 | ) |  | (5,431 | ) |  |  |  | (5,431 | ) |  | (6,614 | ) |  |  |  | (6,614 | )
Securities held for trading and other securities held for non-operating purposes |  | (36 | ) |  |  |  | (36 | ) |  | (5,037 | ) |  |  |  | (5,037 | ) |  | (5,037 | ) |  |  |  | (5,037 | )
Non-operating financing receivables |  | (1,151 | ) |  |  |  | (1,151 | ) |  | (129 | ) |  |  |  | (129 | ) |  | (555 | ) |  |  |  | (555 | )
Net borrowings |  | (4,076 | ) |  | 19,145 |  | 15,069 |  |  | (5,912 | ) |  | 20,875 |  | 14,963 |  |  | (5,631 | ) |  | 19,316 |  | 13,685 |

| As of December 31,

|  | 2012 |  | 2013 |  | 2014

Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS |  | (euro million) |  | 62,417 |  |  | 61,049 |  |  | 62,209 |
Ratio of total debt to total shareholders’ equity including non-controlling interest |  |  |  | 0.39 |  |  | 0.42 |  |  | 0.42 |
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest |  |  |  | (0.15 | ) |  | (0.17 | ) |  | (0.20 | )
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) |  |  |  | 0.24 |  |  | 0.25 |  |  | 0.22 |

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In 2014, net borrowings amounted to euro 13,685 million, representing a euro 1,278 million decrease from 2013 as a result of net cash provided by operating activities of continuing operations (euro 15,110 million) and proceeds from disposals of euro 3,684 million which funded cash outflows relating to capital expenditures totaling euro 12,240 million and investments (euro 408 million) and dividend payments and other changes amounting to euro 4,434 million, and currency translation differences which amounted to a positive euro 137 million.

The Group leverage was 0.22 at December 31, 2014 reporting a decrease from 0.25 as of the end of 2013.

Total equity increased by euro 1,160 million from December 31, 2013. This was due to comprehensive income for the year (euro 5,598 million) as a result of net profit (euro 850 million), positive foreign currency translation differences (euro 5,008 million) in translating to euro amounts the net equity of subsidiaries whose functional currency is the U.S. dollar due to the euro depreciation in exchange rates recorded at year end (down by 12.3% due to the exchange rate recorded on December 31, 2014 at 1.210 euro compared to 1 euro = 1.378 US$ at December 31, 2013). This addition to equity was almost completely offset by dividend payments to Eni’s shareholders and other changes for euro 4,438 million.

Total debt of euro 25,891 million consisted of euro 6,575 million of short-term debt (including the portion of long-term debt due within twelve months equal to euro 3,859 million) and euro 19,316 million of long-term debt.

Total debt included ordinary bonds for euro 17,924 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 3,816 million (including accrued interest and discount). Bonds issued in 2014 amounted to euro 1,025 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (89%), U.S. dollar (8%), pound sterling (2%) and 1% in other currencies.

In 2013, net borrowings amounted to euro 14,963 million, representing a euro 106 million decrease from 2012 as a result of net cash provided by operating activities of continuing operations (euro 11,026 million) and proceeds from disposals of euro 6,360 million which funded cash outflows relating to capital expenditures totaling euro 12,800 million and investments (euro 317 million) and dividend payments and other changes amounting to euro 4,225 million, and currency translation differences which amounted to a positive euro 630 million.

The Group leverage was 0.25 at December 31, 2013 reporting a small increase from 0.24 as of end of 2012.

> Capital expenditures by segment

Exploration & Production. In 2014, capital expenditures of the Exploration & Production segment amounted to euro 10,524 million, representing a slight increase of euro 49 million, or 0.5%, from 2013 mainly due to the development of oil and gas reserves (euro 9,021 million). Significant expenditures were directed mainly outside Italy, in particular Norway, Angola, Congo, the United States, Nigeria, Egypt, Indonesia and Kazakhstan. 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. About 98% of exploration expenditures that amounted to euro 1,398 million were directed outside Italy, in particular in Libya, Mozambique, the United States, Nigeria, Angola, Indonesia, Cyprus, Norway and Gabon.

In 2013, capital expenditures of the Exploration & Production segment amounted to euro 10,475 million, representing an increase of euro 168 million, or 1.6%, from 2012 mainly due to the development of oil and gas reserves (euro 8,580 million). Significant expenditures were directed mainly outside Italy, in particular Norway, the United States, Angola, Congo, Nigeria, Kazakhstan, Egypt and the United Kingdom. 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. About 98% of exploration expenditures that amounted to euro 1,850 million were directed outside Italy, in particular in Mozambique, Norway, Congo, Togo, Nigeria, the United States and Angola, as well as the acquisition of new licenses in the Republic of Cyprus and in Vietnam.

Gas & Power. In 2014, capital expenditures in the Gas & Power segment totaled euro 172 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (euro 98 million) and to develop the gas marketing activity (euro 66 million).

In 2013, capital expenditures in the Gas & Power segment totaled euro 229 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (euro 119 million) and to develop the gas marketing activity (euro 87 million).

Refining & Marketing. In 2014, capital expenditures in the Refining & Marketing segment amounted to euro 537 million and regarded mainly: (i) refining, supply and logistics with projects designed to improve the conversion rate and flexibility of refineries (euro 362 million), in particular at the Sannazzaro refinery; and (ii) upgrading of the refined product retail network (euro 175 million).

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In 2013, capital expenditures in the Refining & Marketing segment amounted to euro 672 million and regarded mainly: (i) refining, supply and logistics with projects designed to improve the conversion rate and flexibility of refineries (euro 497 million), in particular at the Sannazzaro refinery; and (ii) upgrading and rebranding of the refined product retail network (euro 175 million).

Chemicals. In 2014, capital expenditures in the Chemical segment amounted to euro 282 million and regarded mainly: (i) improvement of plants’ efficiency (euro 161 million) and other upgradings (euro 28 million); (ii) environmental protection, safety and environmental regulation (euro 30 million); and (iii) maintenance and savings (euro 26 million).

In 2013, capital expenditures in the Chemical segment amounted to euro 314 million and regarded mainly: (i) improvement of plants’ efficiency (euro 170 million) and other upgradings (euro 66 million); (ii) environmental protection, safety and environmental regulation (euro 52 million); and (iii) maintenance and savings (euro 14 million).

Engineering & Construction. In 2014, capital expenditures in the Engineering & Construction segment (euro 694 million) mainly regarded: (i) the Engineering & Construction Offshore business unit, the continuation of the construction activity for a realization of a new base in Brazil, as well as maintenance and upgrading of already existing assets; (ii) in the Engineering & Construction Onshore business unit, the acquisition of equipment and maintenance of existing assets facilities; (iii) in the Offshore Drilling business unit, maintenance of drilling rig Perro Negro 7 and semi-submersible platform Scarabeo 7, as well as maintenance and upgrading of exiting assets; and (iv) in the Onshore Drilling business unit, the preparation work for two new rigs in Saudi Arabia and upgrading of the asset base.

In 2013, capital expenditures in the Engineering & Construction segment (euro 902 million) mainly regarded: (i) completion of the preparation work for a new pipelayer, in continuation of the construction activity of a new base in Brazil, as well as maintenance and upgrading of existing assets in the Offshore Engineering & Construction business; (ii) acquisition of equipment and facilities for the base in Canada, as well as maintenance of the asset base in the Onshore Engineering & Construction business; (iii) upgrading of the works on the semi-submersible rig Scarabeo 5 and Scarabeo 7, as well as jack-up Perro Negro 3, in the Offshore Drilling business unit; and (iv) purchase of materials and equipment and planned upkeep of the current asset base in the Onshore Drilling business.

Recent developments

The table below sets forth certain indicators of the trading environment for the periods indicated:

|  | Three months ended March 31,

|  | 2014 |  | 2015

Average price of Brent dated crude oil in U.S. dollars (1) |  | 108.21 |  | 53.94
Average price of Brent dated crude oil in euro (2) |  | 78.96 |  | 47.90
Average EUR/USD exchange rate (3) |  | 1.371 |  | 1.126
Average European Refining Margin (4) |  | 1.17 |  | 7.56
EURIBOR - three month euro rate % (3) |  | 0.3 |  | 0.1

(1) |  | Price per barrel. Source: Platt’s Oilgram.
(2) |  | Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).
(3) |  | Source: ECB.
(4) |  | In USD per barrel 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.

> Significant transactions

The Company’s Annual General Shareholders Meeting scheduled on May 13, 2015, is due to approve the full year dividend proposal of euro 1.12 per share. Eni expects to pay the balance of the dividend for fiscal year 2014 amounting to euro 0.56 per share in May 2015. The total cash out is estimated at euro 2 billion.

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Management’s expectations of operations

The Company is forecasting a moderate strengthening in global economic growth in 2015, driven by the United States. However, certain risks may affect: uncertainty remains around the strength of the Euro-zone recovery, the extent of the slowdown of the Chinese economy and of other emerging economies, as well as financial stability. Oil prices are forecast to be significantly lower than last years, due to an oversupplied global market. In the Exploration & Production segment, management’s main operating targets include efficiency initiatives, investment optimization, as well as a strong focus on project execution and time-to-market, in order to cope with the negative impact of a lower oil price scenario. Looking at the other Company’s business segments, mainly exposed to the European economic outlook, Eni’s management anticipates challenging market conditions reflecting structural headwinds due to weak commodity demand, oversupply/overcapacity and competitive pressure from more efficient producers. The fall in oil prices may only lessen the negative impact of such trends. The preservation of profitability in these sectors will leverage on the continued renegotiation of gas supply contracts, restructuring/reconversion of the production capacity tied to the oil cycle, cost efficiencies and margin optimization.

> Exploration & Production

In the next few years, our priority in our Exploration & Production segment will be to preserve and grow cash generation in a low oil price environment. To achieve this objective we plan to leverage on production growth, strict capital and cost discipline, focused exploration activity, as well as the monetization of our excess stakes in recent material discoveries, in line with our "dual exploration model", and the sale of non strategic assets.We expect the outlook for the production of liquids and natural gas to be favorable in 2015 with growth that will be driven by new field start-ups, mainly in Norway and Venezuela, and the continuing ramp-up of fields started in 2014 mainly in Angola, Congo, and the United States. This forecast includes assumptions relating to production levels in Libya and Nigeria which are exposed to risks of disruptions and political instability. Overall, we plan to grow production at an average rate of 3.5% across the plan period 2015-2018, driven by the start-ups of new fields and production ramp up that will add more than 650 KBOE/d in 2018. This new production has a good level of visibility since it is mostly related to projects that have been sanctioned and are operated. The main start ups include Goliat in the Barents Sea and Perla in Venezuela in 2015, the re-start of the Kashagan field late in 2016, the oil and gas project of Offshore Cape Three Points in Ghana and the Jangkrik project in Indonesia in 2017. Our production plans are based on our Brent price scenario of 63 $/BBL on average in 2015-2016 and on a gradual recovery in the following years up to 90 $/BBL in 2018 which is confirmed in the long term (on constant monetary term compared to 2018, i.e. from 2019 onwards crude oil prices will grow in line with a projected inflationary rate). See “Item 4 – Exploration & Production”.

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. The Company estimates that production entitlements in its current portfolio of PSAs will increase on average by approximately 1,000 BBL/d for each $1 decrease in oil prices compared to current Eni’s assumptions for oil prices. 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.

Management will focus on delivering the planned projects on time. Some of our projects are complex due to scale and reach of operations, environmentally-sensitive or remote locations, harsh external conditions, industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. Furthermore, we have experienced delays and cost overruns at certain projects which were caused by 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: (i) in-sourcing critical engineering and project management activities; (ii) increasing direct control and governance on construction activities; (iii) deploying our employees and competences to manage hook-up and commissioning; and (iv) entering into framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants and increasing focus on supply chain programming to optimize order flows.

Management also plans to increase the share of operated production in the Company’s portfolio. We expect to operate 84% of the planned new field start-ups in the plan period. 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 risky wells will represent approximately 24% of the planned wells to be drilled in 2015.

In order to mitigate the expected negative impact of lower oil prices in the short to medium term, the Company is planning to implement a number of initiatives of rationalization and optimization in order to reduce expenditures. The main target is to reduce the capital budget compared to the previous four-year plan by 13% at constant exchange rate, while at the same time achieving an equivalent rate of production growth. In order to reduce spending we will leverage

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on the renegotiation of contractual terms with contractors to align costs of field services and capital goods to the changed market conditions. In addition, we will take a modular and phased approach to project development by postponing certain development phases and slowing down projects that still need to be sanctioned and by focusing on those developments with shorter time to market. This will enable the Company to reduce financial exposure and to accelerate production start-ups. Finally, we will be more selective in exploration initiatives by prioritizing projects near fields and in proven areas and in appraisal activities in order to ensure fast reserve replacement. In 2015, Eni plans a decrease of 13% of capital expenditures in Exploration & Production from 2014 at constant exchange rate, due to a reduction in exploration expenditures, project re-phasing and contract renegotiations. In addition, Eni intend to reduce unitary operating costs by 7% by means of efficiency initiatives including contract revisions, rescheduling of non-mandatory activities and an expected reduction in energy costs and logistics.

Finally, the Company plans to seek cost efficiencies due to greater deployment of proprietary technologies designed to maximize the rate of hydrocarbon recovery from reservoirs and reduce drilling costs, as well as continuing operational improvement.

> Gas & Power

We expect a weak outlook for natural gas sales and prices due to structural headwinds in the industry as we forecast demand stagnation, oversupplies and strong competition across all of our main markets in Europe, including Italy. Management does not expect any improvements in this scenario in the next four-year plan. Management expects gas sales to be flat or decreasing over the next four years and gas prices to continue falling.

We believe that going forward reduced sales opportunities and continued pricing competition will be caused by weaker-than-anticipated demand growth which is expected to be dragged down by macroeconomic uncertainties and by the current downturn in the thermoelectric sector which will be penalized by the competition from coal which is cheaper than gas in firing power plants and the development of renewable sources of energy (photovoltaic, solar to name the most important). The absolute level of gas consumption in Europe contracted by approximately 12% in the time span from 2008 to 2013 and in 2014 gas consumption fell dramatically by a further 12%. According to our projections gas consumption will return back to 2013 levels somewhere in 2020. Against this backdrop, European markets remains well supplied thanks to the fast development of liquid hubs where operators can trade spot gas. In 2013, approximately 62% of gas volumes supplied were traded at continental hubs. These trends will drive continuing competition and pricing pressure, which are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses whereby wholesaler 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.

In Italy we expect that gas prices in the wholesale market will remain under pressure due to a number of negative factors including competitive pressure and the current level of minimum take volumes of Italian operators which are well above the absolute dimension of the Italian market. In the retail market, the regulated tariffs to residential and commercial users are currently indexed to spot prices of gas quoted at continental hubs. See also the risk factors described in “Item 3 – Risks in the Company Gas & Power business – Risks associated with sector-specific regulations in Italy”. Finally, our margins in the production of electricity at our gas-fired plants have significantly deteriorated due to the increasing pressure of cheaper electricity from coal and renewables and we expect a slow recovery in electricity margins along the plan period.

Against this scenario the Company priority in its Gas & Power business is to preserve the economic and financial sustainability in the long term. In order to achieve this goal, 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, the development of highly profitable segments and cost efficiencies and operational streamlining.

Our take-or-pay, long-term supply contracts include revisions clauses whereby each counterparties has right to renegotiate the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Right to renegotiate derives from the contractual principle which states a fair sharing of the economic benefits of the contracts between the counterparties. In 2014, we substantially completed a round of renegotiations and achieved an indexation to hub benchmarks for around 70% of our supply portfolio. This new indexation mechanism replaced the oil linked formula adopted in previous periods, thus mitigating the risk of mismatch between our procurement costs and the hub prices to which selling prices are benchmarked. We expect to complete the alignment of the remainder of our supply portfolio to market conditions by 2016. Subsequently we will seek to align our procurement costs to prices prevailing in the wholesale market which includes sales to large industrial and power companies and resellers.

Once we have completed contract renegotiations in accordance with our plans, we will be able to fully compete on the marketplace and to support our long-term profitability and cash generation.

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However, 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. Furthermore in case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration procedure could be started to solve the commercial dispute. This potentially adds to the level of uncertainty surrounding the outcome of those renegotiations. Considering also ongoing price renegotiations with Eni long-term customers, future results of the Gas Marketing activities are subject to increasing volatility and unpredictability.

In addition to contract renegotiation, the Company intends to grow its presence in market segments where margins can be sustained in the long run. 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 in line with our past performance. In the long run, we will leverage integration with our upstream operations by marketing equity gas, particularly with the start of the gas projects in Mozambique. 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 and flexibility in volumes collection (see “Item 4 – Gas & Power”). The second leg of the Company’s marketing effort will address retail customers across Europe with a view to enhancing the existing customer base. The drivers to achieve this will be a strategy of customer retention centered on brand identity, the administrative advantages of the dual offer of gas and electricity and a competitive cost to serve; a wide range of sale channels 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 marketing and general and administrative costs. Finally, the Company intends to capture margins improvements by means of trading activities by entering 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). 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. By this way, the Company also intends to rationalize its logistic cost structure by better exploiting available transport capacity. 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. As part of the risks which management considered in its profitability outlook, there is also a regulatory risk relating to the Italian market as disclosed in "Item 3 – Risk factors" in the section "Risk in the Company’s Gas & Power business", under the heading "Risks associated with sector-specific regulations in Italy".

Management believes that a weak industry outlook adversely affected by sluggish demand growth and large gas availability on the marketplace, the possible evolution of sector-specific regulation and strong competitive pressures represent risk factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts. The Company exposure to take-or-pay obligations improved significantly in 2014 due to contract renegotiations and effective selling activities. Thanks to these levers, in 2014, the Company achieved a 50% reduction in its deferred costs recorded in the balance sheet (from euro 1.9 billion at the beginning of 2014 down to approximately euro 0.9 billion at year end) as the Company lifted 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. We plan to substantially finalize the recovery of the residual amounts of gas paid in advance by the plan period leveraging on contract renegotiations, which may reduce the annual minimum take and provide more flexible conditions for gas off-takes, and optimization of our sales programs.

These projections could be subject 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".

> Refining & Marketing

Management expects that the trading environment will show limited improvement throughout the four-year period covered by the industrial plan. We expect a challenging business outlook due to structural headwinds in the industry which will continue to be negatively affected by anticipated weak demand trends, excess capacity and rising

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competitive pressure from cheaper product streams imported from Asia, Russia, the Middle East and the United States. We consider an ongoing recovery in refining margins driven by lower crude oil prices to be a temporary trend.

Against this scenario the Company priority in its Refining & Marketing business is to recover the economic and financial sustainability in a short timeframe, targeting to break even at both operating profit excluding charges which management is not planning for and cash generation before investment in 2015, then to stabilize profitability and cash generation in the long run. In order to achieve this goal, our strategy in the Refining & Marketing sector will leverage on reducing and rationalizing refining capacity in order to limit the Company’s exposure to volatile refining margins, and on efficiency initiatives.

We are planning for a 50% capacity cut (2012 base) which, once implemented, will bring our installed capacity in line with our targeted exposure to the refining business considering our view of industry trends and fundamentals. Till 2014, we have delivered a 30% capacity downsizing, including the shutdown of the Venice refinery, which underwent a restructuring process to be converted into a plant for the production of bio-fuels based on a proprietary technology, and of the Gela refinery, which will be converted into a unit for the manufacturing of bio-fuels like the Venice site and into a logistic hub. Finally we signed a preliminary agreement to divest our interest in a refining asset located in the Czech Republic and we expect to close the transaction by mid 2015. We believe that the restructuring initiatives implemented so far have reduced the refining break-even margin. Going forward, we plan to divest our interest in certain refining assets abroad and to downsize our less competitive Italian refineries. We intend to make selective capital expenditures expecting to invest approximately euro 1 billion to improve efficiency and optimize existing plant, to complete the bio refinery at the Venice site and to implement the Gela project. We have defined other initiatives designed to which will provide for: (i) optimize plant set-up and logistics operations by means of higher flexibility and process integration; and (ii) deliver cost efficiencies, particularly in refinery fixed expenses and energy savings.

In Marketing activities, where we expect continuing competitive pressure due to weak demand trends and oversupplies in our core domestic market, we are planning to achieve a gradual improvement in results of operations mainly by focusing on margin preservation and cost efficiencies. We will try to do this by means of effective marketing initiatives to retain customers, product and service innovation and a continuing focus on the quality of service, as well as the expansion of non-oil activities. Management plans to improve the efficiency of the Italian retail network by closing low-throughput outlets and other rationalizations. Retail operations abroad will be focused on those areas and markets where we expect attractive profitability due to an improving scenario for consumption, while we plan to divest our presence in marginal areas, mainly in East Europe.

With respect to short-term targets, refining throughputs on Eni’s account are expected to be slightly higher than those processed in 2014 in light of a moderately improved scenario compared to the previous year. The production of bio-fuels is foreseen to increase following an expected production ramp-up at the Venice refinery.

Retail sales of refined products in Italy and the Rest of Europe: retail sales are expected to remain stable compared to 2014. While we anticipate weak demand trends and strong competitive pressure, we plan to leverage on marketing initiatives, as well as customer retention efforts to drive sales and maintain the Company’s market share.

> Chemicals

Eni’s chemical operations are exposed to volatile costs of oil-based feedstock and the cyclicality of demand due to the commoditized nature of Eni’s product portfolio and underlying weaknesses in the industry. Our commodity chemical businesses have been unprofitable in recent years and we expect only limited improvements in the scenario in the foreseeable future due to structural cost disadvantages with respect to Asian and Middle East players and also U.S. players, as well as a weak macroeconomic outlook which will hamper a sustainable recovery in demand. We believe that the current improvement in the cost of oil-based feedstock will provide only limited upside to the weak underlying fundamentals of the petrochemical sector in Europe. Against this backdrop, management’s strategy will consist of progressively reducing the exposure to loss-making commodity chemicals, by restructuring production capacity thanks to the closure, divestment or plant reconversion of our unprofitable production lines, and of refocusing on more profitable market segments. In 2014, we completed the reconversion of the Porto Torres obsolete cracking unit into a plant for the production of specialties based on green feedstock in partnership with Novamont and we also divested our loss-making unit at Sarroch, thus finalizing the restructuring of our operations in Sardinia. We also defined a plan which targets the long-term sustainability of the Porto Marghera cracking unit. This plan comprises the development of an innovative green chemical project and the definitive closure of the oil-based cracking plant. We believe that the restructuring initiatives implemented in 2014 will lower the business breakeven going forward. Our return to profitability will be underpinned by a progressive growth in the production of chemicals based on green technologies and in niche productions such as elastomers where we have the competitive advantage granted by proprietary technologies. This will be also driven by the start-up in the plan period of certain projects to jointly product and market elastomers with Asian partners in Malaysia and South Korea. Management plans to continue efficiency actions, cost savings and rationalization initiatives at loss-making plants.

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Based on the planned industrial actions, management expects the Chemical business to break even in 2016 at both operating profit excluding charges which management is not planning for (i.e. impairment losses and other extraordinary items) and cash flow from operations.

> Engineering & Construction

We expect a challenging trading environment in the oilfield services sector due to lower crude oil prices. In spite of this, we forecast that the execution of recently-acquired projects will support operating results.

Over the four-year plan Saipem intends to improve profitability by leveraging on a growth in those market segments where it owns competitive advantages, like ultra-deep projects, trunkline segment, harsh environments and complex onshore projects. Saipem will also leverage on the enhancement of the EPC(I)-oriented business model its world-class technology, engineering and delivering skills, its strong local presence and established relationships with other major oil companies and national oil companies. The profitability and cash generation over the plan period will be sustained by selective capital expenditures, efficiency actions, working capital optimization.

> Capital expenditure plans

Over the next four years, the Company plans to invest euro 47.8 billion to support continued organic growth; approximately 90% of planned capital expenditures is expected to be directed to the Exploration & Production.

Some euro 36 billion will be devoted to development activities in our Exploration & Production segment to fuel production growth. Project start-ups and plateau enhancement at existing fields will be geographically diversified and executed mainly in Angola, Indonesia, Congo, Norway, Kazakhstan, Venezuela, Libya and Egypt and the start of development activities in Mozambique which will target production growth beyond the plan period.

Exploration capex will amount to approximately euro 5 billion, intended to pursue finding projects in well-established basins, proven areas and in near-field activities to ensure fast reserve replacement.

In the Refining & Marketing segment we plan to make selective capital expenditures, mainly targeting refinery efficiency and flexibility, as well as plant reliability and security. We plan to complete the conversion of the Venice plant into a "bio-refinery" to produce bio-fuels and to execute the Gela project for the reconversion of the local refinery into a bio-plant and the building of a logistic hub. Other capital projects will be directed to network upgrading.

In the Chemical business we plan to selectively expand capacity in the best-positioned lines of business (namely elastomers), while targeting plant efficiency, reliability and energy savings in other areas, including the restructuring and upgrading of the loss-making sites. We plan to finalize the project to convert the Porto Torres plant into a bio-chemical complex, to execute the project of restructuring the Porto Marghera plant by building new plants based on green and renewable feedstock, and to develop strategic initiatives in the field of elastomers in emerging markets.

Eni’s capital expenditure program is reflective of a lower oil price environment and will be more selective by focusing the more profitable projects in portfolio, projects with fast pay-back and by rephasing certain large oil and gas projects which are planned to be developed along a number of stages. These optimizations and other measures including contract renegotiations will drive a 17% reduction in capital expenditure, with respect to the previous plan at constant exchange rates (down by 11% excluding the impact of a changed assumption about the euro vs. the U.S. dollar exchange rate).

For the year 2015, we are planning euro 12 billion of capital expenditure, down by 14% at costant exchange rates (down by 7% excluding new exchange rate assumptions).

Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 90 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2019 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 to the Group. In 2014, management assessed that the cost of capital to the Group decreased from the previous year mainly reflecting a reduction in the premium for the sovereign risk incorporated into the yields on Italian ten-year bonds, and, to a lower extent, a reduced market risk premium of the Eni share. The other financial parameters used for assessing the cost of capital: the cost of borrowings to Eni determined by expected trends in borrowing spreads and management’s estimates about the composition of the Company’s financial debt and ratio of net borrowings to equity, were substantially unchanged from the previous reporting period; (ii) an appreciation of the country risk which 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

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consensus outlook; in 2014, our average premium for the country risk was substantially in line with 2013; and (iii) a premium for the business risk.

> Liquidity and leverage

In the current weak oil price environment, management’s priority remains to preserve a solid balance sheet and to avoid deterioration in the Company’s financial structure, seeking to maintain its key ratio of net borrowings to equity – leverage – within the range of 0.1-0.3. At the end of 2014, leverage stood at 0.22 which represented a 0.03 points improvement from the previous reporting period. Management believes that this target range in leverage is consistent with the Company’s business profile, which features an increasing exposure to the Exploration & Production segment. See "Item 4 – Business developments".

For planning purposes, management assumes a declining scenario of Brent crude oil prices from approximately 100 $/BBL in 2014 to 63 $/BBL on average in the years 2015-2016, and expects a recovery in the years 2017-2018 up to the Company’s long-term Brent price of 90 $/BBL. Our recovery assumption is supported by the industry reaction to the current weak oil price. Based on the announcement and plans declared by other oil companies which point to spending reductions, we believe that an oil shortage could emerge sometime in the medium to long term, assuming a 5% per annum declining rate at existing fields, whereas oil demand could be stimulated by low oil prices and then could start growing again.

In the short to medium term, management plans to mitigate the effects of projected lower revenues in the Exploration & Production segment on the expected cash flows from operation by reducing capital expenditures, the level of which was reset at euro 12 billion per year, and by achieving efficiencies in the Exploration & Production operating costs and in corporate general and administrative costs. The planned reduction in capital expenditures, which will foresee a 17% reduction versus the previous plan at constant exchange rate assumptions, will leverage on:

• |  | a reduction in exploration expenditures which will be mainly focused on low-risk activities, particularly on replacing produced reserves in proven areas and nearby producing assets;
• |  | a reduction in development expenditures by rescheduling the activities at certain large projects without jeopardizing the achievement of the Company’s targets of production growth;
• |  | a reduction of capital expenditures in refining and chemicals due to the shutdown of certain plants which will require fewer investments than in the past and the disposal of certain assets under development like the divestment of our interest in the South Stream project which was defined at the end of 2014; and
• |  | renegotiations of contracts for oilfields services and other supplies in our Exploration & Production segment.

We expect that in the years 2015-2016 our cash flow from operations will be able on average to fund our projected capital expenditures. In the subsequent years, under our planning assumption of a recovery in crude oil prices and considering our industrial actions, we will able to increase our cash flow from operations by 40% thus generating a significant surplus over the projected level of capital expenditures. Furthermore, management expects to deliver approximately euro 8 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of excess stakes in our exploration assets. We believe that the market value of our discoveries has only been impacted by the current weak price environment and that many operators may be interested in acquiring stakes in certain of our assets thanks to their robustness in terms of size, location, cost structure and other industry parameters. These additional cash flows will put the Company in the position to retain degrees of flexibility in order to achieve certain Company’s corporate purposes including support to a high credit rating and payment of dividends to shareholders. In addition, we expect that our disposals will be completed in large part within 2015-2016. Overall, we believe that the Group leverage will remain within the 0.30 ceiling across the weakest years of our financial plans and then improve in line with the expected trends in the price scenario and our planned improvement in cash generation. This forecast factors in our pricing assumptions and considers the planned actions in terms of capital discipline, cost control, restructuring of our Gas & Power, Refining & Marketing and Chemical businesses which will turn cash positive in the plan period due to contract renegotiations, expansion in profitable market segments and reduced exposure to the commodity risk, as well as asset disposal.

Our cash flow projections are exposed to the risks of further deterioration in the oil price environment. Currently, based on our portfolio of oil&gas properties, we estimates that, holding all other factors constant, our net profit and cash flow changes by approximately euro 0.15 billion for each dollar variation in Brent prices on a yearly basis compared to our price forecasts. We note that the Brent price in the period January 1 to March 31, 2015 was 54 $/BBL on average. We retain additional levels of flexibility that we may use in case the current decline in oil prices may result sharper or more prolonged than our assumptions. Particularly, approximately half of the investment in the four-year plan have 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 an average exchange rate of 1.185 U.S. dollars per euro in the 2015-2018 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

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driver of the Group results of operations, cash flow and balance sheet in case the current appreciation of the U.S. dollar versus the euro continues. We note that in the first quarter of 2015 the euro vs. the U.S. dollar exchange rate was 1.13. This trend will favorably impact 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

Management plans to pay a dividend of euro 1.12 per share for fiscal year 2014 subject to approval from the General Shareholders’ Meeting scheduled in May 2015. Of this, euro 0.56 per share was paid in September 2014 as an interim dividend with the balance of euro 0.56 per share expected to be paid in late May 2015.

Considering the current weak oil price scenario, the Company decided to rebase the annual dividend at euro 0.8 per share in relation to 2015 fiscal year, while confirming in the following years a progressive distribution policy taking into account our expected underlying earnings growth.

The dividend is based on management’s planning assumptions of a declining Brent scenario down from 100 $/BBL in 2014 to 55 $/BBL in 2015 and of a recovery in the subsequent years up to the long-term price of 90 $/BBL.

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 and 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 and 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 workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to "Item 3 – Risk factors".

> Off-balance sheet arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in "Item 18 – note 36 – 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 36 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements".

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> Contractual obligations

Amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

| Maturity year

| Total |  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2018 |  | 2020 and thereafter

| (euro million)

Total debt |  | 29,912 |  | 10,360 |  | 3,327 |  | 3,234 |  | 1,462 |  | 2,820 |  | 8,709
Long-term finance debt |  | 22,942 |  | 3,533 |  | 3,226 |  | 3,217 |  | 1,462 |  | 2,795 |  | 8,709
Short-term finance debt |  | 2,716 |  | 2,716 |  |  |  |  |  |  |  |  |  |
Fair value of derivative instruments |  | 4,254 |  | 4,111 |  | 101 |  | 17 |  |  |  | 25 |  |
Interest on finance debt |  | 4,775 |  | 792 |  | 702 |  | 609 |  | 478 |  | 413 |  | 1,781
Guarantees to banks |  | 173 |  | 173 |  |  |  |  |  |  |  |  |  |
Non-cancelable operating lease obligations (1) |  | 2,985 |  | 606 |  | 468 |  | 398 |  | 314 |  | 242 |  | 957
Decommissioning liabilities (2) |  | 16,570 |  | 217 |  | 191 |  | 194 |  | 326 |  | 264 |  | 15,378
Environmental liabilities (3) |  | 1,665 |  | 300 |  | 283 |  | 234 |  | 298 |  | 177 |  | 373
Purchase obligations (4) |  | 223,926 |  | 19,317 |  | 16,346 |  | 15,622 |  | 15,201 |  | 14,645 |  | 142,795
Natural gas to be purchased in connection with take-or-pay contracts (5) |  | 210,798 |  | 16,479 |  | 14,725 |  | 14,034 |  | 14,078 |  | 13,616 |  | 137,866
Natural gas to be transported in connection with ship-or-pay contracts (5) |  | 9,562 |  | 1,771 |  | 1,212 |  | 1,184 |  | 934 |  | 843 |  | 3,618
Other take-or-pay and ship-or-pay obligations |  | 965 |  | 123 |  | 118 |  | 106 |  | 98 |  | 97 |  | 423
Other purchase obligations (6) |  | 2,601 |  | 944 |  | 291 |  | 298 |  | 91 |  | 89 |  | 888
Other obligations (7) |  | 130 |  | 3 |  | 3 |  | 3 |  | 3 |  | 2 |  | 116
of which: |  |  |  |  |  |  |  |  |  |  |  |  |  |
- Memorandum of intent relating to Val d’Agri |  | 130 |  | 3 |  | 3 |  | 3 |  | 3 |  | 2 |  | 116
Total |  | 280,136 |  | 31,768 |  | 21,320 |  | 20,294 |  | 18,082 |  | 18,563 |  | 170,109

(1) |  | Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(2) |  | Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3) |  | Environmental liabilities do not include the environmental charge amounting to euro 1,109 million for the proposal to the Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment cannot be reasonably estimated.
(4) |  | Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(5) |  | 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 – Liberalization of the Italian natural gas market” for a discussion of nature and importance of Eni’s take-or-pay contracts and the related risks from the evolving regulatory environment that could negatively impact Eni’s results.
(6) |  | Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States of euro 1,317 million.
(7) |  | 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 “Item 18 – note 30 – of the Notes on Consolidated Financial Statements”.

The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment as of December 31, 2014. 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.

| Total |  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 and thereafter

| (euro million)

Committed projects |  | 32,126 |  | 10,376 |  | 8,188 |  | 5,039 |  | 3,103 |  | 5,420

> Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term finance requirements and to settle obligations.

Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as

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a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. The Group has also established a cash reserve which consists of cash on hand and very liquid financial assets (short-term deposits and securities) the amount of which 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 ensure the funding of 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 36 of the Notes on Consolidated Financial Statements”.

As of December 31, 2014, Eni maintained short-term unused borrowing facilities of euro 12,698 million, of which euro 41 million committed. Long-term committed borrowing facilities amounted to euro 6,598 million, of which euro 647 million were due within 12 months, which were completely undrawn at the balance sheet date. 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 euro 15 billion, of which about euro 13.3 billion were drawn as of December 31, 2014.

> 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 36 of the Notes on Consolidated Financial Statements".

For information about credit losses in 2014 and the allowance for doubtful accounts see "Item 18 – note 11 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 36 of the Notes on Consolidated Financial Statements".

> Research and development

For a description of Eni’s research and development operations in 2014, see "Item 4 – Research and development".

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Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

The following table lists the Company’s Board of Directors as at April 20156:

Name |  | Position |  | Year elected or appointed |  | Age
Emma Marcegaglia |  | Chairman |  | 2014 |  | 49
Claudio Descalzi |  | CEO |  | 2014 |  | 60
Andrea Gemma |  | Director |  | 2014 |  | 41
Pietro A. Guindani |  | Director |  | 2014 |  | 57
Karina A. Litvack |  | Director |  | 2014 |  | 52
Alessandro Lorenzi |  | Director |  | 2011 |  | 66
Diva Moriani |  | Director |  | 2014 |  | 46
Fabrizio Pagani |  | Director |  | 2014 |  | 48
Luigi Zingales |  | Director |  | 2014 |  | 52

In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members.

The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on May 8, 2014, 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 Zingales 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 afore mentioned 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 has been Chairman of Eni since May 2014. She was born in Mantua in 1965. She graduated in Business Economics at the Bocconi University in Milan and attended a Master in Business Administration at New York University. She is President of Businesseurope and Luiss Guido Carli University, Deputy Chairman and CEO of Marcegaglia SpA, Member of the Board of Directors of Bracco SpA, Italcementi SpA and Gabetti Property Solutions SpA. She is Chairman of Fondazione Eni Enrico Mattei, appointed in November 2014. From May 2008 to May 2012, she was President of Confindustria. She was also a Member of the Management Board of Banco Popolare and Director of FinecoBank SpA. From May 2004 to May 2008, she was appointed as Deputy Vice President of Confindustria for infrastructures, energy, transport and environment, also acting as the Italian Representative for the High Level Group established by the European Commission for energy, competitiveness and environment. From 2000 to 2002, she was Vice President of Confindustria for Europe; from 1996 to 2000, President of the Young Italian Entrepreneurs Association of Confindustria; from 1997 to 2000, President of the European Confederation of the Young Entrepreneurs (YES) and from 1994 to 1996, she was National Vice President of the Young Italian Entrepreneurs Association of Confindustria.

Claudio Descalzi has been CEO of Eni since May 2014. He was born in Milan in 1955 and he graduated in physics in 1979 from the University of Milan. He is currently Vice President of Confindustria Energia and Director of Fondazione Teatro alla Scala. He joined Eni in 1981 as oil&gas field petroleum engineering and project manager, for the development of North Sea, Libya, Nigeria and Congo. In 1990, he was appointed Head of reservoir and operating

(6) |  | Until May 8, 2014, the members of the Board of Directors were: Giuseppe Recchi (Chairman), Paolo Scaroni (CEO), Carlo Cesare Gatto, Alessandro Lorenzi, Paolo Marchioni, Roberto Petri, Alessandro Profumo, Mario Resca and Francesco Taranto.

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activities for Italy. In 1994, he was named Managing Director of Eni subsidiary in Congo and in 1998 Vice Chairman & Managing Director of Naoc, Eni subsidiary 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 Chairman of the board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of Eni - Exploration & Production Division. From 2006 to 2014, he was President of Assomineraria. From 2008 to 2014, he was Chief Operating Officer of Eni - 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" award by the Society of Petroleum Engineers and the American Institute of Mining Engineers.

Andrea Gemma has been Director of Eni since May 2014. He was born in Rome in 1973. He is Professor of Private Law at The Third University of Rome, Department of Law, Member of the Strategic Board of the American University of Rome. Cassationist Lawyer and Partner of the Law and Tax Firm Gemma & Partners. He is a Member of the Banking and Financial Ombudsman (ABF) at the Rome College appointed by Bank of Italy, Member of the Studies Centre of the Chamber of Arbitration of Rome, Arbitrator at the Chamber of Arbitration of Public Works. He is Chairman of Immobiliare Strasburgo Srl, Deputy Chairman of Serenissima SGR SpA and Chairman of the Watch Structure of Sorgent-e SpA. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA, Sequoia Partecipazioni SpA, Suditalia Compagnia di Assicurazioni e Riassicurazione SpA and Alpi Assicurazioni SpA, Liquidator of Corit SpA and Sigrec SpA (Unicredit Group). He was Official Receiver of Dima Costruzioni SpA and Progress Assicurazioni SpA. In 2012, he was Member of the Ministerial Commission for the reform of the bankruptcy proceedings and extraordinary administration procedures. In 2010-2012, he was appointed by the Minister of Justice as implementer of the Prison Plan and, in 2008-2009, Expert of the working group of the Commission appointed by the Premiership and officiated by the Minister for the European policies for the implementing of the European legislation.

Pietro A. Guindani has been Director of Eni since May 2014. He was born in Milan in 1958. He graduated in Business at the Bocconi University in Milan. From 1982 to 1986, he was Relationship Banker of Citibank N.A. Subsequently, he became Director International Finance Department of Montedison SpA (Enimont SpA) until 1992. He was Group Finance, Budget and Reporting Manager of European Vinyls Corporation SA/NV (1992-1993). In 1993, he became International Finance Director of 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 Omnitel NV. Currently, he is Chairman of the Board of Directors of Vodafone Omnitel BV, Board Member of FINECOBank SpA, of Salini-Impregilo SpA and of the Italian Institute of Technology, President of the Bocconi University Alumni Association, Board Member of Civita Foundation, Assonime and Confindustria, Vice President for Universities, Innovation and Human Capital of Assolombarda. He was also Director of Pirelli & C SpA (2011-2014), Carraro SpA (2009-2012) and Sorin SpA (2009-2012).

Karina A. Litvack has been Director of Eni since May 2014. She was born in Montreal in 1962. She graduated in Political Economy at the University of Toronto. 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 of Transparency International UK. From 1986 to 1988, she was a member of the Corporate Finance team of PaineWebber Inc. From 1991 to 1993, she was a Project Manager of the New York City Economic Development Corp. In 1998, she joined F&C Asset Management plc where she held the position of Analyst Ethical Research, Director Ethical Research and Director Head of Governance and Sustainable Investments (2001-2012). She was also a Member of the Board of the Extractive Industries Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012).

Alessandro Lorenzi has been a Director of Eni since May 2011. He was born in Turin in 1948. He is currently a founding partner of Tokos Srl, consulting firm for securities investment, Chairman of Società Metropolitana Acque Torino SpA, Director of Ersel SIM SpA and Millbo 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 VI 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 the GFT Group, where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of the GFT Group (1984-1988), Head of Finance and Control of the 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 Central Manager and subsequently, Director of Ersel SIM SpA until June 2000. In 2000, he became Central Manager 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. In 2006, he became Central Corporate Manager at Lavazza SpA, becoming member of the Board of Directors from 2008 to June 2011.

Diva Moriani has been Director of Eni since May 2014. She was born in Arezzo in 1968. She graduated in Economics at the University of Florence. She is actually Executive Vice Chairman of Intek Group SpA, CEO of KME AG Vorstand, German holding company of KME Group, Member of the Supervisory Board of KME Germany GmbH and Director of Moncler SpA, Ergycapital SpA, Dynamo Academy, KME Srl, Dynamo Foundation and Associazione

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Dynamo. From 2007 to 2012, she was CEO of I2Capital Partners, private equity fund sponsored by Intek SpA, with an investment strategy focused on Special Situation.

Fabrizio Pagani has been Director of Eni since May 2014. He was born in Pisa in 1967. He graduated in International Studies at the Scuola Superiore Sant’Anna, Pisa, and received a Master from the European University Institute, Florence. He has been visiting scholar at the Columbia University, New York. Currently, he is the Head of the Office of the Minister of Finance. He has been Senior Economic Counsellor of the Prime Minister and G20 Sherpa from 2013 to 2014; Director of the G8/G20 Office at the OECD from 2011 to 2013; Political Counsellor of the OECD General Secretary from 2009 to 2011; Director of SACE from 2007 to 2008; Head of the Office of the State Undersecretary, within the Prime Minister Office; Senior Advisor at the OECD from 2002 to 2006; Counsellor for International Affairs of the Minister of Industry and Foreign Trade from 1999 to 2001; Deputy Chief of the Legislative Office at the Department of European Affairs from 1998 to 1999; Professor of International Law at the School of Political Science at the University of Pisa from 1993 to 2001; Deputy Director of the International Training Programme for Conflict Management at the School S. Anna of Pisa, from 1995 to 1998; he has been NATO Fellow.

Luigi Zingales has been Director of Eni since May 2014. He was born in Padua in 1963. He graduated in Economics at the Bocconi University in Milan and earned a doctorate in Economics at the Massachusetts Institutes of Technology of Cambridge. He is actually “Robert C. McCormack Professor of Entrepreneurship and Finance” at the University of Chicago Booth School of Business. He is also Research Associate at the National Bureau of Economic Research, Research Fellow at the Center for Economic Policy Research, Fellow at the European Corporate Governance Institute, Member of the Committee on Capital Market Regulation, Member of the American Academy of Arts and Sciences and Past President of the American Finance Association. He was Taussig Research Professor at the Harvard University of Cambridge from 2005 to 2006 and from 2014 to 2015; Assistant, Associate and Full Professor of Finance “Robert C. McCormack Professor of Entrepreneurship and Finance” at the University of Chicago Booth School of Business from 1992 to 2005; Director of the American Finance Association from 2005 to 2008; Member of the United Nation Commission on Microfinance from 2006 to 2007; Director of Telecom Italia SpA from 2007 to 2014 and Lead Independent Director of Telecom Italia SpA from 2011 to 2014. He is also author of many publications in economic and financial matters.

> Senior Management

The table below sets forth the composition of Eni’s Senior Management as at December 31, 2014. 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 in compliance with the new organizational structure, approved by the Board of Directors on May 28, 2014 and in effect as from July 1, 2014.

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Name |  | Management position |  | Year first appointed to current position |  | Total number of years of service at Eni |  | Age
Claudio Descalzi |  | General Manager of Eni |  | 2014 |  | 34 |  | 60
Marco Alverà |  | Chief Midstream Officer (1) |  | 2013 |  | 10 |  | 39
Luca Bertelli |  | Chief Exploration Officer |  | 2014 |  | 30 |  | 56
Roberto Casula |  | Chief Development, Operations & Technology Officer |  | 2014 |  | 26 |  | 52
Claudio Granata |  | Chief Services and Stakeholder Relations Officer |  | 2014 |  | 31 |  | 54
Massimo Mantovani |  | Chief Legal & Regulatory Affairs (2) |  | 2005 |  | 21 |  | 51
Massimo Mondazzi |  | Chief Financial and Risk Management Officer (3) |  | 2012 |  | 23 |  | 51
Salvatore Sardo |  | Chief Downstream & Industrial Operations Officer (4) |  | 2014 |  | 10 |  | 62
Antonio Vella |  | Chief Upstream Officer |  | 2014 |  | 31 |  | 57
Marco Petracchini |  | Internal Audit Department (5) Senior Executive Vice President |  | 2011 |  | 16 |  | 50
Roberto Ulissi |  | Board Secretary and Corporate Governance Counsel (6) Corporate Affairs and Governance Department Senior Executive Vice President |  | 2006 |  | 9 |  | 52
Angelo Zaccari |  | Retail Market G&P Department Senior Executive Vice President |  | 2014 |  | 6 |  | 61
Rita Marino (7) |  | Procurement Department Executive Vice President |  | 2014 |  | 9 |  | 50
Camilla Alessandra Palladino (8) |  | Media Relations Senior Vice President |  | 2014 |  | 8 |  | 36
Pasquale Salzano |  | Government Affairs Department Senior Vice President (9) |  | 2014 |  | 3 |  | 41

(1) |  | Since February 19, 2015, he has been Chief Midstream Gas & Power Officer.
(2) |  | Prior to July 1, 2014, he was General Counsel Legal Affairs Senior Executive Vice President.
(3) |  | Prior to July 1, 2014, he was Chief Financial Officer.
(4) |  | Since February 19, 2015, he has been Chief Refining & Marketing and Chemicals Officer.
(5) |  | The Senior Executive Vice President of the Internal Audit Department reports hierarchically and functionally 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).
(6) |  | Since 2006, he has been the Board Secretary and since 2014, he 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.
(7) |  | Prior to July 1, 2014, she was Executive Vice President of the Procurement Department, but she did not report to the Chief Executive Officer.
(8) |  | Until February 19, 2015. Since February 19, 2015, Marco Bardazzi has been assigned the position of External Communication Department Executive Vice President and the Media Relations function was abolished.
(9) |  | Since February 19, 2015, he has been Eni’s Executive Vice President Government Affairs Department.

The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief Midstream Officer7, the Chief Downstream & Industrial Operations Officer8, the Senior Executive Vice President Retail Market G&P Department, the Chief Financial and Risk Management Officer, the Chief Services & Stakeholder Relations Officer, the Chief Legal & Regulatory Affairs, 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 Procurement Department, the Senior Vice President Media Relations9, the Senior Vice President Government Affairs10 and the Chief Executive Officer of Versalis SpA are members of the Management Committee, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend

(7) |  | Since February 19, 2015, he has been Chief Midstream Gas & Power Officer.
(8) |  | Since February 19, 2015, he has been Chief Refining & Marketing and Chemicals Officer.
(9) |  | Since February 19, 2015, the membership has been assigned to External Communication Department Executive Vice President also in consideration of the fact that Media Relation function was abolished.
(10) |  | Since February 19, 2015, he has been Eni’s Executive Vice President Government Affairs Department.

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meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of Committee Secretary are performed by the Senior Executive Vice President Corporate Affairs and Governance.

The Chief Financial and Risk Management 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

Marco Alverà was born in New York in 1975. Graduated in Philosophy and Economics from the London School of Economics in 1997, he is currently an Associate Fellow at the Oxford University Centre for Corporate Reputation. He began his career at Goldman Sachs in London in 1996, working in M&A and Private Equity. In 2000, he founded Netesi, Italy’s first broadband ADSL company. From 2002 to 2005, he worked at Enel as Director of Group Corporate Strategy, becoming Chief Financial Officer of Wind Telecom in 2004 and overseeing the sale of Wind to Orascom. He joined Eni in 2005 as Assistant to the Chief Executive Officer for special projects. In 2006, he was appointed Director of Supply & Portfolio Development at Eni’s Gas & Power Division and Chief Executive Officer of Bluestream and Promgas. In 2008, he moved to Eni’s Exploration & Production Division as Executive Vice President for Russia, North Europe and North and South America. In these countries he managed operations and led negotiations with governments and other international oil companies. Since 2010, he has been Chief Executive Officer of Eni Trading and Shipping SpA, which manages all the commodity Trading and Shipping activities for Eni. In January 2012, he was appointed Senior Executive Vice President of Eni Trading and, in March 2013, Senior Executive Vice President of Optimization and Trading. In July 2013, in his role as Senior Executive Vice President, he took on responsibility for the business unit Midstream, which brings together all of the commodity supply and trading activities, the development and optimization of the assets portfolio, the integrated management of commodity risks, the commercial development of the LNG portfolio and large gas & power accounts, the management and development of gas transport assets and primary logistics. He has also been a Board member of Gazprom Neft and since July 2014, a Board member of Eni Foundation. Since July 1, 2014, he has been Eni’s Chief Midstream Officer. Since February 19, 2015, he has been Chief Midstream Gas & Power Officer.

Luca Bertelli was born in Sesto Fiorentino in 1958. He graduated cum laude 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 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 and 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, 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

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Executive Vice President of Eni’s Exploration & Production Division and extended his responsibilities to include the whole of Africa and the Middle East and coordinating the Mozambique program for the development of the Mamba and Coral discoveries. Since July 2014, he has been a Board member of Eni Foundation. Since July 1, 2014, he has been Eni’s Chief Development, Operations & Technology Officer.

Claudio Granata was born in Rome in 1960. Graduated in economics, he joined the Eni Group in 1983. From 1983 to 1994, he worked as a labor 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 Exploration & Production 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 Exploration & Production Division, 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. Since July 2014, he has been a Board member of 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 Milan in 1963. He graduated in Law from the University of Milan and has a Master in Law (LLM) from the University of London. He was admitted to practice law in Italy as Avvocato and in England as Solicitor. He practiced law at a number of Legal offices in Milan and London for around 5 years and joined Eni’s Legal Department in 1993 where he was mostly involved in international issues. In October 2005, he was appointed Eni’s Senior Executive Vice President Legal Affairs, since when he has also been a member of the Company’s Supervisory Board. He is a member of the ICC Paris corporate responsibility and anti-corruption commission and, since 2011, he has been involved in the work of the B20 anti-corruption group. He was a member of the Board of Snam SpA11 from 2005 to 2012 and of University of Bologna from 2011 to 2012. He is the author of numerous publications and he also carries out teaching activities. Since July 1, 2014, he has been Eni’s Chief of Legal and Regulatory Affairs.

Massimo Mondazzi was born in Monza in 1963. He graduated in Economics and Business Administration from Bocconi University in 1987 and he joined Eni in 1992, after a number positions in industrial companies as a management consultant. He worked in the Administration and Control area of the Exploration & Production Division until 2006, where he reached the level of Director. From 2006 to 2009, he was the Director of Planning and Control for the Eni Group, before returning to the Exploration & Production Division as the 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 & 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 Manager charged with preparing Company’s financial reports pursuant to Article 154-bis of Italian Legislative Decree No. 58/1998. Since July 1, 2014, he has been Eni’s Chief Financial and Risk Management Officer.

Salvatore Sardo was born in Turin in 1952. He graduated in economics from the University of Turin. He is also a chartered Auditor. From September 1976 to 1981, he worked for Coopers & Lybrand as an auditor, rising to the level of supervisor. In 1981, he moved to Stet where he was initially responsible for management control for manufacturing activities, becoming central co-director in 1992 and, from 1996, Central Director of Planning & Control. In 1997, he joined Telecom Italia as Deputy General Manager of Administration & Control and from 1998 to June 2001, he was chairman of Seat Pagine Gialle SpA. From October 1999, he was operational head of Telecom Italia’s Real Estate Department, Chairman of EMSA, Chairman and Managing Director of EMSA Servizi and Chairman and Managing Director of IMMSI, a company listed on the Milan stock exchange, as well as Operating Chairman of TELIMM, IMSER and Telemaco, companies in the same sector. From October 1, 2001, he was head of the Real Estate and General Services unit of the Telecom Italia Group, reporting directly to the Chief Executive, and from November 2000, he was head of the Telecom Italia Real Estate and Service BU. In February 2003, he joined Enel as Head of Group Procurement, Services and Security, reporting directly to the Chief Executive. He joined Eni in 2005 as Director of Human Resources and Business Services, reporting directly to the Chief Executive, and also overseeing the operational guidelines and control of the Information & Communication Technology unit and the EniServizi subsidiary. From November 2008 to June 2014, he was appointed Eni’s chief corporate operations officer, reporting directly to the Chief

(11) |  | Until January 1, 2012, the company name was Snam Rete Gas SpA.

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Executive, overseeing the operational guidelines and control of procurement, Human Resources and Organization, Information & Communication Technology, Health, Safety, Environment & Quality, Security, Compensation & Benefits and the EniServizi subsidiary. From April 2009 to November 25, 2014, he was also appointed Chairman of Eni Corporate University. From April 2010 to October 2012, he was Chairman of Snam. From April 2013 to July 2014, he was a member of the Board of the Eni Foundation. In April 2013, he was appointed Chairman of Versalis From April 2008 to April 2011, he was a member of the Board and member of the Remuneration Committee of Saipem. On June 2, 2008, he was made a Commendatore dell’Ordine al Merito della Repubblica Italiana and on July 8, 2011, a Grande Ufficiale dell’Ordine al merito della Repubblica Italiana, two of the Country’s highest institutional honors. He has also been a standing statutory auditor of Italtel, Finsiel and Telecom Italia. From July 2014 to February 2015, he was Eni’s Chief Downstream & Industrial Operations Officer, reporting directly to the Chief Executive Officer. Versalis, Syndial and EniPower report to the Chief Downstream & Industrial Operations Officer. Since February 19, 2015, he has been Chief Refining & Marketing and Chemicals Officer.

Antonio Vella was born in 1957. He is currently Chief Upstream Officer of Eni SpA. From December 2012 to May 2014, Antonio Vella held the position of Eni Exploration & Production Division Executive Vice President Central Asia, Far East and Pacific Area. In 2009, he was appointed Executive Vice President Operations of Eni Exploration & Production Division. From 2006 to 2009, he was Regional Senior Vice President North Africa and Middle East Area (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) of Eni Exploration & Production Division. From 2002, he was Regional Vice President for Australasia, Russia, Azerbaijan and then in 2005 Board Member & Managing Director of Eni Algeria. In 1999, he held the position of District General Manager of Nigerian Agip Oil Co (NAOC), and in 2000, he became Vice Chairman and Managing Director of NAOC, NAE (Nigerian Agip Exploration) and AENR (Agip Energy), Eni’s affiliated companies in Nigeria. In 1991, he was appointed Project Manager for the development of the Libyan fields, and in 1993, he moved to Egypt first as Operations Manager and then as General Manager and Managing Director of Petrobel in charge of all Eni upstream operations in Egypt. From 1988 to 1991, he worked as Project Manager in EniChem’s petrochemical plants and refineries in Italy. Antonio Vella joined the Eni Group in 1983, where he started his professional career as Petroleum Engineer in Agip Name, a subsidiary of the Eni Group in Libya, in onshore and offshore upstream operations. Antonio Vella graduated in Petroleum Engineering from the Polytechnic of Turin in 1982.

Marco Petracchini was born in Rome in 1964. He graduated Cum Laude 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. 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 was also a member of numerous Italian and European committees representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law (Commission "Vietti") and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also Special Professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel.

Angelo Zaccari was born in Naples in 1953. He has a degree in political science and after extensive experience in the oil business, in refining, supply, sales and international trading at Mobil Oil, from December 2003 to September 2006, he was marketing and sales Director and Chief Executive of Edison Energia, with responsibility for sales of natural gas and electricity. From October 2006 to April 2007, he was head of fuel procurement at Alitalia, with responsibility for a new Business Unit reporting directly to the Chairman and Chief Executive. From May 2007 to August 2008, he was Director of the market division and Chief Executive of Enìa Energia, with responsibility for sales, marketing, procurement, risk management and development of the company formerly own by the municipalities of Piacenza, Parma and Reggio Emilia. In September 2008, he was hired by Eni in the Gas & Power Division as Director of the Retail and Power Department, with responsibility for the management and development of Gas & Power sales activities for the Italian retail market and marketing. Since 2009, he continued his experience in the Gas & Power sector as market director for Italy, with responsibility for the management and development of all commercial activities and, from March 2013, as Executive Vice President of the Gas & Power Retail and Mid Market Europe Department. Since July 1, 2014, he has been Eni’s Senior Executive Vice President Retail Market Gas & Power Department.

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Rita Marino was born in Salerno in 1964. Graduated with honors in Economics from LUISS Guido Carli University in Rome in 1987, she gained twenty-five years of experience in major national industrial groups. In 2011, she was appointed Head of Procurement at Eni, after having served, since 2005, as Internal Audit Director, Internal Control Officer and Secretary of the Internal Control Committee. From 1987 to 2002, she held various positions in the Telecom Italia group, in the Planning and Management Control and Mergers & Acquisitions departments. Appointed Director in 1997, that same year she served on the team working on the privatization of Telecom Italia, and in 1999 she was the team’s M&A point of reference to counter the takeover bid for Telecom Italia launched by Olivetti. From 2003 to 2005, she worked in Enel as Manager of the Strategies, Control and Procurement Processes Department, as well as Chief Operating Officer of a company in the group. Between 2000 and 2005, she served as a member of the Board of Directors of various Telecom Italia and Enel group companies. From 2005 to 2010, she served on the Supervisory Board of Eni, and from 2009 to 2010, she was also a Board member of Associazione Italiana Internal Auditor (AIIA). Since April 2013, she is a Board member of Syndial. In 2010, she won the Bellisario "Woman Manager" prize, and since 2011, she has been on the list of "Ready For Board Women". Since July 1, 2014, she has been Eni’s Executive Vice President Procurement Department.

Camilla Alessandra Palladino was born in Milan in 1978. Graduated in modern history and English at the University of Oxford in 1999. From 2001 to 2006, she was a journalist in London at Breakingviews.com, a financial comment and analysis service syndicated across a number of European newspapers, including the Wall Street Journal Europe and La Repubblica. She joined Eni in 2006 as head of Internal Communications. From November 2010 to September 2013, she was Senior Vice President Investor Relations, with responsibility for providing mandatory financial information and relations with investors. Since October 1, 2013, she has been Eni’s Senior Vice President Media Relations.

Pasquale Salzano was born in Pomigliano d’Arco (Naples) in 1973. In 1996, he graduated with Honors 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. From July 2012, he was Vice President, International Institutional Relations within the Office for Institutional and Regulatory Affairs. 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, he was Eni’s Senior Vice President Government Affairs. Since February 19, 2015, he has been Eni’s Executive Vice President Government Affairs Department.

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 considering relevant proposals made by the Compensation Committee and 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 responsibilities12.

(12) |  | 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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The main elements of the 2015 remuneration policy and of the compensation paid in 2014 to the Chairman, the CEO, other Board members and Eni’s Chief Operating Officer and of other Managers with strategic responsibilities, are described below.

> 2015 Remuneration Policy Guidelines

The guidelines for the 2015 Remuneration Policy for Executive Directors reflect the decisions made by the Board of Directors on May 28, 2014 following the renewal of the corporate bodies, based on the shareholders’ resolutions of May 8, 2014 reducing remuneration under Article 84-ter of Law No. 98/2013 and approving the 2014-2016 Long-Term Monetary Incentive Plan under Article 114-bis of Legislative Decree No. 58/1998.

For Managers with strategic responsibilities, the 2015 Guidelines provide for the same instruments used in 2014 and in particular the short and long-term incentive plans strictly in line with those of Chief Executive Officer and General Manager, to better guide and align managerial actions with the targets defined in the Company’s Strategic Plan.

> Market references

The market references used for remuneration benchmarks are: (i) for the Chairman, Non-executive Directors and the Chief Executive Officer and General Manager, similar roles in the main international companies in the Oil sector, as well as in the national and European listed companies of greatest capitalization; and (ii) for Managers with strategic responsibilities, the roles with the same level of responsibility and managerial complexity in large national and international industrial companies.

> General principle of clawback

A clawback mechanism will be adopted, through a specific regulation, allowing to reclaim the variable remuneration components already paid, or to withhold those subject to deferral, whose achievement took place on the basis of data that subsequently proved to be manifestly misstated, or allowing the recoupment of all the incentives of the year (or the years) for which fraudulent alteration was detected in the results data used in order to achieve 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.

> CHAIRMAN OF THE BOARD OF DIRECTORS AND NON-EXECUTIVE DIRECTORS

> Chairman of the Board of Directors

Remuneration of the Chairman for the delegated powers
The Policy Guidelines for the Chairman of the Board of Directors reflect the decisions taken by the Board of Directors on May 28, 2014, which defined a fixed remuneration for the delegated powers amounting to euro 148,000, in addition to remuneration for the position determined by the Shareholders’ Meeting on May 8, 2014, amounting to euro 90,000, in compliance with the maximum of euro 238,000 defined by the same Shareholders’ Meeting. These Guidelines do not provide for variable remuneration.

Payments due in the event of termination of office or employment
No specific term end payments are envisaged for the Chairman, nor do any agreements exist for indemnities in the case of early termination of the mandate.

Benefits
For the Chairman, the Remuneration Policy Guidelines provide, in line with the decisions taken by the Board of Directors on May 28, 2014, insurance coverage for the risk of death and permanent disability.

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> Non-executive Directors

Remuneration for participation in Board Committees
The Board of Directors Meeting of May 9, 2014 confirmed the maintenance of an additional annual remuneration13 for Non-executive and/or Independent Directors for participating in Board Committees, to the following extent:

• |  | for the Control and Risk Committee, the remuneration amounts to euro 45,000 for the Chairman and euro 35,000 for the other members; and
• |  | for the Compensation Committee, the Sustainability and Scenario Committee and the Nomination Committee the remunerations amount to euro 30,000 for the Chairman and euro 20,000 for the other members.

The Policy Guidelines subsequently approved by the Board on March 12, 2015 provide for, in relation to the growing and significant commitment required of Committee members and to the results of the remuneration benchmarks, the increase in remuneration for participation in the Control and Risk Committee, proposing a remuneration of euro 60,000 for the Chairman and euro 40,000 for the other members, and the elimination, starting in 2015, of the criterion of remuneration reduction by 10% set forth in the 2014 Policy in the case of participation in several Committees, a reduction that was not objectively justified by the mode of performance of multiple roles.

Payments due in the event of termination of office or employment
No specific payments are provided for the term end of non-executive Directors nor do any agreements exist that provide for indemnities in the case of early termination of the mandate.

> CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER

For the Chief Executive Officer and General Manager, the remuneration structure in 2015 defined by the Board of Directors for a full term takes into account the specific powers delegated in accordance with the Articles of Association, and with principles and general purposes of Eni Remuneration Policy, as well as the 25% reduction of the maximum payable overall remuneration of the previous mandate, in accordance with the Shareholder’s 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 the May 8, 2011, as well as any compensation that may be due for participating in the Board of Directors of Eni’s subsidiaries or associated companies.

Fixed remuneration
The total fixed remuneration is set at a gross annual amount equal to euro 1,350,000, of which euro 550,000 for the position of Chief Executive Officer and euro 800,000 for the position of General Manager.

In his capacity as Eni Senior Manager, the General Manager is also entitled to receive an indemnity 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 2015 annual variable incentive Plan is linked to the achievement of the predefined targets for 2014 as described in the 2014 Remuneration Report, measured according to a performance scale 70÷130, 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, the minimum overall performance is 85 points. This Plan provides for remuneration calculated pro-rata based on the time in office in 2014, with reference to a minimum incentive level (performance = 85), target (performance = 100) and maximum (performance = 130), respectively equal to 85%, 100% and 130% of the total fixed remuneration, in connection to the results achieved by Eni in the previous year.

The 2015 targets approved by the Board Meeting of March 12, 2015 for the 2016 annual variable incentive Plan provide for a structure focused on the essential goals, consistent with the strategies outlined for the new term and balanced against the prospects of interest to 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%).

(13) |  | This remuneration supplements the one established by the Shareholders’ Meeting of May 8, 2014, for the remuneration of Non-executive Directors, amounting to euro 80,000 annual gross.

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Long-term variable incentives
The long-term variable component consists of two distinct plans:

• |  | Deferred Monetary Incentive Plan (DMI), also envisaged for all the managers of the Company, with three annual assignments, starting in 2015 and linked to the Company performance measured in terms of Earnings Before Taxes (EBT). The conditions of the Plan include in particular: (i) incentive to be given each year based on the EBT results achieved by the Company in the previous year, measured on a performance scale 70÷130, for a minimum, target and maximum value, respectively equal to 34.4%, 49.2% and 64% of the total fixed remuneration. If the results are below the minimum level of performance, no assignment is made; and (ii) the incentive to be paid at the end of the three-year vesting period set on the basis of the average annual EBT results achieved during the vesting period, as a percentage between zero and 170% of the assigned value, according to a scale between 70% and 170%. Where results are below the minimum level of 70%, the performance is considered to be zero.
• |  | Long-Term Monetary Incentive Plan (IMLT), approved by the Shareholders’ Meeting of May 8, 2014, also provided for managerial resources critical to the business, with three annual assignments from 2014 and linked to the performance parameters measured in relative terms compared to the peer group of reference. These parameters, in line with international best practices, are designed to ensure greater alignment with the interests of shareholders in the medium to long term, through the use of the "Total Shareholder Return"14, and a more sustainable value creation in the medium to long term, through the use of the "Net Present Value" of proved reserves. The conditions of the Plan include, in particular: (i) incentive to be given every year equal to 100% of the overall fixed remuneration; and (ii) incentive to be paid at the end of the three-year vesting period determined in relation to the results achieved in terms of variation of the identified parameters (TSR with a weighting of 60% and NPV of proved reserves15 with a weighting of 40%) in the three-year period in question in relative terms compared to a peer group consisting of the following international oil companies: Exxon, Chevron, Shell, BP, Total and Repsol. The amount to be paid is defined as a percentage of the amount assigned according to the average annual placements achieved during the vesting period, compared with those achieved by the companies in the peer group according to the following scale: 1st place = 130%; 2nd place = 115%, 3rd place = 100%; 4th place = 85%; 5th place = 70%; 6th and 7th place = 0%. The minimum incentive threshold involves reaching 5th place for both indicators in at least one year of the three-year vesting period.

Both Plans envisage that, should the current office not be renewed, the payment of each incentive assigned will occur at the natural expiry of the related vesting period, in accordance with the performance conditions defined in the Plan.

Treatments established in the event of termination of office or employment
For the Chief Executive Officer and General Manager, in line with the practices of reference 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 following payments are provided for:

• |  | upon termination of the management employment relationship, due to non-renewal or early termination of the 2014-2017 administrative mandate, even for resignations caused by a reduction of delegated powers, there is a provision to pay an indemnity supplementing the severance pay, with mutual exemption from notice, of two years of total fixed remuneration (equal to euro 1,350,000), for a total gross amount equal to euro 2,700,000. Also with reference to the recommendation in criterion 6.C.1 subparagraph g) of the Corporate Governance Code, it is stated that, in relation to the applicable contractual provisions, such compensation is not paid 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 mandate, not justified by an essential reduction of delegated powers, as well as in the event of death governed by Article 2122 of the Italian Civil Code; and
• |  | non-competition agreement that can be activated by the Board of Directors through an option right, to be exercised within a possible second administrative term, against a specific consideration of euro 500,000 gross to be paid in three annual installments. If the option is exercised by the Board and the agreement is implemented, the consideration is paid against a commitment undertaken by the Chief Executive Officer and General Manager not to perform, for the twelve months following the expiry of the mandate, any activities of Exploration & Production that could be in competition with Eni in key markets worldwide. This amount will be set by the Board of Directors to a linearly varying degree from euro 1,500,000 to a maximum of euro 2,250,000 based on the performance of the previous three years, making reference to the total annual remuneration, and will be paid at the expiry of the term of the agreement. Any violation of the non-competition agreement will involve the non-payment of the consideration (or its restitution, where the violation has come to Eni’s awareness after the payment), and the obligation to pay damages consensually and conventionally set at an amount equal to twice the amount of the non-competition agreement, without prejudice to Eni’s right to seek fulfillment in specific form.

(14) |  | The Total Shareholder Return (TSR) is an indicator that measures the overall return of a stock investment, taking into consideration both the price change and the dividends paid and reinvested in the same stock, in a specific period.
(15) |  | The Net Present Value is an indicator that represents the present value of the future cash flows of proved hydrocarbon reserves, net of future production and development costs and related taxes. It is calculated on the basis of standard references defined by the Securities Exchange Commission on the basis of the data published by the oil companies in the official documentation (Form 10-K and Form 20-F).

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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 in compliance with what is provided for in the national collective labor agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the complementary pension plan (FOPDIRE), as well as in the supplementary health plan (FISDE) are also provided, together with a company car for business and personal use.

> OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES

Fixed remuneration
The fixed remuneration is based on the assigned role and responsibilities, taking into consideration a graduated and possibly inferior positioning compared to the limits set by the median references of the national and international executive markets for roles with similar levels of managerial responsibility and complexity, and it may be updated periodically during the annual salary review that involves all managerial resources.

The 2015 Guidelines, in consideration of the context of reference and current market trends, provide for selective criteria, while maintaining appropriate levels for competitiveness and motivation. In particular, the proposed actions will cover measures to adapt the selective fixed/one-off for holders of positions that have increased the scope of responsibility or the level of coverage of the role, and in consideration of retention needs and excellent quality performance.

In addition, as Eni officers, the Managers with strategic responsibilities are entitled to receive the indemnities due for travel in Italy and abroad, in line with the applicable provisions of the relevant national collective labor agreement for senior managers and in the corporate complementary agreements.

Annual variable incentives
The annual variable incentive Plan provides for remuneration to be awarded in 2015, calculated with reference to Eni performance results, for the business areas and individuals, achieved in the previous year and measured in accordance with a performance scale of 70÷130 with a minimum incentive level equal to 85 points, below which no incentive is due, as already described for the Chief Executive Officer and General Manager. The target incentive level (performance = 100) differs by up to a maximum of 60% of the fixed remuneration, based on the role.

The targets of the Managers with strategic responsibilities are based on those assigned to the Senior Management and are focused for each business area on the economic/financial, operational and industrial performance, on internal efficiency and on sustainability issues (in terms of health and safety, environmental protection, stakeholder relations), as well as on individual targets assigned in relation to the scope of responsibilities of the role, consistent with the provisions of the Company’s Strategic Plan.

Long-term variable incentives
The Managers with strategic responsibilities, in line with the provisions for the Chief Executive Officer, participate in the 2015-2017 Deferred Monetary Incentive Plan (IMD) approved by the Board of Directors on March 12, 2015 and in the 2014-2016 Long-Term Monetary Incentive Plan ( IMLT) approved by the Board of Directors on February 12, 2014 and by the Shareholders’ Meeting on May 8, 2014. In particular, the Plans have the following characteristics:

• |  | 2015-2017 Deferred Monetary Incentive Plan, designed solely for the managerial resources who have delivered the performance results established in the annual Variable Incentive Plan (threshold target). The Plan provides for three annual assignments, starting in 2015, with the same performance conditions and characteristics as those described above for the Chief Executive Officer and General Manager. For the Managers with strategic responsibilities, the incentive to be assigned each year is set in relation to the EBT results achieved by the Company in the previous year, measured on a performance scale of 70÷130. The target incentive level differs, based on the role, by up to a maximum of 40% of the fixed remuneration. The incentive to be paid at the end of the three-year vesting period is determined on the basis of the average annual EBT results achieved during the three-year period, as a percentage between zero and 170% of the assigned value; and
• |  | 2014-2016 Long-Term Monetary Incentive Plan, scheduled for the managerial resources critical for the business with three annual assignments, starting in 2014, with the same performance conditions and characteristics already described for the Chief Executive Officer and General Manager. For the Managers with strategic responsibilities, the incentive to be assigned each year differs depending upon the level of the role up to a maximum of 75% of the fixed remuneration. The incentive to be paid at the end of the three-year vesting period is set in relation to the results of the identified parameters (TSR with a weighting of 60% and

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|  | NPV of proved reserves with a weighting of 40%) in the three-year period in question in relative terms compared to the peer group, as a percentage between zero and 130% of the assigned value.

Both Plans include clauses aimed at promoting employee retention, envisaging, in the case of consensual contract termination or transfer and/or loss of control on the part of Eni of the company of which the individual in question is an employee during the course of the vesting period, that the employee in question maintains the right to the incentive in a smaller measure based on the period between the assignment of the incentive and the occurrence of these events and in relation to the actual results for the period; no payment is envisaged in the case of unilateral termination of employment.

Payment due in the event of termination of employment
For Managers with strategic responsibilities, as for Eni Senior Managers, the payment due for employment termination as per the relevant national collective labor agreement is envisaged, together with any other additional severance indemnity agreed upon on an individual basis upon termination, according to the criteria established by Eni for cases of early resolution and/or retirement. These criteria take into account the retirement age and the actual age of the manager at the time when the 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, non-competition agreements may also be entered into with payments defined in relation to the remuneration received and the conditions of duration and efficacy of the agreement.

Benefits
For Managers with strategic responsibilities, in line with the policy implemented in 2014 and in line with what is provided for in the national collective labor agreement and the complementary company level agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE), as well as in the complementary health plan (FISDE), 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 2015 Remuneration Policy Guidelines lead to a remuneration mix in line with the managerial role held, with greater weight placed upon the variable component, in particular in the long term, for roles characterized by a greater impact on Company results, as highlighted in the pay-mix diagram below, calculated by considering the value of short and long-term incentives offered for results within the target values.

> COMPENSATION AND OTHER INFORMATION

> Implementation of the 2014 remuneration policies

There follows a description of the remuneration decisions taken in 2014 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, Chief Operating Officers of Eni’s Divisions, and other Managers with strategic responsibilities, in relation to their time in office.

The implementation of the 2014 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 2014 Remuneration Policy, approved by the Board of Directors on March 17, 2014, as further provided for by the resolutions passed by the Board of Directors on May 9 and 28, 2014 on the remuneration of Non-executive Directors called to be part of the Board Committees and on the definition of the remuneration of Executive Directors, in accordance with the resolutions passed at the Shareholders’ Meeting in accordance with Law No. 98/2013.

> Directors in office until May 8, 2014

> Chairman of the Board of Directors - Giuseppe Recchi

Fixed compensations
The Chairman Giuseppe Recchi was paid a fixed remuneration, pro-rated until May 8, 2014, approved, for the office and in relation to the delegated powers, respectively by the Shareholders’ Meeting of May 5, 2011 and by the Board of Directors Meeting of June 1, 2011.

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Variable compensation set by shareholders
In 2014, according to what was verified by the Board of Directors on March 17, 2014 as proposed by the Compensation Committee, the conditions required to pay the variable component of the remuneration approved by the Shareholders’ Meeting of May 5, 2011 to the Chairman were not met.

Annual variable incentives
In 2014, as verified by the Board of Directors on March 17, 2014 as proposed by the Compensation Committee, an actual performance of 114 points earned the outgoing Chairman Giuseppe Recchi the payment of a bonus equal to 68.4% of the fixed remuneration, equal to a gross amount of euro 342,000, taking into account the target (60%) and maximum (78%) levels of incentive assigned.

Severance indemnity for end of office or termination of employment
No severance indemnities for end of office were resolved in favor of the Chairman.

Benefits
Forms of welfare insurance coverage, including for risk of death and permanent disability were recognized in favor of the Chairman Giuseppe Recchi, in office until May 8, 2014.

> Non-executive Directors

Outgoing Directors were paid the pro-rated fixed remunerations resolved by the Shareholders’ Meeting on May 5, 2011, as well as additional remunerations payable for participation in the Board Committees, as resolved by the Board of Directors on June 1, 2011.

According to that which was verified by the Board of Directors on March 17, 2014 as proposed by the Compensation Committee, the conditions required to pay the variable component of the remuneration approved by the Shareholders’ Meeting of May 5, 2011 were not met.

> Chief Executive Officer and General Manager - Paolo Scaroni

Fixed compensations
The Chief Executive Officer and General Manager Paolo Scaroni, in office until May 8, 2014, was paid the pro rated fixed remunerations approved by the Board of Directors Meeting of June 1, 2011, which absorb the remunerations approved by the Shareholders’ Meeting for the Directors.

Annual variable incentives
The 2014 annual incentive was paid, based on the actual results regarding the targets set for 2013 in line with the Strategic Plan and the annual budget, assessed on a constant basis and approved by the Board, as proposed by the Compensation Committee, at its meeting on March 17, 2014. The approved figures led to determining a performance score of 112 points in the measurement scale used, which provides for target and maximum performance levels of 100 and 130 points, respectively.

For the purposes of the variable remuneration, the actual performance determined for the Chief Executive Officer and General Manager Paolo Scaroni the payment of a bonus equal to 128% of the gross annual fixed remuneration, amounting to euro 1,430,000, given the target (110%) and maximum (155%) incentive levels assigned, for a gross amount of euro 1,831,000.

Deferred Monetary Incentive Plan
The Board of Directors, at its meeting of March 17, 2014, based on verification and a proposal made by the Compensation Committee, resolved the achievement of a 2013 EBITDA result (measured on a constant basis) below the target level, which determines for the 2014 assignment the application of a 70% multiplier to the defined target percentage (55% of the fixed remuneration).

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For the outgoing Chief Executive Officer and General Manager Paolo Scaroni, the Board ruled to assign a 2014 incentive (third and last assignment) equal to euro 550,500.

The deferred monetary incentive assigned in 2011 therefore reached maturity in 2014, based on Eni’s actual EBITDA results during the 2011-2013 period, and as proposed by the Compensation Committee, the Board of Directors at its Meeting of March 17, 2014 approved the multiplier to be applied to the amount assigned, for the purposes of calculating the amount to be paid. This was set at 110%. As a result, an incentive of euro 865,000 was paid to the Chief Executive Officer (equal to 110% of the base incentive of euro 786,500 assigned in 2011).

Long-Term Monetary Incentive Plan
In 2014, the Long-Term Monetary Incentive assigned in 2011 to the Chief Executive Officer and General Manager reached maturity. The Board of Directors, at its meeting of March 17, 2014, on the basis of the results related to the change in adjusted net profit + DD&A actually achieved in the period 2011-2013 and the annual placements with the peer group of reference, verified, as proposed by the Compensation Committee, the absence of the conditions for granting such an incentive.

Stock option Plans
Eni has not approved any stock option Plans since 2009. For more details on the existing Plans, please refer to the documents published in the “Governance” section of the Eni website and the information contained in the “Notes to the Financial Statements” in the 2014 Annual Report. The stock options assigned in 2008, the last assignment performed, were not exercised and expired on July 31, 2014 in relation to the end of the exercise period set in the Plan.

Severance indemnity for end of office or termination of employment
In connection with the expiry of the administrative term of office and at the time of the consequent consensual termination of the executive employment of Mr. Paolo Scaroni, the Board of Directors Meeting of April 28, 2014 reviewed the indemnities set to supplement the remuneration and entitlements by law (severance pay) and by contract, resolving upon, in accordance with the provisions of the 2014 Remuneration Policy, the payment of the following indemnities:

• |  | Additional indemnity to the severance pay with exemption from any notice obligation: total gross amount set at euro 5,202,000, as the sum of the fixed component amounting to euro 3,200,000 and the variable component linked to the average performance of the 2011-2013 period (average score of 120 points), calculated with reference to an amount of euro 2,002,000.
• |  | Term-end severance indemnity: gross amount equal to euro 748,376 set with reference to the fixed remuneration and 50% of the maximum variable remuneration provided for administrative employment to guarantee social security contributions and severance pay equal to that paid by Eni for management employment.

As for the non-competition agreement, any payment of the related gross consideration, set at euro 2,219,000, will be made only at the end of the term of the agreement, after verification of compliance with the relevant conditions.

As for the long-term incentives assigned during the term of office and still outstanding, in accordance with the provisions of the resolution of the Board of Directors on June 1, 2011, their disbursement will take place at the natural expiry, according to the general and performance conditions set for each Plan and on the basis of the related actual results that will from time to time be resolved by the Board of Directors on the basis of a verification and proposal of the Compensation Committee.

Based on a proposal by the Compensation Committee, the Board ordered the formalization of the consensual termination of the executive employment of Mr. Paolo Scaroni at the standard terms and conditions set forth in the employment resolutions for Eni executives.

Benefits
For the outgoing Chief Executive Officer and General Manager, the Policy Guidelines provide for insurance coverage for the risk of death or permanent disability, and in compliance with what is provided for in the national collective labor agreement and the supplementary company level agreements for Eni Senior Managers, enrolment in the complementary pension plan (FOPDIRE), as well as in the supplementary health plan (FISDE) are also provided, together with a company car for business and personal use.

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> Directors appointed on May 8, 2014

> Chairman of the Board of Directors - Emma Marcegaglia

Fixed compensations
The Chairman Emma Marcegaglia, appointed on May 8, 2014, was paid the pro-rated fixed remuneration approved for the office and in relation to the delegated powers, respectively by the Shareholders’ Meeting of May 8, 2014 and by the Board of Directors Meeting of May 28, 2014.

Benefits
The Chairman Emma Marcegaglia, appointed on May 8, 2014, was recognized forms of 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 new Directors were paid pro-rated fixed remuneration resolved strictly as a fixed amount by the Shareholders’ Meeting of May 8, 2014. Additional remuneration was also paid for participation in the Board Committees, as resolved by the Board of Directors Meeting of May 9, 2014, which confirmed the remuneration already set for the Control and Risk Committee and the other Board Committees, including the Nomination Committee, supplementing the provisions of the 2014 Remuneration Policy.

> Chief Executive Officer and General Manager - Claudio Descalzi

Fixed compensations
The Chief Executive Officer and General Manager Claudio Descalzi, appointed on May 9, 2014, was paid the pro-rated fixed remunerations approved by the Board of Directors Meeting of May 28, 2014, which also absorb the remunerations approved by the Shareholders’ Meeting for all the Directors16.

Annual variable incentives
To Claudio Descalzi, solely in relation to the previous role as COO of the Exploration & Production Division, the Company paid an annual monetary incentive determined in accordance with the Remuneration Policy defined for Chief Operating Officers of Eni’s Divisions and other Managers with strategic responsibilities and with the actual performance for 2013 of the Exploration & Production Division.

Deferred Monetary Incentive Plan
Claudio Descalzi, solely in relation to the previous role as COO of the Exploration & Production Division, was assigned the 2014 deferred monetary incentive, determined in accordance with the Remuneration Policy defined for Chief Operating Officers of Eni’s Divisions and other Managers With Strategic Responsibilities, as well as on the basis of the 2013 EBITDA results resolved by the Board of Directors. Furthermore, in 2014 the Deferred Monetary Incentive assigned in 2011 to Claudio Descalzi, as COO of the Exploration & Production Division, reached maturity.

Long-Term Monetary Incentive Plan
For the Chief Executive Officer and General Manager Claudio Descalzi, the Board of Directors at its meeting of September 17, 2014, as proposed by the Compensation Committee, approved the assignment of the 2014 incentive of the 2014-2016 Long-Term Monetary Incentive Plan equal to euro 1,350,000 (100% of the fixed remuneration).

In 2014, the Long Term Monetary Incentive assigned in 2011 to Claudio Descalzi also reached maturity, as COO of the Exploration & Production Division, for which, according to the figure approved by the Board of Directors, the performance conditions for payment have not been met.

(16) |  | Claudio Descalzi was also paid, until taking on the office of Chief Executive Officer of the Company, the fixed remuneration payable as COO of the Exploration & Production Division.

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Stock option Plans
The stock options assigned in 2008 to Claudio Descalzi, the last assignment performed, were not exercised and expired on July 31, 2014 in relation to the end of the exercise period envisaged by the Plan.

Consideration for the emption right of the Board of Directors for the activation of the non-competition agreement
In 2014, the first tranche was disbursed, amounting to euro 167,000 gross out of the euro 500,000 gross for the emption right at activation of the Agreement reserved for the Board of Directors.

Benefits
For the Chief Executive Officer and General Manager Claudio Descalzi appointed on May 9, 2014, in line with the resolution of the Board of Directors Meeting on May 28, 2014, insurance coverage was also recognized for the risk of death or permanent disability, and in compliance with what is provided for in the national collective labor agreement and the supplementary corporate agreements for Eni Senior Managers, enrolment in the complementary pension plan (FOPDIRE), as well as in the supplementary health plan (FISDE) are also provided, together with a company car for business and personal use.

> Chief Operating Officers of Eni’s Divisions and other Managers with strategic responsibilities

Fixed compensations
For the current Managers with strategic responsibilities, within the context of the annual salary review process envisaged for all managers, in 2014 selective adjustments were made to fixed remuneration, in cases of promotion to more senior levels, or in relation to the necessity to adjust remuneration levels with respect to the market references identified.

Annual variable incentives
In March 2014, annual monetary incentives were paid to the Division Chief Operating Officers and the other Managers with strategic responsibilities, as determined in accordance with the defined Remuneration Policy, with reference to the actual performance of 2013. In particular, the incentive is linked to business performance and a number of individual targets in relation to the scope of responsibilities of the role, consistent with the provisions of the 2013 Eni Performance Plan, and on the basis of economic and operational performance achieved by the respective business sectors, also considering the achievement of specific targets of sustainability (in terms of health and safety, environmental protection, and stakeholder relations).

Deferred Monetary Incentive Plan
For Division Chief Operating Officers and other Managers with strategic responsibilities, the assignment of the 2014 deferred monetary incentive was made, determined in line with the defined Remuneration Policy, and based on the 2013 EBITDA results approved by the Board of Directors that determined an assignment multiplier of 70% to be applied to the target incentive to be assigned (differentiated by role level up to a maximum of 40% of the fixed remuneration).

In 2014, the Deferred Monetary Incentive assigned in 2011 also reached maturity.

Long-Term Monetary Incentive Plan
For Chief Operating Officers of Eni’s Divisions and the other Managers with strategic responsibilities, the assigned amounts were determined in accordance with the target incentive level, differentiated by role level up to a maximum of 75% of the fixed remuneration. In 2014, the Long Term Monetary Incentive assigned in 2011 also reached maturity, for which, according to the figure approved by the Board of Directors, the performance conditions for payment have not been met.

Stock option Plans
The stock options assigned in 2008, the last assignment performed, were not exercised and expired on July 31, 2014 in relation to the end of the exercise period set in the Plan.

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Severance indemnity for end of office or termination of employment
During 2014, the Managers with strategic responsibilities who terminated their employment were paid, in order to supplement the legal and contractual dues, the amounts defined in line with the Company policy on early retirement incentives.

Benefits
For Managers with strategic responsibilities, in line with that which is provided for in the national collective labor agreement and the complementary corporate agreements for Eni Managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE), as well as in the complementary 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 2014

The individual amounts of compensation paid in 2014 to each member of the Board of Directors, to Chief Operating Officers and to each member of the Board of Statutory Auditors, as well as the overall amounts paid to other Managers with strategic responsibilities, are reported in the table below, pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications. 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 "Committee membership remuneration" 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, in accordance with that specified, in greater detail, in the Table "Monetary incentive Plans for Directors, General Managers, and other Managers with strategic responsibilities"; the column "Profit sharing" does not show any figures since there are no provisions for profit sharing;
• |  | based on the criteria of competence and taxability, the "Non-monetary benefits" 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;
• |  | 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.

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Remuneration paid to Directors, Statutory Auditors, Chief Operating Officers and other Managers
with strategic responsibilities

(euro thousand)

`Name` | `Notes` |  | `Office` |  | `Term of office` |  | `Office expiry` `(*)` |  | `Fixed remuneration` |  | `Committee membership remuneration` |  | `Bonuses and other incentives` |  | `Variable non-equity remuneration` |  | `Other remuneration` |  | `Total 2014` |  | `Fair value of equity remuneration` |  | `Severance indemnity for end of office or termination of employment`
`Profit sharing` |  | `Non-monetary benefits`

Board of Directors |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Giuseppe Recchi | (1) |  | Chairman |  | 01.01-05.08 |  | 05.2014 |  | 272 | (a) |  |  |  |  | 342 | (b) |  |  |  | 4 |  |  |  |  | 618 |  |  |  |  |
Emma Marcegaglia | (2) |  | Chairman |  | 05.08-12.31 |  | 05.2017 |  | 154 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 154 |  |  |  |  |
Paolo Scaroni | (3) |  | CEO and General Manager |  | 01.01-05.08 |  | 05.2014 |  | 505 | (a) |  |  |  |  | 2,696 | (b) |  |  |  | 8 |  |  |  |  | 3,209 |  |  |  | 8,361 | (c)
Claudio Descalzi | (4) |  | CEO and General Manager |  | 05.09-12.31 |  | 05.2017 |  | 874 | (a) |  |  |  |  |  |  |  |  |  | 9 |  | 500 | (b) |  | 1,383 |  |  |  |  |
|  |  | COO E&P Division (**) |  | 01.01-05.08 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

Remuneration in the company that prepares the Financial Statements |  | 273 | (c) |  |  |  |  | 1,218 | (d) |  |  |  | 4 |  |  |  |  | 1,495 |  |  |  |  |
Remuneration from subsidiaries and associates |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 479 | (e) |  | 479 |  |  |  |  |

|  | Total |  | 1,147 |  |  |  |  |  | 1,218 |  |  |  |  | 13 |  | 979 |  |  | 3,357 |  |  |  |  |

Carlo Cesare Gatto | (5) |  | Director |  | 01.01-05.08 |  | 05.2014 |  | 41 | (a) |  | 18 | (b) |  |  |  |  |  |  |  |  |  |  |  | 59 |  |  |  |  |
Paolo Marchioni | (6) |  | Director |  | 01.01-05.08 |  | 05.2014 |  | 41 | (a) |  | 17 | (b) |  |  |  |  |  |  |  |  |  |  |  | 58 |  |  |  |  |
Roberto Petri | (7) |  | Director |  | 01.01-05.08 |  | 05.2014 |  | 41 | (a) |  | 13 | (b) |  |  |  |  |  |  |  |  |  |  |  | 54 |  |  |  |  |
Alessandro Profumo | (8) |  | Director |  | 01.01-05.08 |  | 05.2014 |  | 41 | (a) |  | 16 | (b) |  |  |  |  |  |  |  |  |  |  |  | 57 |  |  |  |  |
Mario Resca | (9) |  | Director |  | 01.01-05.08 |  | 05.2014 |  | 41 | (a) |  | 16 | (b) |  |  |  |  |  |  |  |  |  |  |  | 57 |  |  |  |  |
Francesco Taranto | (10) |  | Director |  | 01.01-05.08 |  | 05.2014 |  | 41 | (a) |  | 18 | (b) |  |  |  |  |  |  |  |  |  |  |  | 59 |  |  |  |  |
Andrea Gemma | (11) |  | Director |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  | 49 | (b) |  |  |  |  |  |  |  |  |  |  |  | 101 |  |  |  |  |
Pietro Angelo Guindani | (12) |  | Director |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  | 29 | (b) |  |  |  |  |  |  |  |  |  |  |  | 81 |  |  |  |  |
Karina A. Litvack | (13) |  | Director |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  | 44 | (b) |  |  |  |  |  |  |  |  |  |  |  | 96 |  |  |  |  |
Alessandro Lorenzi | (14) |  | Director |  | 01.01-12.31 |  | 05.2017 |  | 92 | (a) |  | 59 | (b) |  |  |  |  |  |  |  |  |  |  |  | 151 |  |  |  |  |
Diva Moriani | (15) |  | Director |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  | 23 | (b) |  |  |  |  |  |  |  |  |  |  |  | 75 |  |  |  |  |
Fabrizio Pagani | (16) |  | Director |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  | 29 | (b) |  |  |  |  |  |  |  |  |  |  |  | 81 |  |  |  |  |
Luigi Zingales | (17) |  | Director |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  | 32 | (b) |  |  |  |  |  |  |  |  |  |  |  | 84 |  |  |  |  |

Board of Statutory Auditors

Ugo Marinelli | (18) |  | Chairman |  | 01.01-05.08 |  | 05.2014 |  | 40 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 40 |  |  |  |  |
Francesco Bilotti | (19) |  | Statutory Auditor |  | 01.01-05.08 |  | 05.2014 |  | 28 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 28 |  |  |  |  |
Paolo Fumagalli | (20) |  | Statutory Auditor |  | 01.01-05.08 |  | 05.2014 |  | 28 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 28 |  |  |  |  |
Renato Righetti | (21) |  | Statutory Auditor |  | 01.01-05.08 |  | 05.2014 |  | 28 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 28 |  |  |  |  |
Giorgio Silva | (22) |  | Statutory Auditor |  | 01.01-05.08 |  | 05.2014 |  | 28 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 28 |  |  |  |  |
Matteo Caratozzolo | (23) |  | Chairman |  | 05.08-12.31 |  | 05.2017 |  | 52 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 52 |  |  |  |  |
Paola Camagni | (24) |  | Statutory Auditor |  | 05.08-12.31 |  | 05.2017 |  | 45 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 45 |  |  |  |  |
Alberto Falini | (25) |  | Statutory Auditor |  | 05.08-12.31 |  | 05.2017 |  | 45 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 45 |  |  |  |  |
Marco Lacchini | (26) |  | Statutory Auditor |  | 05.08-12.31 |  | 05.2017 |  | 45 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 45 |  |  |  |  |
Marco Seracini | (27) |  | Statutory Auditor |  | 05.08-12.31 |  | 05.2017 |  | 45 | (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 45 |  |  |  |  |

Chief Operating Officers

Angelo Fanelli | (28) |  | R&M Division |  | 01.01-06.30 |  |  |  | 300 | (a) |  |  |  |  | 396 | (b) |  |  |  | 7 |  |  |  |  | 703 |  |  |  |  |

Other Managers with strategic responsibilities (***) | (29) |  | Remuneration in the company that prepares the Financial Statements |  | 5,945 |  |  |  |  |  | 5,777 |  |  |  |  | 161 |  | 120 |  |  | 12,003 |  |  |  | 4,990 |
|  | Remuneration from subsidiaries and associates |  | 737 |  |  |  |  |  | 115 |  |  |  |  | 261 |  | 47 |  |  | 1,160 |  |  |  |  |
|  | Total |  | 6,682 | (a) |  |  |  |  | 5,892 | (b) |  |  |  | 422 | (c) | 167 | (d) |  | 13,163 |  |  |  | 4,990 | (e)

|  |  |  |  |  |  |  |  | 10,094 |  |  | 363 |  |  | 10,544 |  |  |  |  | 454 |  | 1,146 |  |  | 22,601 |  |  |  | 13,351 |

Notes

(*) |  | The term of office expires with the Shareholders’ Meeting approving the Financial Statements for the year ending December 31, 2016.
(**) |  | The position of COO E&P Division has been covered ad interim from May 9 to June 30, 2014 without any remuneration.
(***) |  | 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 managers).
(1) |  | Giuseppe Recchi - Chairman of the Board of Directors
|  | (a) The amount includes the pro-rata until May 8, 2014, respectively of the fixed remuneration of euro 265 thousand set by the Shareholders’ Meeting on May 5, 2011 (euro 94 thousand) and the fixed remuneration for the delegated powers of euro 500 thousand approved by the Board on June 1, 2011 (euro 178 thousand).
|  | (b) The amount corresponds to the annual variable incentive.
(2) |  | Emma Marcegaglia - Chairman of the Board of Directors
|  | (a) The amount includes the pro-rata from May 8, 2014, respectively of the fixed remuneration of euro 90 thousand set by the Shareholders’ Meeting on May 8, 2014 (euro 58 thousand) and from May 9, 2014 of the fixed remuneration for the delegated powers of euro 148 thousand approved by the Board on May 28, 2014 (euro 96 thousand).
(3) |  | Paolo Scaroni - Chief Executive Officer and General Manager
|  | (a) The amount includes the pro-rata until May 8, 2014, respectively of the fixed remuneration of euro 430 thousand for the position of Chief Executive Officer (euro 153 thousand), which incorporates the remuneration set by the Shareholders’ Meeting on May 5, 2011 for the position of Director, and the fixed remuneration of euro 1 million for the position of General Manager (euro 352 thousand); indemnities due for transfers, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and of the Company’s complementary agreements and other fees attributable to the employment for the period 2011-2014 are added to this amount for a total of euro 255 thousand.
|  | (b) The amount includes the variable annual incentive of euro 1,831 thousand, the deferred monetary incentive of euro 865 thousand awarded in 2011 and paid in 2014.
|  | (c) Amount approved by the Board of Directors Meeting on April 28, 2014, including the additional severance indemnity (euro 5,202 thousand), the economic treatment for the term of office end (euro 748 thousand), the non-competition agreement to be paid in May 2015 on the expiry of the term of the agreement (euro 2,219 thousand), the severance indemnity provided for the applicable Italian laws (euro 187 thousand), as well as the amount of euro 5 thousand for the novation transaction.

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(4) |  | Claudio Descalzi - Chief Executive Officer and General Manager
|  | (a) The amount includes the pro-rata from May 9, 2014, respectively of the fixed remuneration of euro 550 thousand for the position of Chief Executive Officer (euro 355 thousand), which incorporates the remuneration set by the Shareholders’ Meeting on May 8, 2014 for the position of Director, and the fixed remuneration of euro 800 thousand for the position of General Manager (euro 519 thousand); to this amount are added the indemnities owed for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and by the Company’s additional agreements, for a total amount of euro 9 thousand.
|  | (b) Amount relating to the consideration provided for the option right of the Board of Directors for the activation of the non-competition agreement. This amount, although quoted in full in the table, is paid in three annual installments starting in 2014.
|  | (c) The amount includes the pro-rata until May 8, 2014 of the fixed gross remuneration of the COO of the E&P Division; to this amount are added the indemnities due for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and by the Company’s additional agreements, for a total amount of euro 5 thousand.
|  | (d) The amount includes the payment of euro 879 thousand for the variable annual incentive and of euro 339 thousand for the deferred monetary incentive assigned in 2011 and paid in 2014.
|  | (e) The amount corresponds to the pro-rata until May 8, 2014 of the remuneration for the position of Chairman of Eni UK.
(5) |  | Carlo Cesare Gatto - Director
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
|  | (b) The amount includes the pro-rata until May 8, 2014, respectively of euro 11.2 thousand for participating in the Control and Risk Committee and euro 6.4 thousand for the Compensation Committee.
(6) |  | Paolo Marchioni - Director
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
|  | (b) The amount includes the pro-rata until May 8, 2014, respectively of euro 11 thousand for participating in the Control and Risk Committee and euro 6.3 thousand for the Oil-Gas Energy Committee.
(7) |  | Roberto Petri - Director
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
|  | (b) The amount includes the pro-rata until May 8, 2014, respectively of euro 6.4 thousand for participating in the Compensation Committee and euro 6.4 thousand for the Oil-Gas Energy Committee.
(8) |  | Alessandro Profumo - Director
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
|  | (b) The amount includes the pro-rata until May 8, 2014, respectively of euro 6.4 thousand for participating in the Compensation Committee and euro 9.6 thousand for the Oil-Gas Energy Committee.
(9) |  | Mario Resca – Director
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
|  | (b) The amount includes the pro-rata until May 8, 2014, respectively of euro 9.6 thousand for participating in the Compensation Committee and euro 6.4 thousand for the Oil-Gas Energy Committee.
(10) |  | Francesco Taranto - Director
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
|  | (b) The amount includes the pro-rata until May 8, 2014, respectively of euro 11.2 thousand for participating in the Control and Risk Committee and euro 6.4 thousand for the Oil-Gas Energy Committee.
(11) |  | Andrea Gemma - Director
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
|  | (b) The amount includes the pro-rata from May 9, 2014, respectively of euro 20.3 thousand for participating in the Control and Risk Committee, euro 11.6 thousand for the Sustainability and Scenario Committee and euro 17.4 thousand for the Appointment Committee.
(12) |  | Pietro Angelo Guindani - Director
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
|  | (b) The amount includes the pro-rata from May 9, 2014, respectively of euro 17.4 thousand for participating in the Compensation Committee and euro 11.6 thousand for the Sustainability and Scenario Committee.
(13) |  | Karina A. Litvack - Director
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
|  | (b) The amount includes the pro-rata from May 9, 2014, respectively of euro 20.3 thousand for participating in the Control and Risk Committee, euro 11.6 thousand for participating in the Compensation Committee and euro 11.6 thousand for the Sustainability and Scenario Committee.
(14) |  | Alessandro Lorenzi - Director
|  | (a) The amount includes the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting on May 5, 2011 (euro 41 thousand) and from May 9, 2014 for the fixed annual remuneration set by the Shareholders’ Meeting on May 8, 2014 (euro 51 thousand).
|  | (b) The amount includes euro 40.5 thousand for participating in the Audit and Risk Committee and the pro-rata until May 8, 2014 of euro 6.4 thousand for the Oil-Gas Energy Committee and from May 9, 2014 of euro 11.6 thousand for the Compensation Committee.
(15) |  | Diva Moriani - Director
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
|  | (b) The amount includes the pro-rata from May 9, 2014, respectively of euro 11.6 thousand for participating in the Compensation Committee and euro 11.6 thousand for the Appointment Committee.
(16) |  | Fabrizio Pagani - Director
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
|  | (b) The amount includes the pro-rata from May 9, 2014, respectively of euro 17.4 thousand for the Sustainability and Scenario Committee and euro 11.6 thousand for the Appointment Committee.
(17) |  | Luigi Zingales - Director
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
|  | (b) The amount includes the pro-rata from May 9, 2014, respectively of euro 20.3 thousand for participating in the Control and Risk Committee and euro 11.6 thousand for the Appointment Committee.
(18) |  | Ugo Marinelli - Chairman of the Board of Statutory Auditors
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(19) |  | Francesco Bilotti - Statutory Auditor
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(20) |  | Paolo Fumagalli - Statutory Auditor
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(21) |  | Renato Righetti - Statutory Auditor
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(22) |  | Giorgio Silva - Statutory Auditor
|  | (a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(23) |  | Matteo Caratozzolo - Chairman of the Board of Statutory Auditors
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(24) |  | Paola Camagni - Permanent Auditor
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(25) |  | Alberto Falini - Permanent Auditor
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(26) |  | Marco Lacchini - Permanent Auditor
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(27) |  | Marco Seracini - Permanent Auditor
|  | (a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(28) |  | Angelo Fanelli - Chief Operating Officer R&M Division
|  | (a) The amount corresponds to the pro-rata until June 30, 2014 of the Gross Annual Salary (euro 300 thousand) to which are added the indemnities due for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and the Company’s additional agreements, as well as other indemnities related to the employment contract, for a total amount of euro 850.
|  | (b) The amount corresponds to the annual variable incentive.
(29) |  | Other Managers with strategic responsibilities
|  | (a) To the amount of euro 6,682 thousand as Gross Annual Salary, as the indemnities owed for the transfers performed, in Italy and abroad, in line with the provisions of the relevant national collective labor 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 euro 456 thousand.
|  | (b) The amount includes the payment of euro 2,464 thousand relating to the deferred monetary incentive assigned in 2011 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, as well as the housing provided for senior managers in international mobility assignment.
|  | (d) Amounts due for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231, to the role of Manager responsible for the preparation of the Company’s Financial Statements and to the remuneration received for positions held in subsidiaries or associated companies of Eni.
|  | (e) The amount includes the severance indemnity and early retirement incentives paid in relation to the termination of the employment.

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> OTHER INFORMATION

Accrued compensation
Total compensation accrued in the year 2014 pertaining to all the Board members amounted to euro 10.1 million; it amounted to euro 0.419 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, 2014, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, Chief Operating Officers and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2014 period, filled said roles, even if only for a fraction of the year) amounted to euro 43 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2014. The breakdown is as follow:

| 2014
| (euro million)

Fees and salaries |  | 25
Post-employment benefits |  | 2
Other long-term benefits |  | 10
Indemnity upon termination of the office |  | 6
|  | 43

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, 2014, 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 2014 period, filled said roles, even if only for a fraction of the year), was euro 1,648 thousand.

Name |  |  |  | (euro thousand)
Claudio Descalzi |  | Chief Executive Officer |  | 343
Angelo Fanelli |  | Chief Operating Officer of the R&M Division |  | 248
Senior managers (a) |  |  |  | 1,057
|  |  |  | 1,648

(a) |  | No. 18 managers.

> Stock options

The Company discontinued any stock-based compensation scheme in 2009; as such, options outstanding as of the end of the year pertained to stock options schemes adopted in previous reporting periods. At December 31, 2014, no options were outstanding for the purchase of an equal amount of Eni ordinary shares without nominal value.

The following table shows the evolution of stock option activity in 2013 and 2014.

| 2013 |  | 2014

| Number of shares |  | Weighted average exercise price (euro) |  | Market price (euro) |  | Number of shares |  | Weighted average exercise price (euro) |  | Market price (euro)

Options as of January 1 |  | 8,259,520 |  |  | 23.545 |  | 18.457 |  | 2,980,725 |  |  | 22.540 |  | 17.533
Options exercised in the period |  |  |  |  |  |  |  |  |  |  |  |  |  |
Options cancelled in the period |  | (5,278,795 | ) |  | 24.112 |  | 16.278 |  | (2,980,725 | ) |  | 22.540 |  | 19.766
Options outstanding as of December 31 |  | 2,980,725 |  |  | 22.540 |  | 17.533 |  |  |  |  |  |  |
of which exercisable as of December 31 |  | 2,969,450 |  |  | 22.540 |  | 17.533 |  |  |  |  |  |  |

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Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the table below indicates, by name, the stock options assigned to the Chief Executive Officer and General Manager, to the Chief Operating Officers of the Divisions and, at an aggregate level, to other Managers with strategic responsibilities (including all those individuals who, during the course of the 2014 period, filled said roles, even if only for a fraction of the year).

In particular, the purchase rights (options) for Eni shares or for subsidiaries, which can be exercised after three years from the date granted are indicated, in relation to the existing stock incentive plans, the last of which was granted in 2008. The data are shown in accordance with the criteria of aggregate representation, as there are no options outstanding at December 31, 2014.

> Stock options granted to Directors, Chief Operating Officers and other Managers with strategic responsibilities

Name |  | Paolo Scaroni |  | Claudio Descalzi |  | Angelo Fanelli |  | Other Managers with strategic responsibilities (1)
Office |  | CEO and General Manager |  | Chief Operating Officer of E&P Division |  | Chief Operating Officer of R&M Division |
Plan |  | Eni Stock Option Plans |  | Eni Stock Option Plans |  | Eni Stock Option Plans |  | Eni Stock Option Plans

Options held at the start of the year |  |  |  |  |  |  |  |  |
Number of options |  |  | 348,975 |  | 47,025 |  | 27,500 |  | 377,300
Average exercise price | (euro) |  | 22.540 |  | 22.540 |  | 22.540 |  | 22.540
Average maturity | (months) |  | 7 |  | 7 |  | 7 |  | 7
Options granted during the year |  |  |  |  |  |  |  |  |
Number of options |  |  |  |  |  |  |  |  |
Exercise price | (euro) |  |  |  |  |  |  |  |
Period of possible exercise | (from-to) |  |  |  |  |  |  |  |
Fair value on grant date | (euro) |  |  |  |  |  |  |  |
Grant date |  |  |  |  |  |  |  |  |
Market price of underlying shares upon granting of options | (euro) |  |  |  |  |  |  |  |
Options exercised during the year |  |  |  |  |  |  |  |  |
Number of options |  |  |  |  |  |  |  |  |
Exercise price | (euro) |  |  |  |  |  |  |  |
Market price of underlying shares on exercise date | (euro) |  |  |  |  |  |  |  |
Options expired during the year |  |  |  |  |  |  |  |  |
Number of options |  |  | 348,975 |  | 47,025 |  | 27,500 |  | 377,300
Options held at the end of the year |  |  |  |  |  |  |  |  |
Number of options |  |  |  |  |  |  |  |  |
Options relevant to the year |  |  |  |  |  |  |  |  |
Fair value | (euro thousand) |  |  |  |  |  |  |  |

(1) |  | Managers who, during the course of the year and with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, were permanent members of the Company Management Committee and the ones who report directly to the Chief Executive Officer (No. 20 managers).

Board practices

Corporate Governance
The Corporate Governance structure of Eni SpA 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) of December 2011 (hereinafter "Corporate Governance Code" or "Code"). On July 14, 2014, the Italian Corporate Governance Committee approved a few amendments to the Corporate Governance Code. At its Meeting held on December 11, 2014, the Board adopted the new recommendations of the Code, acknowledging that Eni’s Corporate Governance model was already broadly compliant with the new recommendations. Some of the solutions previously adopted by Eni have been updated to include and specify the role assigned by the Board of Directors to the Chairman of the Board on May 9, 2014, regarding the Internal Audit function.

The names of Eni’s Directors, their positions, the year in which each of them was initially appointed as a Director and their ages are reported in the related table above.

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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 role as guarantor 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 Senior Executive Vice President of the Internal Audit Department reports to the Board, and on its behalf, to the Chairman. 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 to the Chairman. He lends assistance and independent legal advice (regarding the management) to the Board and the Directors and presents annually 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 following strategic, operational and organizational powers:

• |  | defines the system and rules of Corporate Governance for the Company and the Group;
• |  | establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets;
• |  | expresses the general criteria for determining the maximum number of offices that a Company Director may hold in other companies;
• |  | delegates and revokes the powers of the CEO and the Chairman, establishing the limits and procedures for exercising those powers and determining the compensation associated with these duties;
• |  | establishes the basic structure of the organizational, administrative and accounting arrangements of the Company (including the internal control and risk management system), of its strategically important subsidiaries and of the Group as a whole. It evaluates the adequacy of these arrangements;
• |  | establishes the guidelines for the internal control and risk management system, so that the main risks facing the Company and its subsidiaries are correctly identified and adequately measured, managed and monitored, determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives. It sets the financial risk limits of the Company. It also examines the main business risks, which are identified taking into account the characteristics of the activities carried out by the Company and its subsidiaries and which are reported by the Chief Executive Officer at least quarterly. Moreover, it evaluates, every six months, the adequacy of the internal control and risk management system with respect to the characteristics of the Company and its risk profile, as well as the system’s effectiveness;
• |  | approves at least annually the Audit Plan drawn up by the Senior Executive Vice President of the Internal Audit Department. It also evaluates the findings contained in the recommendation letter, if any, of the Audit Firm and in its statement on the key issues that arose during the statutory audit;
• |  | defines the strategic guidelines and objectives of the Company and the Group, including sustainability policies. It examines and approves the budgets and strategic, industrial and financial plans of the Group, periodically monitoring their implementation, as well as agreements of a strategic nature for the Company;
• |  | examines and approves the annual financial report including the individual and 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;
• |  | evaluates and approves transactions of the Company and its subsidiaries with related parties17, 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;

(17) |  | 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.

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• |  | resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries;
• |  | 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 Zingales 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. During its meeting of February 26, 2015, 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, which replaced the Oil-Gas Energy 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 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 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 can attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they can attend Control and Risk Committee meetings, except when the meetings are addressing issues regarding them. Finally, they can 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 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.

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Compensation Committee
Members: Pietro A. Guindani (Chairman), Karina Litvack, Alessandro Lorenzi and Diva Moriani.

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.

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 and presents proposals for: (i) general criteria for the compensation of Managers with strategic responsibilities; (ii) annual and long-term incentive plans, 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) 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 2014, the Compensation Committee met twelve times, with an attendance rate: (i) of 94% of its members in the four meetings held before the expiration date of the previous Board of Directors (May 8, 2014); and (ii) of 97% of its members in the eight meetings held after the appointment of the current Committee.

In 2014, the main topics discussed during the first part of the year were: (i) the periodical evaluation of the Remuneration Policy conducted in 2013, including defining the proposal guidelines for the 2014 Remuneration Policy; (ii) the definition of the proposal for reviewing the Long-Term Monetary Incentive Plan; (iii) the evaluation of Eni’s 2013 results and determination of the 2014 performance targets for the purposes of the variable Incentive Plans; (iv) the establishment of the proposals regarding the Deferred Monetary Incentive Plan for the CEO and General Manager and for other executives; (v) the examination of the 2014 Remuneration Report; and (vi) the recognition of compensation for retiring Directors with delegated powers at the end of their terms.

Following the renewal of the Board of Directors, on May 28, 2014 the Committee submitted to the Board of Directors a proposal for amending its operating rules. In the same meeting the Committee also submitted to the Board proposals on compensation for Directors with delegated powers for the 2014-2017 term, taking into account the principles and criteria set out in the 2014 Remuneration Report, the resolution approved by the Shareholders’ Meeting for reducing the compensation of Directors with delegated powers in compliance with law, as well as domestic and international market benchmarks for similar positions or roles, while complying with provisions on related parties transactions.

During the second part of the year, the Committee examined the results of the vote of the Shareholder’s Meeting on the 2014 Remuneration Policy, comparing Eni with major Italian listed companies and its peer companies, as well as looking at the Company’s practice of handling relations with shareholders and investors, with emphasis on communication pertaining to compensation issues. The Committee also formulated the proposal concerning the fulfillment ("2014 attribution") of the Long-Term Monetary Incentive Plan for the CEO and General Manager and for critical management personnel. Furthermore, the Committee examined the proposals for the adoption of the new Corporate Governance Code recommendations (July 14, 2014) on compensation and proposed to the Board of Directors that they be fully adopted. The Board resolved to adopt them in December 2014. It also completed an extensive analysis of the system of objectives relating to Eni’s incentive Plans, sharing in particular the criteria for identifying annual and long-term performance indicators (for the Long Term Monetary Incentive Plan) for the purposes of the proposed 2015 Remuneration Policy. Finally, the Committee examined the regulatory framework, Company practices and market practices concerning "clawback" for the purposes of defining the proposed guidelines for the 2015 Remuneration Policy.

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, available to the public on the Company’s website.

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Control and Risk Committee
Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Karina Litvack and Luigi Zingales.

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 annual and semi-annual financial reports. It is entirely made up of non-executive and independent Directors18 who possess the necessary expertise consistent with the duties they are required to perform19.

In particular, at their appointment, the Directors Lorenzi, Litvack and Zingales 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 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; c) on the approval, at least once a year, of the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; d) on the description, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, providing its evaluation of the overall adequacy of the system itself; e) 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; f) on specific aspects concerning the identification of the main risks faced by the Company, as well as on the design, implementation and management of the internal control and risk management system; and g) 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.

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 the appropriateness of the powers and resources assigned to the officer in charge of preparing financial reports and, as well as for the purposes of overseeing the proper application of accounting standards and their consistency, performs the duties assigned it under the MSG on "Eni’s internal control system over financial reporting", including examining the report on the internal control system for financial reporting prepared by the officer in charge of preparing financial reports at the time of the approval of the consolidated annual and semi-annual financial statements; and c) 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 whether they continue to be met; 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

(18) |  | 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.
(19) |  | The Governance system put in place by Eni establishes that at least two members of the Committee – and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.

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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 of specific operational areas, providing simultaneous notice to the Chairman of the Board of Statutory Auditors. The Committee also examines and assesses: (a) communications and information received from the Board of Statutory Auditors and its members regarding the internal control and risk management system, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports; (b) half yearly reports issued by Eni’s Watch Structure, including in its capacity as Guarantor of the Code of Ethics, as well as the timely updates provided by the Structure, after the updates have been given to the Chairman of the Board and to the CEO, about any particular material or significant situation detected in the performance of its duty; (c) information on the internal control and risk management system, including that provided in the course of periodic meetings with the competent Company structures; and (d) enquiries and reviews concerning the internal control and risk management system carried out by third parties.

Furthermore, the Committee oversees the activities of the Legal Affairs Department in case of judicial inquiries, 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, available to the public at the Company’s website.

Nomination Committee
Members: Andrea Gemma (Chairman), Diva Moriani, Fabrizio Pagani and Luigi Zingales.

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, 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 on the basis of the results of the self-assessment, 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 professional qualifications it feels should be represented on the same, 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 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 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) 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.

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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, available to the public at the Company’s website.

Sustainability and Scenarios Committee
Members: Fabrizio Pagani (Chairman), Andrea Gemma, Pietro A. Guindani and Karina Litvack.

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 proposals 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 May 8, 2014 for a term of three financial years20. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2016.

Name |  | Position |  | Year first appointed to Board of Statutory Auditors
Matteo Caratozzolo |  | Chairman |  | 2014
Paola Camagni |  | Auditor |  | 2014
Alberto Falini |  | Auditor |  | 2014
Marco Lacchini |  | Auditor |  | 2014
Marco Seracini |  | Auditor |  | 2014
Stefania Bettoni |  | Alternate |  | 2014
Mauro Lonardo |  | Alternate |  | 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 within the scope of the Board’s

(20) |  | Until May 8, 2014 the members of the Board of Statutory Auditors were: Ugo Marinelli (Chairman); Roberto Ferranti (until September 5, 2013); Francesco Bilotti (as of September 5, 2013, Alternate Auditor since 2005); Paolo Fumagalli; Renato Righetti; Giorgio Silva and Maurizio Lauri (Alternate Auditor).

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Authority, the adequacy 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 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.

In particular, pursuant to Article 19, paragraph 1, letters c) and d) of Legislative Decree No. 39/2010, the Board of Statutory Auditors supervises the auditing activities and the independence of the Audit Firm, verifying compliance with all applicable regulations, as well as the nature and scale of any services other than financial auditing services provided to the Eni Group, either directly or through companies belonging to its network.

In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the financial statements.

On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, the Board of Statutory Auditors approved the internal rules concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC 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 performing 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 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.

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Eni Watch Structure and Model 231
In accordance with the Italian regulations concerning the "administrative liability of legal entities deriving from criminal offences", contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, "Legislative Decree No. 231/2001"), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high-ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni SpA’s 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. Most recently, the Board of Directors, in its meetings of April 10 and May 28, 2014, updated the Model 231 to incorporate all the types of crimes relevant to the Company pursuant to Legislative Decree No. 231 of 2001.

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. The composition of the Eni Watch Structure, initially composed of only three members, was modified in 2007 with the inclusion of two external members, one of whom was appointed as Chairman of the Eni Watch Structure selected among academics and professionals of proven authority and expertise in economic and business management issues. At present, the Watch Structure of Eni SpA is composed of three external members and three internal members. The internal members are the Chief Legal & Regulatory Officer; the Senior Vice President Relations with Entrepreneurial Associations Coordination and the Senior Executive Vice President Internal Audit of the Company. On May 28, 2014, the Board of Directors, with the favorable opinion of the Board of Statutory Auditors, appointed the current members of the Watch Structure.

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.

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 Reconta 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. Until December 22, 2014 this task was carried out by the Magistrate of the Court of Auditors, Raffaele Squitieri, on the basis of the resolution approved on October 28, 2009 by the Presidential Council of the Court of Auditors. On the basis of the resolution approved on December 22, 2014, the Presidential Council of the Court of Auditors appointed Adolfo Teobaldo De Girolamo. The Magistrate of the Court attends the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Control and Risk Committee.

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Employees

As of December 31, 2014, Eni had a total of 84,405 employees, with an increase of 518 employees, or up by 0.6% from December 31, 2013, which reflects an increase of 1,673 employees working outside Italy and a decrease of 1,155 employees in Italy.

|  | 2012 (1) |  | 2013 |  | 2014

|  | (number)

Exploration & Production |  | 11,304 |  | 12,352 |  | 12,777
Gas & Power (2) |  | 4,836 |  | 4,616 |  | 4,228
Refining & Marketing |  | 8,608 |  | 8,438 |  | 6,774
Chemicals |  | 5,668 |  | 5,708 |  | 5,443
Engineering & Construction |  | 43,387 |  | 47,209 |  | 49,559
Other activities |  | 871 |  | 818 |  | 726
Corporate and financial companies |  | 4,731 |  | 4,746 |  | 4,898
|  | 79,405 |  | 83,887 |  | 84,405

(1) |  | The numbers for 2012 have been restated following the adoption of IFRS 11.
(2) |  | Following the deconsolidation of Snam in 2012, employees of the Gas & Power business segment include Marketing and International transport activities.

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The table below sets forth Eni’s employees as of December 31, 2012, 2013 and 2014 in Italy and outside Italy:

|  | 2012 (1) |  | 2013 |  | 2014

|  | (number)

Exploration & Production | Italy |  | 3,933 |  | 4,133 |  | 4,534
| Outside Italy |  | 7,371 |  | 8,219 |  | 8,243
|  |  | 11,304 |  | 12,352 |  | 12,777
Gas & Power (2) | Italy |  | 2,126 |  | 2,178 |  | 1,980
| Outside Italy |  | 2,710 |  | 2,438 |  | 2,248
|  |  | 4,836 |  | 4,616 |  | 4,228
Refining & Marketing | Italy |  | 6,098 |  | 5,909 |  | 4,897
| Outside Italy |  | 2,510 |  | 2,529 |  | 1,877
|  |  | 8,608 |  | 8,438 |  | 6,774
Chemicals | Italy |  | 4,606 |  | 4,615 |  | 4,476
| Outside Italy |  | 1,062 |  | 1,093 |  | 967
|  |  | 5,668 |  | 5,708 |  | 5,443
Engineering & Construction | Italy |  | 5,186 |  | 5,136 |  | 5,016
| Outside Italy |  | 38,201 |  | 42,073 |  | 44,543
|  |  | 43,387 |  | 47,209 |  | 49,559
Other activities | Italy |  | 871 |  | 818 |  | 726
| Outside Italy |  |  |  |  |  |
|  |  | 871 |  | 818 |  | 726
Corporate and financial companies | Italy |  | 4,577 |  | 4,589 |  | 4,594
| Outside Italy |  | 154 |  | 157 |  | 304
|  |  | 4,731 |  | 4,746 |  | 4,898
Total | Italy |  | 27,397 |  | 27,378 |  | 26,223
| Outside Italy |  | 52,008 |  | 56,509 |  | 58,182
|  |  | 79,405 |  | 83,887 |  | 84,405
of which senior managers |  |  | 1,504 |  | 1,505 |  | 1,503

(1) |  | The numbers for 2012 have been restated following the adoption of IFRS 11.
(2) |  | Following the deconsolidation of Snam in 2012, employees of the Gas & Power business segment include Marketing and International transport activities.

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Share ownership

As of February 28, 2015, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 258,462 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 | Number of shares owned

Board of Directors |  |  |  |
Emma Marcegaglia |  | Chairman |  | 53,894
Claudio Descalzi |  | CEO |  | 39,455
Luigi Zingales |  | Director |  | 2,000
Board of Statutory Auditors |  |  |  | 5,000
Senior Managers |  |  |  | 158,113

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Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

The Ministry of Economy and Finance controls Eni as a result of shares held directly and indirectly through Cassa Depositi e Prestiti SpA (CDP), in which the Ministry of Economy and Finance holds a 80.10% stake.

As of March 16, 2015, the total amount of Eni SpA’s voting securities owned by these shareholders was:

Title of class |  | Number of shares owned |  | Percent of class

Ministry of Economy and Finance |  | 157,552,137 |  | 4.34 |
Cassa Depositi e Prestiti SpA |  | 936,179,478 |  | 25.76 |

The following table shows the percentage of Eni’s share capital owned directly or indirectly by subjects that as of March 16, 2015, have notified that their holding exceeds the threshold of 2% pursuant to Article 120 of Italian Consolidated Law on Financial Intermediation and to Consob Resolution No. 11971/99 (Consob Regulations on Issuers).

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. 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, were repealed by the last of the implementing ministerial regulations in the areas of energy, transport and communications, which have been in force since June 7, 2014. Consequently, provisions of Article 6.2 of Eni’s By-laws concerning the special powers of the Italian State have ceased to be in effect. See “Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)”. As of March 27, 2015, there were 28,264,329 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 1.6% 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 44 of the Notes on Consolidated Financial Statements”.

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Item 8. FINANCIAL INFORMATION

Consolidated Statements and other financial information

See "Item 18 – Financial Statements".

> Legal proceedings

Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, 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 36 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. Due to a deeply changed oil price environment and in order to preserve the Group balance sheet, management decided to rebase the dividend and is planning to pay a dividend of euro 0.8 per share for fiscal year 2015. From 2016 onwards taking into account an expected improvement in the oil price scenario and the planned improvements in the Group cash flow due to the implementation of our value-generation strategy in Exploration & Production and the turnaround of our Gas & Power, Refining & Marketing and Chemical segments, management intends to assess its progressive dividend policy which contemplates an increasing dividend at a rate which is expected to be set taking into account Eni’s underlying earnings and cash flow growth, as well as capital expenditure requirements and the targeted financial structure. This dividend policy is based on management’s planning assumptions for oil prices at 55 $/BBL in 2015 and a gradual recovery in the subsequent years up to our long-term case of 90 $/BBL in 2018, as well as the risk factors described in Item 3 and the other planning assumptions and initiatives described in "Item 5 – Management’s expectations of operations".

At the Annual Shareholders’ Meeting scheduled on May 13, 2015, management intend to propose the distribution of a dividend of euro 1.12 per share for fiscal year 2014, of which euro 0.56 was paid as interim dividend in September 2014. Total cash outlay for the 2014 balance dividend is expected at approximately euro 2 billion (whereas euro 2 billion were distributed in September 2014) if the Annual Shareholders’ Meeting approves the annual dividend. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance to the full-year dividend to be paid in each following year. For further information about the Company’s dividend policy see "Item 5 – Management’s expectations of operations".

Significant changes

See "Item 5 – Recent developments" for a discussion of significant events occurred after 2014 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.

| MTA |  | New York Stock Exchange

| High |  | Low |  | High |  | Low

| (euro per share) |  | (US$ per ADR)

Year ended December 31, |  |  |  |  |  |  |  |
2010 |  | 18.560 |  | 14.610 |  | 53.890 |  | 35.370
2011 |  | 18.420 |  | 12.170 |  | 53.740 |  | 32.980
2012 |  | 18.700 |  | 15.250 |  | 49.440 |  | 36.850
2013 |  | 19.480 |  | 15.290 |  | 52.120 |  | 40.390
2014 |  | 20.410 |  | 13.290 |  | 55.300 |  | 32.810
2013 |  |  |  |  |  |  |  |
First quarter |  | 19.480 |  | 17.010 |  | 52.120 |  | 44.360
Second quarter |  | 18.980 |  | 15.290 |  | 48.960 |  | 40.390
Third quarter |  | 17.950 |  | 15.710 |  | 48.500 |  | 40.660
Fourth quarter |  | 18.650 |  | 16.300 |  | 50.800 |  | 44.920
2014 |  |  |  |  |  |  |  |
First quarter |  | 18.210 |  | 16.250 |  | 50.170 |  | 43.790
Second quarter |  | 20.040 |  | 17.970 |  | 54.900 |  | 49.210
Third quarter |  | 20.410 |  | 18.070 |  | 55.300 |  | 46.750
Fourth quarter |  | 18.610 |  | 13.290 |  | 46.480 |  | 32.810
2015 |  |  |  |  |  |  |  |
First quarter (to March 27, 2015) |  | 16.680 |  | 13.370 |  | 37.690 |  | 31.960
Month of |  |  |  |  |  |  |  |
October 2014 |  | 18.610 |  | 15.860 |  | 46.480 |  | 40.760
November 2014 |  | 17.200 |  | 16.070 |  | 42.640 |  | 39.190
December 2014 |  | 15.870 |  | 13.290 |  | 39.220 |  | 32.810
January 2015 |  | 15.220 |  | 13.370 |  | 34.980 |  | 31.960
February 2015 |  | 16.680 |  | 15.090 |  | 37.690 |  | 34.080
March 2015 (through March 27, 2015) |  | 16.580 |  | 15.240 |  | 37.020 |  | 32.190

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 March 27, 2015, there were 28,264,329 ADRs outstanding, representing 56,528,658 ordinary shares or approximately 1.6% of all Eni’s shares outstanding, held by 118 holders of record (including the Depository Trust Company) in the United States, 116 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 market. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the Italian stock market. 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 float. Since June 1, 2009, the FTSE MIB (previously S&P/MIB Index) is

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the principal indicator used to track the performance of the Italian stock market 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 13%, as established by FTSE after the quarterly rebalancing for FTSE MIB effective March 23, 2015.

Trading in the MTA is allowed in any quantity of the Shares, as well as other financial instruments. Where necessary, Borsa Italiana may specify a minimum lot for each financial instrument. Since March 28, 2000, a three-day rolling cash settlement applied to all trades of equity securities in Italy. Beginning from October 6, 2014, a two-day rolling cash settlement applies to all trades of equity securities in Italy. In addition, 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 December 22, 2014: (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

The 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 and Exchange Traded Commodities market), IDEM (index and stock 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.

According to Legislative Decree No. 58 of February 24, 1998 (“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

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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, in agreement with Consob, also regulates the operation of the clearing and settlement service for transactions involving financial instruments. The regulations and measures of general application adopted by Consob and the Bank of Italy are available on the website of Consob (www.consob.it) or Bank of Italy (www.bancaditalia.it).

The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it).

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Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

> Register office

"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 afore mentioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

> Directors’ issues

Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting.

If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members.

The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions.

According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance.

The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time.

The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors.

In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors with voting rights must be present. Resolutions shall be approved by a majority of the votes of the Directors with voting rights present; in the event of a tie, the person who chairs the meeting shall have a casting vote.

For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see "Item 6 – Board of Directors’ duties and responsibilities".

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Interests in Company’s transactions
As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob ("Commissione Nazionale per le Società e la Borsa" is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the "Consob Regulation"), the Board of Directors – on November 18, 2010 – unanimously approved the Management System Guidelines "Transactions involving interests of Directors and Statutory Auditors and transactions with related parties"21 ("MSG"), which has been in effect from January 1, 201122 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 must leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is 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 investigation and resolution 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 2014, 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 the By-laws, the Company’s share capital amounts to euro 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.

(21) |  | The Board of Directors modified this Management System Guideline on January 19, 2012.
(22) |  | 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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Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the Meeting, by electronic means.

Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.

In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors.

Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE.

Dividend rights
Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations. Specifically, the ordinary Shareholders’ Meeting called to approve the annual financial statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.

Voting rights
The general provisions on share "voting rights" are described at the paragraph "Shareholders’ Meeting" below. In relation to the appointment of the Board of Directors (Eni’s Board is not a "staggered board") and the Board of Statutory Auditors (see Item 6), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (at January 2014 Consob established a threshold of 0.5%), 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. Resolutions of ordinary and extraordinary Shareholders’ Meetings in first, second or third call must be passed with the majorities required by law in each case. The ordinary and the extraordinary Shareholders’ Meeting are normally held after a single call, with the majorities required by law in this 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.

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The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by correspondence (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. By the same date of the publication of the notice calling the Meeting, 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. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements.

The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit and debit records entered on the 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 correspondence 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).

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In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 323 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.

Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban.

Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.

> Limitation on changes in control of the Company (Special Powers of the Italian State)

Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified Italian legislation governing the special powers of the Italian State to comply with European rules. 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, were repealed by the last of the implementing ministerial regulations in the areas of energy, transport and communications. These ministerial regulations (Decree of the President of the Italian Republic No. 85 of March 25, 2014), identifying strategic assets in the energy, transportation and communications sectors, have been in force since June 7, 2014. Consequently, provisions of Article 6.2 of Eni’s By-laws concerning the special powers of the Italian State have ceased to be in effect. The Board of Directors, at its meeting of November 20, 2014, amended the By-laws by deleting clauses on the special powers.

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 above mentioned ministerial regulations. The new 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 of control of a company that holds strategic assets by an entity outside of the EU, when such an acquisition may result in a threat of serious injury to the above mentioned essential interests of the Italian State.

The legislation governing the new special powers of the Italian State provides for a general rule that the acquisition, for any reason, by an entity outside of the EU of stock of company that holds strategic assets be allowed on condition of reciprocity, in compliance with international agreements signed by Italy or the EU. These powers are exercised exclusively on the basis of objective and non-discriminatory criteria.

Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.

In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any of such provisions.

> Shareholder ownership thresholds

There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Finance24 and Consob Regulation25, any direct or indirect

(23) |  | 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.
(24) |  | Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.
(25) |  | Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.

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holding in the voting shares of an Italian listed company in excess of 2%26, 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6%, 90% and 95% 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 declarations shall be made within five trading days of the date of the transaction triggering the obligation to notify, regardless of the date on which it is carried out, using the forms contained in Annex 4A to the above mentioned Regulation.

The relevant thresholds noted above shall be calculated including: (i) shares owned by the reporting person, even if the voting rights belong or are assigned to third parties, or are suspended, as well as shares in which the voting rights belong or are assigned to him; and (ii) shares held through third parties (and shares whose voting rights are assigned to such third parties) such as nominees, trustees or subsidiary companies. 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 so-called "potential holdings" (such as holdings of derivatives or other equity-linked securities).

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 2% of the shares, the company that last 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, and any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

The limit referred to as 2% 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 afore mentioned threshold of a listed company, such listed company or any entity controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. If the foregoing limit is exceeded, the person who last exceeded the foregoing limit (or both holders, if it is not possible to ascertain which of the two persons was the last to exceed the limit) may not exercise the voting rights attached to the shares exceeding the foregoing limit. In the event of non-compliance, the voting rights attached to the shares held in excess of the limit specified shall be suspended and 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 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

(26) |  | 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 – thresholds lower than 2% by its decree for companies with an elevated current market value and, particularly, extensive shareholding structure.

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the prior authorization of the Italian Antitrust Authority27. However, if the acquiring party and the company to be acquired operate in more than one EU Member State and together exceed certain revenue thresholds, the antitrust approval for the acquisition falls under the exclusive jurisdiction of the European Commission.

> Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than are required by law.

Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.

Material contracts

None.

Exchange controls

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 euro 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.

(27) |  | Autorità garante per la concorrenza e il mercato (AGCM - www.agcm.it).

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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. 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 received in respect of 2014 profits are included in the taxable business income for 49.72% of their amount.

Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to un distributed 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 tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares.

Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units.

Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute tax.

Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment.

Dividends are subject to a 1.375% 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.

The substitute tax may also be reduced under the tax treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income tax treaties with approximately 70 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

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be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the treaty one by filing specific forms (certificate) with the Italian Tax Authorities.

As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (ADSs), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities 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, while 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).

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.

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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 euro 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 euro 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 euro 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 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

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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 euro/$ 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 SpA 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, 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 available online on the Company website at: http://www.eni.com/en_IT/documentation/documentation.page?type=bil-rap.

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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.

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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 euro/$ 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 and 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 euro/$ 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 and gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives.

The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and its subsidiaries Eni Finance International, Eni Finance USA and Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA 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 Divisions 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 entail

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|  | counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes.

• |  | Flow hedging: flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, in accordance to a portfolio basis. A central department processes a continuous flow of orders from the Group various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity on the received orders, which are normally related to assets managed by the business units. The central broker entity can normally rely on a continuous flow of hedging orders that can be predictable to a large extent, on the basis of the regular hedging programs made by the Group’s business units. The central entity is therefore in the position to net opposite orders, by retaining the level of risk necessary to cover timing, volume and asset class mismatch among orders. The benefits are the maximization of integration across the whole of the Group assets portfolio and the related netting potential, avoiding unnecessary derivatives, thus reducing costs and aggregated notional amounts of hedging programs. Flow hedging is managed on a portfolio basis and is dynamic by nature, since resulting net position is normally adjusted in order to take into account new orders received and maximum allowed exposure, related to timing, volume and asset classes mismatch. Those derivatives are accounted to profit and loss as the hedging of net exposures does not qualify as hedges under IFRS.
• |  | Asset-backed hedging: is a portfolio-based activity performed to protect assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated to assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible 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 physical delivery) and related financial derivatives. Normally, the target of a portfolio management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, prices scenarios and logistic flexibility/constraints, determine the optimal configuration in term 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.

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Please refer to "Item 18 – note 36 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, 22, 27 and 32 of the Notes on Consolidated Financial Statements" for details of the different derivatives owned by the Company in these markets.

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Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Item 12A. Debt securities

Not applicable.

Item 12B. Warrants and rights

Not applicable.

Item 12C. Other securities

Not applicable.

Item 12D. American Depositary Shares

In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. Since January 18, 2012, Eni’s ADRs are issued, cancelled and exchanged at the office of Bank of New York Mellon, as depositary (the "Depositary") under 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 is the custodian (the "Custodian") on behalf of the holders of Eni’s ADRs, and their principal office is 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.

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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 underlying shares |  | $5.00 (or less) for each 100 ADSs (or portion of 100 ADSs) |  | Each person to whom ADRs are issued against deposits of shares, including deposits and issuances in respect of: • Share distributions, stock split, rights, merger. • Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities.
(b) Selling or exercising rights |  | $5.00 (or less) for each 100 ADSs (or portion of 100 ADSs) |  | Distribution or sale of securities, the fee 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 receipts |  | Registration or transfer fees |  | 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 holders.
(g) Depositary services |  | $0.02 (or less) per ADS per calendar year |  | 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 2014, 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 $1,100,000 in connection with above mentioned expenditures.

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 $240,392.52 for the year ended December 31, 2014.

Category of expense reimbursed, waived or paid directly to third parties |  | Amount reimbursed, waived or paid directly to third parties for the year ended December 31, 2014
|  | (US$)

BNY Mellon products and services |  | 120,000.00
BNY Mellon related to servicing registered shareholders |  | 1,280.82
BNY Mellon paid to third-party vendors (1) |  | 119,111.70
Total |  | 240,392.52

(1) |  | Includes payments for AGM and related ADR Program services.

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PART II

Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

Item 15. CONTROLS AND PROCEDURES

Disclosure controls and procedures
In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act"), the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries.

The Company’s management, with the participation of the principal executive officer and principal 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 principal executive officer and principal financial officer have concluded that these disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.

The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition, this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system.

The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (CoSO) in 2013. Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, 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.

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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 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 principal executive officer, principal financial officer and principal 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 2014 and 2013 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.

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, 2014 and 2013, respectively:

| Year ended December 31,

|  | 2013 |  | 2014

|  | (euro thousand)

Audit fees |  | 28,023 |  | 27,607
Audit-related fees |  | 1,574 |  | 1,287
Tax fees |  | 21 |  | 11
All other fees |  | - |  | -
Total |  | 29,618 |  | 28,905

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.

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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 2014, 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.

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

On May 8, 2014, the Ordinary and Extraordinary Shareholders’ meeting revoked, for the part that had not been accomplished by the date of the meeting, the authorization to purchase ordinary Eni shares, as resolved on May 10, 2013 by the Board of Directors. Besides that, the Ordinary and Extraordinary Shareholders’ meeting resolved to authorize the Board of Directors to purchase Eni’s shares on the MTA – in one or more transactions and in any case within 18 months from the date of the resolution – up to a maximum number of 363,000,000 ordinary Eni’s shares, for a total amount of no more than euro 6,000,000,000.00, including, respectively, the number and the value of treasury shares purchased subsequent to the Shareholders Meeting of July 16, 2012 authorizing the share buy-back, at a unit price of no less than euro 1.102 and not more than the official price reported by Borsa Italiana for the shares on the trading day prior to each individual transaction, increased by 5%, according to the operational procedures established by the rules that govern the organization and management of Borsa Italiana.

As of December 31, 2014, Eni’s treasury shares amounted to No. 33,045,197, corresponding to 0.91% of share capital of Eni for a total book value of euro 581 million. Compared to December 31, 2013, there was an increase of 21,656,910 Eni’s treasury shares (0.60% of share capital of Eni), purchased from January 6, 2014 (beginning of Eni’s share buyback program, pursuant to the resolution passed by the Shareholders’ Meeting of May 10, 2013) through December 9, 2014. Share repurchases have been suspended since then.

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Period |  | Numbers of shares (million) |  | Average price (euro per share) |  | Total cost (euro million) |  | Share capital (%) |  | Share capital (No. of shares)

2014 (From January 6 to December 9) |  | 21.66 |  | 17.55 |  | 380.07 |  | 0.60 |  |
Total purchased as of December 31, 2014 |  | 21.66 |  | 17.55 |  | 380 |  | 0.60 |  | 3,634,185,330
minus: |  |  |  |  |  |  |  |  |  |
- stock option exercised and shares granted pursuant to stock option and stock grant plans |  |  |  |  |  |  |  |  |  |
Total shares held in treasury |  | 21.66 |  |  |  |  |  | 0.60 |  | 3,634,185,330

Period |  | Total numbers of shares purchased |  | Average price paid per share (euro) |  | Total number of shares purchased, as part of publicly announced plans or programs |  | Maximum number of shares that may yet be purchased under the plans or programs

At January 6, 2014 |  | - |  |  |  | - |  | 363,000,000
January 2014 |  | 3,545,000 |  | 17.23 |  | 3,545,000 |  | 359,455,000
February 2014 |  | 3,075,916 |  | 16.93 |  | 6,620,916 |  | 356,379,084
March 2014 |  | 2,229,084 |  | 17.30 |  | 8,850,000 |  | 354,150,000
April 2014 |  | 2,150,000 |  | 18.46 |  | 11,000,000 |  | 352,000,000
May 2014 |  | - |  |  |  | - |  | 352,000,000
June 2014 |  | 530,350 |  | 19.96 |  | 11,530,350 |  | 351,469,650
July 2014 |  | 2,062,000 |  | 19.63 |  | 13,592,350 |  | 349,407,650
August 2014 |  | 2,382,700 |  | 18.56 |  | 15,975,050 |  | 347,024,950
September 2014 |  | 236,860 |  | 19.02 |  | 16,211,910 |  | 346,788,090
October 2014 |  | 2,056,633 |  | 16.52 |  | 18,268,543 |  | 344,731,457
November 2014 |  | 2,266,794 |  | 16.48 |  | 20,535,337 |  | 342,464,663
December 2014 |  | 1,121,573 |  | 15.46 |  | 21,656,910 |  | 341,343,090
December 2014 (through December 9, 2014) |  |  |  |  |  | 21,656,910 |  | 363,000,000
January 2015 |  | - |  |  |  | - |  |
February 2015 |  | - |  |  |  | - |  |
March 2015 |  | - |  |  |  | - |  |

Item 16F. Change in Registrant’s Certifying Accountant

Not applicable.

Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual

Corporate Governance. Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted.

This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities.

The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code for Italian listed companies, which Eni has adopted (hereinafter the Corporate Governance Code).

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> 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 judgment.

Eni’s By-laws require that at least one Director – if the Board has no more than five members – or at least three Directors – if the Board is composed of more than five members – must satisfy the independence requirements.

The Corporate Governance Code provides for additional independence requirements, recommending that the Board of Directors includes an adequate number of independent non-executive Directors. In particular, for issuers belonging to FTSE-MIB index of the Italian Stock Market, like Eni, the Corporate Governance Code recommends that at least one-third of the members of the Board of Directors shall be independent Directors. In any event, independent Directors shall not be fewer than two. Independence is defined as not being currently or recently involved in any direct or indirect relationship with the issuer or other parties associated with the issuer and that may influence his/her independent judgment.

After the appointment of a Director who qualifies as independent and subsequently, upon the occurrence of circumstances affecting the independence requirements and in any case at least once a year, the Board of Directors assesses the independence of the Director. The Board of Statutory Auditors verifies the correct application of the criteria and procedures adopted by the Board of Directors to evaluate the independence of its members.

The Board of Directors shall disclose the result of its evaluations, after the appointment, through a press release to the market and, subsequently, in the Annual Corporate Governance Report.

In accordance with Eni’s By-laws, if a Director does not or no longer satisfies the independence requirements or the minimum number of independent Directors fall below the threshold set by Eni’s By-laws, 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 2014, 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.

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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 member shall be independent Directors.

On 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). The Nomination Committee is made up of three to four Directors, a majority of whom are independent in accordance with the recommendations of the Corporate Governance Code28. 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 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, Alessandro Lorenzi and Diva Moriani. 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

(28) |  | The Committee is currently made up of four Directors, three of whom are independent.

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adopted Eni’s Code of Ethics – replacing the previous version of Eni’s Code of Conduct of 1998. Most recently, the Board of Directors of Eni SpA, in its meetings of April 10 and May 28, 2014, updated Model 231 to incorporate all the types of crimes relevant to the Company pursuant to Legislative Decree No. 231 of 2001. The CEO is responsible for updating Model 231. The CEO is supported in this activity by the "Technical Committee 231", consisting of Units of Chief Legal & Regulatory Affairs, Human Resources and Organization and Internal Audit of the Company.

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 the CEO, who in turn reports on this to the Board of Directors. The composition of the Model 231 Watch Structure – initially formed of only three members – was modified in 2007 with the inclusion of two external members, one of whom was appointed the Chairman of the Watch Structure itself, selected from among academics and professionals with proven experience in economic and business management matters. At present, the Watch Structure of Eni SpA is composed of three external members and three internal members. The internal members are the Chief Legal & Regulatory Officer, the Senior Vice President Relations with Entrepreneurial Associations Coordination and the Senior Executive Vice President Internal Audit of the Company.

On May 28, 2014, the Board of Directors, with the favorable opinion of the Board of Statutory Auditors, appointed the current members of the Watch Structure.

Item 16H. Mine safety disclosure

Not applicable since Eni does not engage in mining operations.

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PART III

Item 17. FINANCIAL STATEMENTS

Not applicable.

Item 18. FINANCIAL STATEMENTS

Index to Financial Statements:

| Page
Report of Independent Registered Public Accounting Firm | F-1
Consolidated Balance Sheet as of December 31, 2014 and 2013 | F-3
Consolidated profit and loss account for the years ended December 31, 2014, 2013 and 2012 | F-4
Consolidated Statements of comprehensive income for the years ended December 31, 2014, 2013 and 2012 | F-5
Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2014, 2013 and 2012 | F-6
Consolidated Statement of cash flows for the years ended December 31, 2014, 2013 and 2012 | F-9
Notes to the Consolidated Financial Statements | F-11

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

> > > To the Board of Directors and Shareholders of Eni SpA

> > > We have audited the accompanying consolidated balance sheets of Eni SpA as of December 31, 2014 and 2013, 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, 2014. 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 SpA at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

> > > We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni SpA’s internal control over financial reporting as of December 31, 2014, 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 April 2, 2015 expressed an unqualified opinion thereon.

> > > /s/ Reconta Ernst & Young SpA

> > > Rome, Italy

> > > April 2, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

> > > To the Board of Directors and Shareholders of Eni SpA

> > > We have audited Eni SpA’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission "2013 framework" (the COSO criteria). Eni SpA 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 on page 183. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

> > > 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 SpA maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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 SpA as of December 31, 2014 and 2013, 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, 2014 and our report dated April 2, 2015 expressed an unqualified opinion thereon.

> > > /s/ Reconta Ernst & Young SpA

> > > Rome, Italy

> > > April 2, 2015

> > F-2

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CONSOLIDATED BALANCE SHEET
(euro million)

|  |  |  | Dec. 31, 2013 |  | Dec. 31, 2014

|  | Note |  | Total amount |  | of which with related parties |  | Total amount |  | of which with related parties

ASSETS |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | (8) |  | 5,431 |  |  |  |  | 6,614 |  |  |
Financial assets held for trading |  | (9) |  | 5,004 |  |  |  |  | 5,024 |  |  |
Financial assets available for sale |  | (10) |  | 235 |  |  |  |  | 257 |  |  |
Trade and other receivables |  | (11) |  | 28,890 |  |  | 1,869 |  | 28,601 |  |  | 1,973
Inventories |  | (12) |  | 7,939 |  |  |  |  | 7,555 |  |  |
Current tax assets |  | (13) |  | 802 |  |  |  |  | 762 |  |  |
Other current tax assets |  | (14) |  | 835 |  |  |  |  | 1,209 |  |  |
Other current assets |  | (15) |  | 1,325 |  |  | 15 |  | 4,385 |  |  | 43
|  |  |  | 50,461 |  |  |  |  | 54,407 |  |  |
Non-current assets |  |  |  |  |  |  |  |  |  |  |  |
Property, plant and equipment |  | (16) |  | 63,763 |  |  |  |  | 71,962 |  |  |
Inventory - compulsory stock |  | (17) |  | 2,573 |  |  |  |  | 1,581 |  |  |
Intangible assets |  | (18) |  | 3,876 |  |  |  |  | 3,645 |  |  |
Equity-accounted investments |  | (19) |  | 3,153 |  |  |  |  | 3,115 |  |  |
Other investments |  | (19) |  | 3,027 |  |  |  |  | 2,015 |  |  |
Other financial assets |  | (20) |  | 858 |  |  | 320 |  | 1,022 |  |  | 239
Deferred tax assets |  | (21) |  | 4,658 |  |  |  |  | 5,231 |  |  |
Other non-current assets |  | (22) |  | 3,676 |  |  | 42 |  | 2,773 |  |  | 12
|  |  |  | 85,584 |  |  |  |  | 91,344 |  |  |
Assets held for sale |  | (33) |  | 2,296 |  |  |  |  | 456 |  |  |
TOTAL ASSETS |  |  |  | 138,341 |  |  |  |  | 146,207 |  |  |
LIABILITIES AND SHAREHOLDERS' EQUITY |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Short-term debt |  | (23) |  | 2,553 |  |  | 264 |  | 2,716 |  |  | 181
Current portion of long-term debt |  | (28) |  | 2,132 |  |  |  |  | 3,859 |  |  |
Trade and other payables |  | (24) |  | 23,701 |  |  | 2,160 |  | 23,703 |  |  | 1,954
Income taxes payable |  | (25) |  | 755 |  |  |  |  | 534 |  |  |
Other taxes payable |  | (26) |  | 2,291 |  |  |  |  | 1,873 |  |  |
Other current liabilities |  | (27) |  | 1,437 |  |  | 17 |  | 4,489 |  |  | 58
|  |  |  | 32,869 |  |  |  |  | 37,174 |  |  |
Non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  | (28) |  | 20,875 |  |  |  |  | 19,316 |  |  |
Provisions for contingencies |  | (29) |  | 13,120 |  |  |  |  | 15,898 |  |  |
Provisions for employee benefits |  | (30) |  | 1,279 |  |  |  |  | 1,313 |  |  |
Deferred tax liabilities |  | (31) |  | 6,750 |  |  |  |  | 7,847 |  |  |
Other non-current liabilities |  | (32) |  | 2,259 |  |  |  |  | 2,285 |  |  | 20
|  |  |  | 44,283 |  |  |  |  | 46,659 |  |  |
Liabilities directly associated with assets held for sale |  | (33) |  | 140 |  |  |  |  | 165 |  |  |
TOTAL LIABILITIES |  |  |  | 77,292 |  |  |  |  | 83,998 |  |  |
SHAREHOLDERS' EQUITY |  | (34) |  |  |  |  |  |  |  |  |  |
Non-controlling interest |  |  |  | 2,839 |  |  |  |  | 2,455 |  |  |
Eni shareholders' equity |  |  |  |  |  |  |  |  |  |  |  |
Share capital |  |  |  | 4,005 |  |  |  |  | 4,005 |  |  |
Reserve related to cash flow hedging derivatives net of tax effect |  |  |  | (154 | ) |  |  |  | (284 | ) |  |
Other reserves |  |  |  | 51,393 |  |  |  |  | 57,343 |  |  |
Treasury shares |  |  |  | (201 | ) |  |  |  | (581 | ) |  |
Interim dividend |  |  |  | (1,993 | ) |  |  |  | (2,020 | ) |  |
Net profit |  |  |  | 5,160 |  |  |  |  | 1,291 |  |  |
Total Eni shareholders' equity |  |  |  | 58,210 |  |  |  |  | 59,754 |  |  |
TOTAL SHAREHOLDERS' EQUITY |  |  |  | 61,049 |  |  |  |  | 62,209 |  |  |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY |  |  |  | 138,341 |  |  |  |  | 146,207 |  |  |

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)

|  | 2012 |  | 2013 |  | 2014

|  | Note |  | Total amount |  | of which with related parties |  | Total amount |  | of which with related parties |  | Total amount |  | of which with related parties

REVENUES |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from operations |  | (37) |  | 127,109 |  |  | 3,622 |  |  | 114,697 |  |  | 3,184 |  |  | 109,847 |  |  | 2,604 |
Other income and revenues |  |  |  | 1,548 |  |  | 57 |  |  | 1,387 |  |  | 33 |  |  | 1,101 |  |  | 69 |
|  |  |  | 128,657 |  |  |  |  |  | 116,084 |  |  |  |  |  | 110,948 |  |  |  |
OPERATING EXPENSES |  | (38) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchases, services and other |  |  |  | 95,034 |  |  | 6,093 |  |  | 90,003 |  |  | 7,897 |  |  | 86,340 |  |  | 7,382 |
Payroll and related costs |  |  |  | 4,640 |  |  | 21 |  |  | 5,301 |  |  | 41 |  |  | 5,337 |  |  | 61 |
OTHER OPERATING (EXPENSE) INCOME |  | (38) |  | (158 | ) |  | 10 |  |  | (71 | ) |  | 68 |  |  | 145 |  |  | 208 |
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS |  | (38) |  | 13,617 |  |  |  |  |  | 11,821 |  |  |  |  |  | 11,499 |  |  |  |
OPERATING PROFIT |  |  |  | 15,208 |  |  |  |  |  | 8,888 |  |  |  |  |  | 7,917 |  |  |  |
FINANCE INCOME (EXPENSE) |  | (39) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Finance income |  |  |  | 7,208 |  |  | 28 |  |  | 5,732 |  |  | 41 |  |  | 6,459 |  |  | 46 |
Finance expense |  |  |  | (8,327 | ) |  | (2 | ) |  | (6,653 | ) |  | (85 | ) |  | (7,710 | ) |  | (55 | )
Finance income from financial assets held for trading, net |  |  |  |  |  |  |  |  |  | 4 |  |  |  |  |  | 24 |  |  |  |
Derivative financial instruments |  |  |  | (252 | ) |  |  |  |  | (92 | ) |  |  |  |  | 162 |  |  |  |
|  |  |  | (1,371 | ) |  |  |  |  | (1,009 | ) |  |  |  |  | (1,065 | ) |  |  |
INCOME (EXPENSE) FROM INVESTMENTS |  | (40) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Share of profit (loss) from equity-accounted investments |  |  |  | 186 |  |  |  |  |  | 222 |  |  |  |  |  | 121 |  |  |  |
Other gain (loss) from investments |  |  |  | 2,603 |  |  |  |  |  | 5,863 |  |  |  |  |  | 369 |  |  |  |
- of which gain on disposals of the 28.57% of Eni East Africa |  |  |  |  |  |  |  |  |  | 3,359 |  |  |  |  |  |  |  |  |  |
|  |  |  | 2,789 |  |  |  |  |  | 6,085 |  |  |  |  |  | 490 |  |  |  |
PROFIT BEFORE INCOME TAXES |  |  |  | 16,626 |  |  |  |  |  | 13,964 |  |  |  |  |  | 7,342 |  |  |  |
Income taxes |  | (41) |  | (11,679 | ) |  |  |  |  | (9,005 | ) |  |  |  |  | (6,492 | ) |  |  |
Net profit for the year - Continuing operations |  |  |  | 4,947 |  |  |  |  |  | 4,959 |  |  |  |  |  | 850 |  |  |  |
Net profit (loss) for the year - Discontinued operations |  |  |  | 3,732 |  |  | 2,234 |  |  |  |  |  |  |  |  |  |  |  |  |
Net profit for the year |  |  |  | 8,679 |  |  |  |  |  | 4,959 |  |  |  |  |  | 850 |  |  |  |
Attributable to Eni |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  |  |  | 4,200 |  |  |  |  |  | 5,160 |  |  |  |  |  | 1,291 |  |  |  |
Discontinued operations |  |  |  | 3,590 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  | 7,790 |  |  |  |  |  | 5,160 |  |  |  |  |  | 1,291 |  |  |  |
Attributable to non-controlling interest |  | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  |  |  | 747 |  |  |  |  |  | (201 | ) |  |  |  |  | (441 | ) |  |  |
Discontinued operations |  |  |  | 142 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  | 889 |  |  |  |  |  | (201 | ) |  |  |  |  | (441 | ) |  |  |
Earnings per share attributable to Eni (euro per share) |  | (42) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  |  | 2.15 |  |  |  |  |  | 1.42 |  |  |  |  |  | 0.36 |  |  |  |
Diluted |  |  |  | 2.15 |  |  |  |  |  | 1.42 |  |  |  |  |  | 0.36 |  |  |  |
Earnings per share attributable to Eni - Continuing operations (euro per share) |  | (42) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  |  | 1.16 |  |  |  |  |  | 1.42 |  |  |  |  |  | 0.36 |  |  |  |
Diluted |  |  |  | 1.16 |  |  |  |  |  | 1.42 |  |  |  |  |  | 0.36 |  |  |  |

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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(euro million)

|  | Note |  | 2012 |  | 2013 |  | 2014

Net profit |  |  |  | 8,679 |  |  | 4,959 |  |  | 850 |
Other items of comprehensive income |  |  |  |  |  |  |  |  |  |  |
Items not to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |
Remeasurements of defined benefit plans |  | (34) |  | (151 | ) |  | 65 |  |  | (82 | )
Share of other comprehensive income on equity-accounted entities in relation to remeasurements of defined benefit plans |  | (34) |  | 2 |  |  | (3 | ) |  | 3 |
Tax effect related to other comprehensive income to be reclassified to profit or loss in subsequent periods |  | (34) |  | 53 |  |  | (40 | ) |  | 22 |
|  |  |  | (96 | ) |  | 22 |  |  | (57 | )
Other comprehensive income to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |
Foreign currency translation differences |  | (34) |  | (716 | ) |  | (1,871 | ) |  | 5,008 |
Change in the fair value of available-for-sale investments |  | (34) |  | 141 |  |  | (64 | ) |  | (77 | )
Change in the fair value of other available-for-sale financial instruments |  | (34) |  | 16 |  |  | (1 | ) |  | 7 |
Change in the fair value of cash flow hedging derivatives |  | (34) |  | (103 | ) |  | (198 | ) |  | (167 | )
Share of other comprehensive income on equity-accounted entities |  | (34) |  | 8 |  |  |  |  |  | 4 |
Tax effect related to other comprehensive income not to be reclassified to profit or loss in subsequent periods |  | (34) |  | 32 |  |  | 63 |  |  | 30 |
|  |  |  | (622 | ) |  | (2,071 | ) |  | 4,805 |
Total other items of comprehensive income |  |  |  | (718 | ) |  | (2,049 | ) |  | 4,748 |
Total comprehensive income |  |  |  | 7,961 |  |  | 2,910 |  |  | 5,598 |
Attributable to: |  |  |  |  |  |  |  |  |  |  |
Eni |  |  |  | 7,096 |  |  | 3,164 |  |  | 5,996 |
Non-controlling interest |  |  |  | 865 |  |  | (254 | ) |  | (398 | )
|  |  |  | 7,961 |  |  | 2,910 |  |  | 5,598 |

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (euro million)

|  | Eni shareholders’ equity |  |

|  | `Share capital` |  | `Legal reserve of Eni SpA` |  | `Reserve for treasury shares` |  | `Reserve related to the fair value of cash flow hedging derivatives net of the tax effect` |  | `Reserve related to the fair value of available-for-sale financial instruments net of the tax effect` |  | `Reserve for defined benefit plans net of tax effect` |  | `Other reserves` |  | `Cumulative currency translation differences` |  | `Treasury shares` |  | `Retained earnings` |  | `Interim dividend` |  | `Net profit for the year` |  | `Total` |  | `Non- controlling interest` |  | `Total shareholders’ equity`

Balance at December 31, 2011 |  |  | 4,005 |  |  | 959 |  |  | 6,753 |  |  | 49 |  |  | (8 | ) |  |  |  |  | 1,421 |  |  | 1,539 |  |  | (6,753 | ) |  | 42,531 |  |  | (1,884 | ) |  | 6,860 |  |  | 55,472 |  |  | 4,921 |  |  | 60,393 |
Changes in accounting principles (IFRS 10 and 11) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (151 | ) |  | (151 | )
Changes in accounting principles (IAS 19) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (52 | ) |  |  |  |  |  |  |  | (52 | ) |  | (9 | ) |  | (61 | )
Balance at January 1, 2012 |  |  | 4,005 |  |  | 959 |  |  | 6,753 |  |  | 49 |  |  | (8 | ) |  |  |  |  | 1,421 |  |  | 1,539 |  |  | (6,753 | ) |  | 42,479 |  |  | (1,884 | ) |  | 6,860 |  |  | 55,420 |  |  | 4,761 |  |  | 60,181 |
Net profit of the year |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,790 |  |  | 7,790 |  |  | 889 |  |  | 8,679 |
Other items of comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Items not to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Remeasurements of defined benefit plans net of tax effect |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (88 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (88 | ) |  | (10 | ) |  | (98 | )
Share of "Other comprehensive income" on equity-accounted entities in relation to remeasurements of defined benefit plans net of tax effect |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2 |  |  | 2 |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (88 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (88 | ) |  | (8 | ) |  | (96 | )
Other comprehensive income to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency translation differences |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (597 | ) |  |  |  |  | (104 | ) |  |  |  |  |  |  |  | (701 | ) |  | (15 | ) |  | (716 | )
Change and reversal of the fair value of investments net of tax effect |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 138 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 138 |  |  |  |  |  | 138 |
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 14 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 14 |  |  |  |  |  | 14 |
Change and reversal of the fair value of cash flow hedge derivatives net of tax effect |  |  |  |  |  |  |  |  |  |  |  | (65 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (65 | ) |  | (1 | ) |  | (66 | )
Share of "Other comprehensive income" on equity-accounted investments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8 |  |  |  |  |  | 8 |
|  |  |  |  |  |  |  |  |  |  |  | (65 | ) |  | 152 |  |  |  |  |  | 8 |  |  | (597 | ) |  |  |  |  | (104 | ) |  |  |  |  |  |  |  | (606 | ) |  | (16 | ) |  | (622 | )
Total comprehensive income of the year |  |  |  |  |  |  |  |  |  |  |  | (65 | ) |  | 152 |  |  | (88 | ) |  | 8 |  |  | (597 | ) |  |  |  |  | (104 | ) |  |  |  |  | 7,790 |  |  | 7,096 |  |  | 865 |  |  | 7,961 |
Transactions with shareholders |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dividend distribution of Eni SpA (euro 0.52 per share in settlement of 2011 interim dividend of euro 0.52 per share) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,884 |  |  | (3,768 | ) |  | (1,884 | ) |  |  |  |  | (1,884 | )
Interim dividend distribution of Eni SpA (euro 0.54 per share) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1,956 | ) |  |  |  |  | (1,956 | ) |  |  |  |  | (1,956 | )
Dividend distribution of other companies |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (681 | ) |  | (681 | )
Allocation of 2011 net profit |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,092 |  |  |  |  |  | (3,092 | ) |  |  |  |  |  |  |  |  |
Effect related to the sale of Snam SpA |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 371 |  |  |  |  |  |  |  |  | 371 |  |  | (1,602 | ) |  | (1,231 | )
Acquisition of non-controlling interest relating to Altergaz SA and Tigáz Zrt |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (4 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (4 | ) |  | (3 | ) |  | (7 | )
Treasury shares sold following the exercise of stock options exercised by Eni managers |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  | 1 |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  | 1 |
Treasury shares sold following the exercise of stock options by Saipem managers |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7 |  |  | 22 |  |  | 29 |
|  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  | 3 |  |  |  |  |  | 1 |  |  | 3,464 |  |  | (72 | ) |  | (6,860 | ) |  | (3,465 | ) |  | (2,264 | ) |  | (5,729 | )
Other changes in shareholders’ equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Elimination of treasury shares |  |  |  |  |  |  |  |  | (6,551 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 6,551 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reconstitution of the reserve for treasury share |  |  |  |  |  |  |  |  | 6,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (6,000 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Stock options expired |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (7 | ) |  |  |  |  |  |  |  | (7 | ) |  |  |  |  | (7 | )
Other changes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1,140 | ) |  |  |  |  |  |  |  | 1,156 |  |  |  |  |  |  |  |  | 16 |  |  | (5 | ) |  | 11 |
|  |  |  |  |  |  |  |  | (551 | ) |  |  |  |  |  |  |  |  |  |  | (1,140 | ) |  |  |  |  | 6,551 |  |  | (4,851 | ) |  |  |  |  |  |  |  | 9 |  |  | (5 | ) |  | 4 |
Balance at December 31, 2012 |  |  | 4,005 |  |  | 959 |  |  | 6,201 |  |  | (16 | ) |  | 144 |  |  | (88 | ) |  | 292 |  |  | 942 |  |  | (201 | ) |  | 40,988 |  |  | (1,956 | ) |  | 7,790 |  |  | 59,060 |  |  | 3,357 |  |  | 62,417 |

F-6

##### Table of Contents

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued (euro million)

|  | Eni shareholders’ equity |  |

`Note` |  | `Share capital` |  | `Legal reserve of Eni SpA` |  | `Reserve for treasury shares` |  | `Reserve related to the fair value of cash flow hedging derivatives net of the tax effect` |  | `Reserve related to the fair value of available-for-sale financial instruments net of the tax effect` |  | `Reserve for defined benefit plans net of tax effect` |  | `Other reserves` |  | `Cumulative currency translation differences` |  | `Treasury shares` |  | `Retained earnings` |  | `Interim dividend` |  | `Net profit for the year` |  | `Total` |  | `Non- controlling interest` |  | `Total shareholders’ equity`

Balance at December 31, 2012 |  |  | 4,005 |  |  | 959 |  |  | 6,201 |  |  | (16 | ) |  | 144 |  |  | (88 | ) |  | 292 |  |  | 942 |  |  | (201 | ) |  | 40,988 |  |  | (1,956 | ) |  | 7,790 |  |  | 59,060 |  |  | 3,357 |  |  | 62,417 |
Net profit of the year |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 5,160 |  |  | 5,160 |  |  | (201 | ) |  | 4,959 |
Other items of comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Items not to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Remeasurements of defined benefit plans net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 18 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 18 |  |  | 7 |  |  | 25 |
Share of "Other comprehensive income" on equity-accounted entities in relation to remeasurements of defined benefit plans net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  | (2 | ) |  | (3 | )
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 17 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 17 |  |  | 5 |  |  | 22 |
Other comprehensive income to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency translation differences | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  | (1,640 | ) |  |  |  |  | (171 | ) |  |  |  |  |  |  |  | (1,812 | ) |  | (59 | ) |  | (1,871 | )
Change and reversal of the fair value of investments net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  | (62 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (62 | ) |  |  |  |  | (62 | )
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  | (1 | )
Change and reversal of the fair value of cash flow hedge derivatives net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  | (138 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (138 | ) |  | 1 |  |  | (137 | )
|  |  |  |  |  |  |  |  |  |  |  | (138 | ) |  | (63 | ) |  | (1 | ) |  |  |  |  | (1,640 | ) |  |  |  |  | (171 | ) |  |  |  |  |  |  |  | (2,013 | ) |  | (58 | ) |  | (2,071 | )
Total comprehensive income of the year |  |  |  |  |  |  |  |  |  |  |  | (138 | ) |  | (63 | ) |  | 16 |  |  |  |  |  | (1,640 | ) |  |  |  |  | (171 | ) |  |  |  |  | 5,160 |  |  | 3,164 |  |  | (254 | ) |  | 2,910 |
Transactions with shareholders |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dividend distribution of Eni SpA (euro 0.54 per share in settlement of 2012 interim dividend of euro 0.54 per share) | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (829 | ) |  | 1,956 |  |  | (3,083 | ) |  | (1,956 | ) |  |  |  |  | (1,956 | )
Interim dividend distribution of Eni SpA (euro 0.55 per share) | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1,993 | ) |  |  |  |  | (1,993 | ) |  |  |  |  | (1,993 | )
Dividend distribution of other companies |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (250 | ) |  | (250 | )
Allocation of 2012 net profit |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4,707 |  |  |  |  |  | (4,707 | ) |  |  |  |  |  |  |  |  |
Acquisition of non-controlling interest relating to Tigáz Zrt | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4 |  |  | (32 | ) |  | (28 | )
Payments and reimbursements by/to minority shareholders | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  | 1 |
Treasury shares sold following the exercise of stock options by Saipem managers | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  | 1 |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4 |  |  |  |  |  |  |  |  | 3,878 |  |  | (37 | ) |  | (7,790 | ) |  | (3,945 | ) |  | (280 | ) |  | (4,225 | )
Other changes in shareholders’ equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Elimination of intercompany profit between companies with different Group interest |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (32 | ) |  |  |  |  |  |  |  | (32 | ) |  | 32 |  |  |  |
Stock options expired |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (13 | ) |  |  |  |  |  |  |  | (13 | ) |  |  |  |  | (13 | )
Other changes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (24 | ) |  |  |  |  |  |  |  | (24 | ) |  | (16 | ) |  | (40 | )
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (69 | ) |  |  |  |  |  |  |  | (69 | ) |  | 16 |  |  | (53 | )
Balance at December 31, 2013 | (34) |  | 4,005 |  |  | 959 |  |  | 6,201 |  |  | (154 | ) |  | 81 |  |  | (72 | ) |  | 296 |  |  | (698 | ) |  | (201 | ) |  | 44,626 |  |  | (1,993 | ) |  | 5,160 |  |  | 58,210 |  |  | 2,839 |  |  | 61,049 |

F-7

##### Table of Contents

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued (euro million)

|  | Eni shareholders’ equity |  |

`Note` |  | `Share capital` |  | `Legal reserve of Eni SpA` |  | `Reserve for treasury shares` |  | `Reserve related to the fair value of cash flow hedging derivatives net of the tax effect` |  | `Reserve related to the fair value of available-for-sale financial instruments net of the tax effect` |  | `Reserve for defined benefit plans net of tax effect` |  | `Other reserves` |  | `Cumulative currency translation differences` |  | `Treasury shares` |  | `Retained earnings` |  | `Interim dividend` |  | `Net profit for the year` |  | `Total` |  | `Non- controlling interest` |  | `Total shareholders’ equity`

Balance at December 31, 2013 | (34) |  | 4,005 |  |  | 959 |  |  | 6,201 |  |  | (154 | ) |  | 81 |  |  | (72 | ) |  | 296 |  |  | (698 | ) |  | (201 | ) |  | 44,626 |  |  | (1,993 | ) |  | 5,160 |  |  | 58,210 |  |  | 2,839 |  |  | 61,049 |
Net profit of the year |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,291 |  |  | 1,291 |  |  | (441 | ) |  | 850 |
Other items of comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Items not to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revaluations of defined benefit plans net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (51 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (51 | ) |  | (9 | ) |  | (60 | )
Share of "Other comprehensive income" on equity-accounted entities in relation to revaluations of defined benefit plans net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2 |  |  | 1 |  |  | 3 |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (49 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (49 | ) |  | (8 | ) |  | (57 | )
Other comprehensive income to be reclassified to profit or loss in subsequent periods |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency translation differences | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  | 4,718 |  |  |  |  |  | 232 |  |  |  |  |  |  |  |  | 4,949 |  |  | 59 |  |  | 5,008 |
Change and reversal of the fair value of investments net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  | (76 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (76 | ) |  |  |  |  | (76 | )
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  | 6 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 6 |  |  |  |  |  | 6 |
Change and reversal the fair value of cash flow hedge derivatives net of tax effect | (34) |  |  |  |  |  |  |  |  |  |  | (130 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (130 | ) |  | (7 | ) |  | (137 | )
Share of "Other comprehensive income" on equity-accounted entities | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 5 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 5 |  |  | (1 | ) |  | 4 |
|  |  |  |  |  |  |  |  |  |  |  | (130 | ) |  | (70 | ) |  | (1 | ) |  | 5 |  |  | 4,718 |  |  |  |  |  | 232 |  |  |  |  |  |  |  |  | 4,754 |  |  | 51 |  |  | 4,805 |
Total comprehensive income of the year |  |  |  |  |  |  |  |  |  |  |  | (130 | ) |  | (70 | ) |  | (50 | ) |  | 5 |  |  | 4,718 |  |  |  |  |  | 232 |  |  |  |  |  | 1,291 |  |  | 5,996 |  |  | (398 | ) |  | 5,598 |
Transactions with shareholders |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dividend distribution of Eni SpA (euro 0.55 per share in settlement of 2013 interim dividend of euro 0.55 per share) | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,993 |  |  | (3,979 | ) |  | (1,986 | ) |  |  |  |  | (1,986 | )
Interim dividend distribution of Eni SpA (euro 0.56 per share) | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2,020 | ) |  |  |  |  | (2,020 | ) |  |  |  |  | (2,020 | )
Dividend distribution of other companies |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (49 | ) |  | (49 | )
Allocation of 2013 net profit |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,181 |  |  |  |  |  | (1,181 | ) |  |  |  |  |  |  |  |  |
Acquisition of treasury shares | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (380 | ) |  |  |  |  |  |  |  |  |  |  | (380 | ) |  |  |  |  | (380 | )
Payments and reimbursements by/to minority shareholders | (34) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  | 1 |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (380 | ) |  | 1,181 |  |  | (27 | ) |  | (5,160 | ) |  | (4,386 | ) |  | (48 | ) |  | (4,434 | )
Other changes in shareholders’ equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Elimination of intercompany profit between companies with different Group interest |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (62 | ) |  |  |  |  |  |  |  | (62 | ) |  | 62 |  |  |  |
Stock options expired |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (7 | ) |  |  |  |  |  |  |  | (7 | ) |  |  |  |  | (7 | )
Other changes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (94 | ) |  |  |  |  |  |  |  | 97 |  |  |  |  |  |  |  |  | 3 |  |  |  |  |  | 3 |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (94 | ) |  |  |  |  |  |  |  | 28 |  |  |  |  |  |  |  |  | (66 | ) |  | 62 |  |  | (4 | )
Balance at December 31, 2014 | (34) |  | 4,005 |  |  | 959 |  |  | 6,201 |  |  | (284 | ) |  | 11 |  |  | (122 | ) |  | 207 |  |  | 4,020 |  |  | (581 | ) |  | 46,067 |  |  | (2,020 | ) |  | 1,291 |  |  | 59,754 |  |  | 2,455 |  |  | 62,209 |

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)

|  | Note |  | 2012 |  | 2013 |  | 2014

Net profit of the year - Continuing operations |  |  |  |  |  |  | 4,947 |  |  |  |  |  | 4,959 |  |  |  |  |  | 850 |
Adjustments to reconcile net profit to net cash provided by operating activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization |  | (38) |  |  |  |  | 9,645 |  |  |  |  |  | 9,421 |  |  |  |  |  | 9,970 |
Impairments of tangible and intangible assets, net |  | (38) |  |  |  |  | 3,972 |  |  |  |  |  | 2,400 |  |  |  |  |  | 1,529 |
Share of (profit) loss of equity-accounted investments |  | (40) |  |  |  |  | (186 | ) |  |  |  |  | (222 | ) |  |  |  |  | (121 | )
Gain on disposal of assets, net |  |  |  |  |  |  | (875 | ) |  |  |  |  | (3,770 | ) |  |  |  |  | (95 | )
Dividend income |  | (40) |  |  |  |  | (431 | ) |  |  |  |  | (400 | ) |  |  |  |  | (385 | )
Interest income |  |  |  |  |  |  | (94 | ) |  |  |  |  | (142 | ) |  |  |  |  | (171 | )
Interest expense |  |  |  |  |  |  | 808 |  |  |  |  |  | 711 |  |  |  |  |  | 719 |
Income taxes |  | (41) |  |  |  |  | 11,679 |  |  |  |  |  | 9,005 |  |  |  |  |  | 6,492 |
Other changes |  |  |  |  |  |  | (1,947 | ) |  |  |  |  | (1,882 | ) |  |  |  |  | 744 |
Changes in working capital: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- inventories |  |  |  | (1,402 | ) |  |  |  |  | 350 |  |  |  |  |  | 1,524 |  |  |  |
- trade receivables |  |  |  | (3,161 | ) |  |  |  |  | (1,379 | ) |  |  |  |  | 2,344 |  |  |  |
- trade payables |  |  |  | 2,014 |  |  |  |  |  | 703 |  |  |  |  |  | (1,253 | ) |  |  |
- provisions for contingencies |  |  |  | 329 |  |  |  |  |  | 59 |  |  |  |  |  | (187 | ) |  |  |
- other assets and liabilities |  |  |  | (1,061 | ) |  |  |  |  | 723 |  |  |  |  |  | 240 |  |  |  |
Cash flow from changes in working capital |  |  |  |  |  |  | (3,281 | ) |  |  |  |  | 456 |  |  |  |  |  | 2,668 |
Net change in the provisions for employee benefits |  |  |  |  |  |  | 17 |  |  |  |  |  | 6 |  |  |  |  |  | 9 |
Dividends received |  |  |  |  |  |  | 930 |  |  |  |  |  | 630 |  |  |  |  |  | 612 |
Interest received |  |  |  |  |  |  | 79 |  |  |  |  |  | 97 |  |  |  |  |  | 112 |
Interest paid |  |  |  |  |  |  | (829 | ) |  |  |  |  | (942 | ) |  |  |  |  | (882 | )
Income taxes paid, net of tax receivables received |  |  |  |  |  |  | (11,882 | ) |  |  |  |  | (9,301 | ) |  |  |  |  | (6,941 | )
Net cash provided by operating activities - Continuing operations |  |  |  |  |  |  | 12,552 |  |  |  |  |  | 11,026 |  |  |  |  |  | 15,110 |
Net cash provided by operating activities - Discontinued operations |  |  |  |  |  |  | 15 |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by operating activities |  |  |  |  |  |  | 12,567 |  |  |  |  |  | 11,026 |  |  |  |  |  | 15,110 |
- of which with related parties |  | (44) |  |  |  |  | (1,117 | ) |  |  |  |  | (2,911 | ) |  |  |  |  | (3,203 | )
Investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- tangible assets |  | (16) |  |  |  |  | (11,267 | ) |  |  |  |  | (10,913 | ) |  |  |  |  | (10,685 | )
- intangible assets |  | (18) |  |  |  |  | (2,294 | ) |  |  |  |  | (1,887 | ) |  |  |  |  | (1,555 | )
- consolidated subsidiaries and businesses |  | (35) |  |  |  |  | (178 | ) |  |  |  |  | (25 | ) |  |  |  |  | (36 | )
- investments |  | (19) |  |  |  |  | (391 | ) |  |  |  |  | (292 | ) |  |  |  |  | (372 | )
- securities |  |  |  |  |  |  | (17 | ) |  |  |  |  | (5,048 | ) |  |  |  |  | (77 | )
- financing receivables |  |  |  |  |  |  | (1,542 | ) |  |  |  |  | (978 | ) |  |  |  |  | (1,289 | )
- change in payables and receivables in relation to investing activities and capitalized depreciation |  |  |  |  |  |  | 54 |  |  |  |  |  | 50 |  |  |  |  |  | 669 |
Cash flow from investing activities |  |  |  |  |  |  | (15,635 | ) |  |  |  |  | (19,093 | ) |  |  |  |  | (13,345 | )
Disposals: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- tangible assets |  |  |  |  |  |  | 1,240 |  |  |  |  |  | 514 |  |  |  |  |  | 97 |
- intangible assets |  |  |  |  |  |  | 61 |  |  |  |  |  | 16 |  |  |  |  |  | 8 |
- consolidated subsidiaries and businesses |  | (35) |  |  |  |  | 3,521 |  |  |  |  |  | 3,401 |  |  |  |  |  |  |
- investments |  |  |  |  |  |  | 1,203 |  |  |  |  |  | 2,429 |  |  |  |  |  | 3,579 |
- securities |  |  |  |  |  |  | 54 |  |  |  |  |  | 36 |  |  |  |  |  | 57 |
- financing receivables |  |  |  |  |  |  | 1,431 |  |  |  |  |  | 1,561 |  |  |  |  |  | 506 |
- change in payables and receivables in relation to disposals |  |  |  |  |  |  | (252 | ) |  |  |  |  | 155 |  |  |  |  |  | 155 |
Cash flow from disposals |  |  |  |  |  |  | 7,258 |  |  |  |  |  | 8,112 |  |  |  |  |  | 4,402 |
Net cash used in investing activities |  |  |  |  |  |  | (8,377 | ) |  |  |  |  | (10,981 | ) |  |  |  |  | (8,943 | )
- of which with related parties |  | (44) |  |  |  |  | 1,485 |  |  |  |  |  | (390 | ) |  |  |  |  | (1,458 | )

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CONSOLIDATED STATEMENT OF CASH FLOWS continued
(euro million)

|  | Note |  | 2012 |  | 2013 |  | 2014

Proceeds from long-term debt |  | (28) |  | 10,506 |  |  | 5,418 |  |  | 1,916 |
Repayments of long-term debt |  | (28) |  | (3,961 | ) |  | (4,720 | ) |  | (2,751 | )
Increase (decrease) in short-term debt |  | (23) |  | (731 | ) |  | 1,017 |  |  | 207 |
|  |  |  | 5,814 |  |  | 1,715 |  |  | (628 | )
Net capital contributions by non-controlling interest |  |  |  |  |  |  | 1 |  |  | 1 |
Sale of treasury shares different from Eni SpA |  |  |  | 29 |  |  | 1 |  |  |  |
Sale (acquisition) of additional interests in consolidated subsidiaries |  |  |  | 604 |  |  | (28 | ) |  |  |
Dividends paid to Eni's shareholders |  |  |  | (3,840 | ) |  | (3,949 | ) |  | (4,006 | )
Dividends paid to non-controlling interest |  |  |  | (536 | ) |  | (250 | ) |  | (49 | )
Acquisition of treasury shares |  |  |  |  |  |  |  |  |  | (380 | )
Net cash used in financing activities |  |  |  | 2,071 |  |  | (2,510 | ) |  | (5,062 | )
- of which with related parties |  | (44) |  | (93 | ) |  | 119 |  |  | (99 | )
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries) |  |  |  | (4 | ) |  | 2 |  |  | 2 |
Effect of exchange rate changes on cash and cash equivalents and other changes |  |  |  | (12 | ) |  | (42 | ) |  | 76 |
Net cash flow of the year |  |  |  | 6,245 |  |  | (2,505 | ) |  | 1,183 |
Cash and cash equivalents - beginning of the year |  | (8) |  | 1,691 |  |  | 7,936 |  |  | 5,431 |
Cash and cash equivalents - end of the year |  | (8) |  | 7,936 |  |  | 5,431 |  |  | 6,614 |

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##### Table of Contents

Notes on Consolidated Financial Statements

1 Basis of presentation

The Consolidated Financial Statements of Eni Group have been prepared in accordance with the 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 conformity with internationally accepted accounting standards. Specifically, this concerns the determination of the amortization expenses using the unit-of-production method and the recognition of the production sharing agreement and buy-back contracts. The Consolidated Financial Statements have been prepared on a historical cost basis, taking into account, where appropriate, value adjustments, except for certain items that under IFRS must be measured at fair value as described in the paragraph "Summary of significant accounting policies".

The 2014 Consolidated Financial Statements approved by Eni’s Board of Directors on April 2, 2015, were audited by the independent auditor Reconta Ernst & Young SpA. The independent auditor of Eni SpA, as the main auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other independent auditors, he 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 include the financial statements of the parent company Eni SpA and those of its subsidiaries. Control of an investee exists when the investor is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. 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 and gas contracts on behalf of companies participating in a joint project, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized proportionally directly in the financial statements of the companies involved. 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.

The income and expense of a subsidiary are included in the Consolidated Financial Statements from the acquisition date until the date when the parent ceases to control the subsidiary. 100% of assets, liabilities, income and expenses of consolidated subsidiaries are combined with those of the parent in the Consolidated Financial Statements; the book value of these subsidiaries is eliminated against the corresponding share of the shareholders’ equity. Equity and net profit of non-controlling interests are included in specific lines of equity and profit and loss account.

The purchase of additional equity interests in subsidiaries from non-controlling interests is recognized in the Group shareholders’ equity and represents the excess of the amount paid over the carrying value of the non-controlling interests acquired; similarly, the effects of the sale of non-controlling interests in subsidiaries without loss of control are recognized in 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 share of equity; (ii) any gain or loss recognized as a result of remeasuring to fair value any investment retained in the former subsidiary; and (iii) any amount related to the former subsidiary previously recognized in other comprehensive income which can be reclassified subsequently to 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.

(1) |  | IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations issued by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).
(2) |  | According to the requirements of the Conceptual Framework of IFRS, information is material if its omission or misstatement could influence the economic decisions that users make on the basis of the financial statements.
(3) |  | Conversely, any component related to the former subsidiary previously recognized in other comprehensive income, which can not be reclassified subsequently to profit and loss account, are reclassified within retained earnings.

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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 have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement. In the Consolidated Financial Statements the Eni’s share of the assets/liabilities and revenues/expenses of the 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 measured under the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of 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.

The equity method of accounting
Investments in unconsolidated subsidiaries, joint ventures and associates are accounted for using the equity method4.

Under the equity method, investments are initially recognized at cost, allocating any difference between the cost of the investment and the investor’s share of the net fair value of the investee’s identifiable net assets similarly to the recognition principles of business combination. Subsequently, the carrying amount is adjusted to reflect: (i) the investor’s share of the post-acquisition profit or loss of the investee; 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 investee are recorded as a reduction of the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also paragraph "Principles of consolidation"). 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". Unconsolidated subsidiaries, joint ventures and associates are accounted for at cost, net of impairment losses if this does not result in a misrepresentation of the Company’s financial position and performance. When an impairment loss no longer exists, a reversal of the impairment loss is recognized in 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 remeasuring to fair value any investment retained in the former joint venture/associate5; 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

(4) |  | 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.
(5) |  | If the retained investment continues to be accounted for using the equity method, no remeasurement to fair value is recognized in profit and loss account.
(6) |  | Conversely, any component related to the former joint venture/associate previously recognized in other comprehensive income, which cannot be reclassified subsequently to profit and loss account, are reclassified within retained earnings.

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at the date when joint control or significant influence are lost and shall be accounted for in accordance with the applicable measurement criteria.

The investor’s share of losses of an investee, that exceeds its interest in the investee, 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 combination transactions are recognized by applying the acquisition method. The consideration transferred in a business combination is measured at the acquisition date and is the sum of the fair value of the assets transferred, the liabilities incurred, as well as any equity instruments issued by the acquirer. Acquisition-related costs are recognized in profit and loss account 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 IFRSs provide exceptions to this measurement principle. The surplus of the cost of investment over the Group’s share of the net fair value of the identifiable assets and liabilities is recognized as goodwill; a gain from a bargain purchase is recognized in the profit and loss account.

Any non-controlling interest is measured as the proportionate share of 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 interest in the acquiree and the consideration transferred for the acquisition of control; the previously held equity interest is remeasured at its acquisition-date fair value and the resulting gain or loss, if any, is recognized in profit and loss account. Furthermore, on acquisition of control, any amount of the acquiree previously recognized in other comprehensive income is charged to profit and loss account or in another item of equity, when the amount cannot be reclassified to profit and loss account. If it is gained control over a business formerly classified as joint operation, the previously held portion of the net assets 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.

Intragroup transactions
All balances and transactions between consolidated companies, including unrealized profits arising from such transactions, have been eliminated.

Unrealized profits 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 provide evidence of impairment loss of the asset transferred.

Foreign currency translation
Financial statements of foreign investees having a functional currency other than the euro, that represents the Group’s functional currency, are translated into euro using the rates of exchange ruling at the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account (source: Bank of Italy). The cumulative amount of exchange rate differences is presented in the separate component of the Group shareholders’ equity "Cumulative currency translation differences"9. Cumulative exchange rate 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. In these cases, cumulative exchange rate differences are recognized in the profit and loss account’s item

(7) |  | Fair value measurement principles are described below in the accounting policy for "Fair value measurements".
(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 profit and loss account.
(9) |  | When the foreign subsidiary is partially owned, the cumulative exchange rate differences, that are attributable to non-controlling interests, are allocated to and recognized as part of "Non-controlling interest".

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"Other gain (loss) from investments". 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 rate 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 rate differences is reclassified to the profit and loss account.

Financial statements of foreign subsidiaries which are translated into euro are denominated in the functional currencies of the countries where the entities operate. The U.S. dollar is the prevalent functional currency for the entities that do not use the euro.

The main foreign exchange rates used to translate the financial statements adopting a different functional currency are indicated below:

(currency amount for euro 1) | Annual average exchange rate 2012 |  | Exchange rate at Dec. 31, 2012 |  | Annual average exchange rate 2013 |  | Exchange rate at Dec. 31, 2013 |  | Annual average exchange rate 2014 |  | Exchange rate at Dec. 31, 2014

U.S. dollar |  | 1.28 |  | 1.32 |  | 1.33 |  | 1.38 |  | 1.33 |  | 1.21
Pound sterling |  | 0.81 |  | 0.82 |  | 0.85 |  | 0.83 |  | 0.81 |  | 0.78
Norwegian krone |  | 7.48 |  | 7.35 |  | 7.81 |  | 8.36 |  | 8.35 |  | 9.04
Australian dollar |  | 1.24 |  | 1.27 |  | 1.38 |  | 1.54 |  | 1.47 |  | 1.48
Hungarian forint |  | 289.25 |  | 292.30 |  | 296.87 |  | 297.04 |  | 308.71 |  | 315.54

3 Summary of significant accounting policies

The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Exploration and production activities10

Acquisition of mineral rights
Costs associated with the acquisition of mineral rights are capitalized in connection with the assets acquired (such as exploratory potential, probable and possible reserves and proved reserves). When the acquisition is related to a set of exploratory potential and reserves, the cost is allocated to the different assets acquired on the basis of the value of the expected discounted cash flows. Expenditure for the exploratory potential, represented by the costs for the acquisition of the exploration rights or for the extension of existing exploration rights, is recognized under "Intangible assets" and is amortized on a straight-line basis over the period of the exploration as contractually established. If the exploration is abandoned, the residual expenditure is charged to the profit and loss account. Acquisition costs for proved reserves and for possible and probable reserves are recognized in the balance sheet as assets. Costs associated with proved reserves are amortized on a unit-of-production (UOP) basis, as detailed in the accounting policy for "Development expenditure", considering both developed and undeveloped reserves. Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortized until classified as proved reserves; in case of a negative result, the costs are charged to the profit and loss account.

Exploration expenditures
Costs associated with exploration activities incurred both before and after the acquisition of mineral rights (such as acquisition of seismic data from third parties, test wells and geophysical surveys) are initially capitalized in order to reflect their nature as an investment and subsequently fully amortized when incurred.

Development expenditures
Development expenditures are costs incurred to obtain access to proved reserves and to provide facilities to extract, gather and store the oil and gas. They are then capitalized within property, plant and equipment and amortized generally on a UOP basis, as their useful life is closely related to the availability of economically

(10) |  | IFRSs do not have specific criteria for hydrocarbon exploration and production activities. Eni continues to use existing accounting policies for exploration and evaluation of assets previously applied before the introduction of IFRS 6 "Exploration for and evaluation of mineral resources".

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producible reserves. This method provides for residual costs at the end of each quarter to be amortized at a rate representing the ratio between the volumes extracted during the quarter and the proved developed 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 development expenditures and proved developed reserves. Costs related to unsuccessful development wells or damaged wells are expensed immediately as losses on disposal. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for "Property, plant and equipment".

Production costs
Production costs are those costs incurred to operate and maintain wells and field equipment and are expensed 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 clauses related to the repayment of costs incurred for the exploration, development and production activities executed through the use of Company’s technologies and financing (Cost Oil) and the Company’s share of production volumes not destined to 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 policies mentioned above. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense.

Decommissioning and restoration liabilities
Costs expected to be incurred with respect to the plugging and abandonment of a well, including costs associated with 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 amortized on a UOP basis.

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 capable of operating. In addition, 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 carrying value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be incurred at the moment the asset is retired. Changes in estimate of the carrying amounts of provisions due to the passage of time and changes in discount rates are recognized as described in the accounting policy for "Provisions"11. Property, plant and equipment are not revalued for financial reporting purposes.

Assets carried under financial leasing or concerning 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 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 payable to the lessor is recognized as a financial liability. These assets are depreciated using the criteria described below. When the renewal is not reasonably certain, leased assets are depreciated over the shorter of the lease term or the estimated useful life of the asset. Expenditures on upgrading, revamping and reconversion which provide additional economic benefits 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. Property, plant and equipment are depreciated systematically, from the moment they begin or should begin to be used, using a straight-line method over their useful life. The useful life is the estimated period over which the assets will be used by the Company. When tangible assets are composed of

(11) |  | Obligations to dismantle, remove and restore relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with refining, marketing and transportation (downstream) and chemical tangible assets are not generally recognized, as undetermined settlement dates for assets dismantlement and restoration do not allow a reasonable estimate of the obligation. The Company performs periodic reviews of its downstream and chemical tangible assets for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.

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more than one significant element with different useful lives, each component is depreciated separately. The amount to be depreciated is the book value less the residual value at the end of the 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 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 components in complex assets are capitalized and depreciated over their useful life; the residual book value of the component that has been substituted is charged to the profit and loss account. Expenditures for ordinary maintenance and repairs are expensed as incurred. The carrying value of property, plant and equipment is reviewed for impairment whenever events indicate that the carrying amounts of those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying value with the recoverable amount, which is the higher of fair value less costs to sell or its value in use. Value in use is the present value of the future cash flows expected to be derived from the use of the asset and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life, net of disposal costs. 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 of their derivatives), the price scenario is approved by the Board of Directors and, under normal market conditions, is based on the forward prices prevailing in the marketplace for the next four years, if there is a sufficient liquidity and reliability level, and on management’s long-term planning assumptions thereafter. If high price discontinuities occur, as in the last months of 2014, to adjust the short-term volatility, market references are measured based on the entire plan period, considering the most updated variables available; in particular, for 2014, management adopted a price scenario which includes the most recent trends of forward curves observed in January 2015, the consensus of a significant sample of independent analysts and internal estimates about the evolution of the supply and demand fundamentals. Discounting is carried out at a rate that reflects a current market valuation of the time value of money and of those specific risks of the asset that are not reflected in the estimate of the 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 activity. The measurement of the specific country risk to be included in the discount rate is provided by external parties. WACC differs considering the risk associated with each operating segments; in particular for the assets belonging to the Gas & Power and Engineering & Construction segments, taking into account their different risk compared with Eni as a whole, specific WACC rates have been defined (for Gas & Power segment on the basis of a sample of companies operating in the same segment; for Engineering & Construction segment on the basis of the market quotation); WACC used for impairment reviews in the Gas & Power segment is adjusted to take into consideration the risk premium of the specific country of the activity while WACC used for impairment reviews in the Engineering & Construction segment is not adjusted for country risk as most of the assets are not located in a specific country. 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, a reversal of the impairment loss is recognized in the profit and loss account. The reversal cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

Intangible assets
Intangible assets are identifiable 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 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 stated 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 systematically over their useful life estimated as the period over which the assets will be used 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 other intangible assets with indefinite useful lives are not amortized. Their carrying values are reviewed for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may

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be impaired. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management 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 amount12, the excess is recognized as an impairment loss. The impairment loss is first allocated to reduce the carrying amount of goodwill; any remaining excess to be allocated to the assets of the unit is applied 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. Impairment charges against goodwill are not reversed13.

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 specific period of time; and (iii) it is probable that the amount of the capitalized costs will be recovered through the revenues generated by 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 reliably determined; (ii) there is the intention, 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 future economic benefits. Intangible assets also include public to private service concession arrangements concerning the development, financing, operation and maintenance of infrastructures under concession, in which the grantor: (i) controls or regulates what services the operator must provide with the infrastructure, and at what price; and (ii) controls – by the ownership, beneficial entitlement or otherwise – any significant residual interest in the infrastructure at the end of the concession arrangement. According to the agreements, the operator has the right to operate the infrastructure, controlled by the grantor, in order to provide the public service14.

Grants related to assets
Grants related to assets are recognized as a reduction of purchase price or production cost of the related assets when there is reasonable assurance that the conditions attaching to them, agreed upon with the grantor government, have been fulfilled.

Inventories
Inventories, including compulsory stock and excluding construction contracts in progress, are stated 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 normal 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 a price sufficient to enable recovery of the costs incurred.

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 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 segment 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.

(12) |  | For the definition of recoverable amount see the accounting policy for "Property, plant and equipment".
(13) |  | Impairment charges 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.
(14) |  | When the operator has an unconditional contractual right to receive cash or another financial asset from or at the direction of the grantor, considerations received or receivable by the operator for construction or upgrade of infrastructure are recognized as a financial asset.

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Construction contracts in progress
Construction contracts in progress are measured using the cost-to-cost method, whereby contract revenue is recognized by reference to the stage of completion of the contract matching it with the contract costs incurred in reaching that stage of completion. Advances are deducted from inventories within the limits of accrued contractual considerations; any excess of such advances over the value of the inventories is recorded as a liability. Losses related to construction contracts in progress are recognized immediately as an expense when it is probable that total contract costs will exceed total contract revenues.

Construction contracts in progress not yet invoiced, whose payment will be made in a foreign currency, are translated into euro using the rates of exchange ruling at the balance sheet date and the effect of rate changes is reflected in the profit and loss account.

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 change 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 profit and loss account under "Finance income (expense)" and in the equity reserve15 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 considering, inter alia, significant breaches of contracts, serious financial difficulties or the risk of bankruptcy and other financial reorganization of the counterparty; impairment losses of available-for-sale financial assets are included in the carrying amount. Interests and dividends on financial assets measured at fair value are accounted for on an accrual basis in "Finance income (expense)"16 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 market place 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 instruments are measured at fair values, 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 realized. Galp and Snam shares related to convertible bonds are measured at fair value through profit and loss account, under the fair value option, in order to reduce the accounting mismatch with the recognition of the option embedded in the convertible bond, measured at fair value through profit and loss account. When investments are not traded in a public market and their fair value cannot be reasonably determined, they are accounted for at cost, net of impairment losses; impairment losses shall not be reversed17.

Receivables and held-to-maturity financial assets
Receivables and held-to-maturity financial assets are recognized initially at their fair values plus transaction costs (e.g. fees of agents or consultants, 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

(15) |  | Changes in the carrying amount of available-for-sale financial assets relating to changes in a foreign exchange rates are recognized in the profit and loss account.
(16) |  | Interests accrued on financial assets held for trading impact the total fair value measurement of the instrument and are recognized, within the 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 item "Finance income (expense)", in the sub-item "Finance income".
(17) |  | Impairment charges 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.

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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. 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 by comparing the carrying value with the present value of the expected cash flows discounted at the effective interest rate as defined 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
Debt is measured at amortized cost (see above the accounting policy for "Non-current financial assets").

Derivatives
Derivatives, including embedded derivatives which 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 highly effective and regularly reviewed. When hedging instruments hedge the risk of changes of the fair value of the hedged item (fair value hedge, e.g. hedging of the variability on the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Hedged items are consistently adjusted to reflect, in the profit and loss account, the changes of fair value associated with the hedged risk; this applies even if the hedged item should be otherwise measured. When derivatives hedge the cash flow variability risk of the hedged item (cash flow hedge, e.g. hedging the variability on the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the changes in the fair value of the derivatives, considered an effective hedge, are initially recognized in the equity reserve related to other comprehensive income and then reclassified to 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 do not meet the conditions required to qualify for hedge accounting 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 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 item "Other operating (expense) income". Economic effects of transactions to buy or sell commodities entered into to meet the entity’s normal operating requirements and for which the settlement is provided with the delivery of the underlying, are recognized on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

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
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 the settlement of that obligation will result in an outflow of resources embodying economic benefits; 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 indemnity or penalty arising from failure to fulfill these obligations. If 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)". When the liability regards a tangible asset (e.g. site dismantling and restoration), the provision is stated with a corresponding entry to the asset to which it refers. Charges to the profit and loss account are made with the amortization process. 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

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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 item that had previously held the provision, 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 to the profit and loss account. A contingent liability is: (i) a possible, but not probable obligation 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) a present obligation 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. Information about Group’s contingent liabilities is provided in note 28.

Employee benefits
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. For defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due. The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. Net interest includes the return on plan assets and the 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)”. Remeasurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognized within statement of comprehensive income. Furthermore, in presence of net assets, changes in their value different from those included in net interest are recognized within statement of comprehensive income. Remeasurements of the net defined benefit liability, recognized in the statement of comprehensive income, are not reclassified to profit and loss account in a subsequent period.

Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of remeasurements are taken to profit and loss account in their entirety.

Treasury shares
Treasury shares are recognized as deductions from equity at cost. Gains or losses resulting from subsequent sales are recognized in equity.

Revenues and costs Revenues associated with sales of products and rendering services are recognized when significant risks and rewards of ownership have passed 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, 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 related to partially rendered services are recognized by reference to the stage of completion, 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 accrued during the year related to construction contracts in progress are recognized on the basis of contractual revenues with reference to the stage of completion of a contract measured on the cost-to-cost basis. For service concession arrangements (see above the accounting policy for "Intangible assets") in which customers fees do not provide a reliable distinction between the compensation for construction/update of the infrastructure and the compensation for

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operating it and in the absence of external benchmarks, revenues recognized during the construction/update phase are limited to the amount of the costs incurred. Additional revenues, derived from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them. Tangible assets, different from an infrastructure used in service concession arrangements, transferred from customers (or constructed using cash transferred from customers) and used to connect them to a network to supply goods and services, are recognized at their fair value as an offset to revenues. When more than one separately identifiable service is provided (for example, connection to a network and supply of goods) the entity shall assess for which one service it receives the transferred asset from the customer and it shall consistently recognize a revenue when the connection is delivered or over the lesser period between the length of the supply and the useful life of the transferred asset. Revenues are measured at the fair value of the consideration received or receivable net of returns, discounts, rebates, bonuses and related taxation. Award credits, related to customer loyalty programs, are recognized as a separate component of the sales transaction which grants the right to customers. Therefore, the portion of revenues related to the fair value of award credits granted is recognized as an offset to the item "Other liabilities". The liability is charged to the profit and loss account in the period in which the award credits are redeemed by customers or the related right is lost. The exchange of goods and services of similar nature and value does not give rise to revenues and costs as they do not represent sale transactions. Costs are recognized when the related goods and services are sold or consumed during the year, they are systematically allocated 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 negative difference between the amount of emissions and the free allowances. Revenues related to emission quotas are recognized when they are sold. In case of sale, if applicable, the acquired emission rights are considered as the first to be sold. Monetary receivables granted to replace the free award emission rights are recognized as a contra to the item "Other income and revenues" of the profit and loss account. Operating lease payments are recognized in the profit and loss account over the contract 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 rate differences
Revenues and costs associated with transactions in currencies other than the functional currency are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in currencies other than functional currency are converted by applying the year end exchange rate and the effect is stated in the profit and loss account. Non-monetary assets and liabilities denominated in currencies other than the functional currency valued at cost are translated at the initial exchange rate. Non-monetary items that are measured at fair value, recoverable amount or net realizable value are translated 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 tax 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 or 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 taxable income will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carryforward of unused tax credits and unused tax losses are recognized to the extent that the recoverability is probable. Income tax assets that are uncertain in the amount to be recovered are recognized according to the probability criterion.

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Relating to the 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 reversal of the temporary differences and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to offsettable taxes. The balance of the offset, if positive, is recognized in the item "Deferred tax assets"; if negative, in the 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. 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. 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 equity-accounted investments, 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 book value of the investment in accordance with the equity method represents the carrying amount for the measurement as non-current assets 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 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 profit and loss account item, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements. 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 retain after the sale.

Fair value measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured.

A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximize the value of the asset.

The fair value of a liability, both financial and non-financial, or of an 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 a liability reflects the effect of a non-performance risk. Non-performance risk includes, but may not be limited to, an entity’s own credit risk.

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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 statements18

Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature19. 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 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
The adoption of the IFRSs effective from January 1, 2014 did not have a significant impact on the financial statements.

6 Use of accounting estimates
The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, 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 of 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 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, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the oilfield services construction and engineering businesses. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates follows.

Oil and gas activities
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be 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. 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

(18) |  | The financial statements are the same reported in the Annual Report on Form 20-F 2013.
(19) |  | Further information on financial instruments as classified in accordance with IFRS is provided in note 36 – Guarantees, commitments and risks - Other information about financial instruments.

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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 expenses and impairment expense. Depreciation and depletion rates on oil and 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 expense. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and 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 values of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced utilization of the plants and, for oil and 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 global or regional market supply and demand conditions. Similar remarks are valid for 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 the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the book value of an asset with its recoverable amount. The recoverable amount is the greater of fair value net of disposal cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. 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 and gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent 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 other intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets at the cash generating unit level on an annual basis and whenever there is an 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 is lower than the carrying amount, goodwill attributed 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 assets of the cash generating unit are impaired pro-rata on the basis of their carrying amount for the residual difference, up to the recoverable amount of assets with finite useful lives.

Decommissioning and restoration liabilities
Obligations to dismantle and remove items of property plant and equipment and restore land or seabed require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded presently in the Consolidated Financial Statements. 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

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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 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 recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors.

Environmental liabilities
As other oil and gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental costs are recognized when it becomes probable that a liability will be incurred and the liability can be reliably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.

Employee benefits
Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. 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 country by country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved. Differences in the amount of the net defined benefit liability (asset), deriving from the remeasurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Remeasurements are recognized within statement of comprehensive income for defined benefit plans and within profit and loss account for long-term plans.

Provisions
In addition to environmental liabilities, decommissioning and restoration liabilities and employee benefits, Eni recognizes provisions primarily related to litigations, tax issues and doubtful trade receivables. The estimate of these provisions is based on managerial judgments.

Revenue recognition
Revenue recognition in the Engineering & Construction segment is based on the stage of completion of a contract as measured on the cost-to-cost basis applied to contractual revenues. Use of the stage of completion

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method requires estimates of future gross profit on a contract by contract basis. The future gross profit represents the profit remaining after deducting costs attributable to the contract from revenues provided for in the contract. The estimate of future gross profit is based on a complex estimation process that includes identification of risks related to the geographical region where the activity is carried out, market conditions in that region and any assessment that is necessary to estimate with sufficient precision the total future costs, as well as the expected timetable to the end of the contract. Additional revenues, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them.

Revenues from the sale of electricity and gas to retail customers include allocations for the not yet billed supplies, occurred between the date of the last meters reading and the year end. These estimates are based on the difference between the volumes allocated by the grid managers and the billed volumes, as well as on other factors, considered by the management, which can impact on them.

7 Recent accounting standards
On November 21, 2013, the IASB issued the amendments to IAS 19 "Defined Benefit Plans: Employee Contributions" (hereinafter the amendments to IAS 19), which allow the recognition of contributions to defined benefit plans from employees or third parties as a reduction of service cost in the period in which the related service is received, provided that the contributions: (i) are set out in the formal conditions of the plan; (ii) are linked to service; and (iii) are independent of number of years of service (e.g. the contributions are a fixed percentage of the employee’s salary or a fixed amount throughout the service period or dependent on the employee’s age). The amendments to IAS 19 shall be applied for annual periods beginning on or after July 1, 2014 (for Eni: Annual report on Form 20-F 2015).

On May 6, 2014, the IASB issued the amendments to IFRS 11 "Accounting for Acquisitions of Interests in Joint Operations" (hereinafter the amendments to IFRS 11), which define the accounting treatment to be applied to the acquisition of both the initial interest or additional interests in a joint operation (without changing the status of joint operation) whose activity constitutes a business, as defined in IFRS 3. In these cases, the acquired interests in a joint operation shall be recognized in accordance with all the applicable principles on business combination accounting, which include but are not limited to: (i) measuring the identifiable assets and liabilities at fair value, other than items for which exceptions are given in IFRSs; (ii) recognizing acquisition-related costs as expenses in the periods in which the costs are incurred; (iii) recognizing deferred tax assets and liabilities that arise from the initial recognition of assets (except for goodwill) or liabilities in respect of deductible or taxable temporary differences; (iv) recognizing the excess of the consideration transferred over the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed, if any, as goodwill; and (v) testing for impairment a cash generating unit to which goodwill has been allocated at least annually, or whenever there is an impairment indicator. The amendments to IFRS 11 shall be applied for annual periods beginning on or after January 1, 2016.

On May 12, 2014, the IASB issued the amendments to IAS 16 and IAS 38 "Clarification of Acceptable Methods of Depreciation and Amortization" (hereinafter the amendments to IAS 16 and IAS 38), which consider inappropriate a depreciation or amortization method that is based on revenue that is generated by an activity that includes the use of an asset. For intangible assets, this indication represents a rebuttable presumption which can be overcome only in the following limited circumstances: (i) the right over the use of an intangible asset is set out as a fixed total amount of revenue to be generated; or (ii) when it can be demonstrated that revenue and the consumption of the economic benefits of the intangible assets are highly correlated. The amendments to IAS 16 and IAS 38 shall be applied for annual periods beginning on or after January 1, 2016.

On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers" (hereinafter IFRS 15), which establishes a comprehensive framework for determining when to recognize revenue and how much revenue to recognize; it applies to all the contracts with the 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 stand-alone 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 revenue and cash flows arising from contracts with customers. IFRS 15 shall be applied for annual periods beginning on or after January 1, 2017.

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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; (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.

On August 12, 2014, the IASB issued the amendment to IAS 27 "Equity Method in Separate Financial Statements", which introduces the possibility to account for investments in subsidiaries, joint ventures and associates using the equity method in the separate financial statements. The amendment to IAS 27 shall be applied for annual periods beginning on or after January 1, 2016.

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. The amendments to IFRS 10 and IAS 28 shall be applied for annual periods beginning on or after January 1, 2016.

On December 18, 2014, the IASB issued the amendments to IAS 1 "Disclosure Initiative", which include essentially explanations about the presentation of the financial statements, highlighting the use of the concept of materiality. The amendments to IAS 1 shall be applied for annual periods beginning on or after January 1, 2016.

On December 12, 2013, the IASB issued the documents "Annual Improvements to IFRSs 2010-2012 Cycle" and "Annual Improvements to IFRSs 2011-2013 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 July 1, 2014 (for Eni: Annual report on Form 20-F 2015).

On September 25, 2014, the IASB issued the document "Annual Improvements to IFRSs 2012-2014 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, 2016.

Eni is currently reviewing these new IFRS to determine the likely impact on the Group’s results.
Current assets
8 Cash and cash equivalents
Cash and cash equivalents of euro 6,614 million (euro 5,431 million at December 31, 2013) included financial assets that have a maturity of three months or less at the date of acquisition amounting to euro 3,373 million (euro 3,086 million at December 31, 2013) and mainly included short-term deposits having notice of more than 48 hours.

Restricted cash amounted to euro 90 million and related to key money in connection with a judicial investigation in the Engineering & Construction. More information about the judicial investigation is disclosed in note 36 – Guarantees, commitments and risks - Corruption investigations.

The average maturity of short-term deposit was 9 days and the average interest rate amounted to 0.15% (0.30% at December 31, 2013).

9 Financial assets held for trading

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Quoted bonds issued by sovereign states |  | 1,961 |  | 1,325
Other |  | 3,043 |  | 3,699
|  | 5,004 |  | 5,024

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The breakdown by issuing entity of financial assets held for trading is presented below:

|  | Nominal value (euro million) |  | Fair value (euro million) |  | Rating - Moody’s |  | Rating - S&P

Quoted bonds issued by sovereign states |  |  |  |  |  |  |  |
Fixed rate bonds |  |  |  |  |  |  |  |
Italy |  | 691 |  | 700 |  | Baa2 |  | BBB-
Spain |  | 190 |  | 202 |  | Baa2 |  | BBB
France |  | 70 |  | 73 |  | Aa1 |  | AA
European Union |  | 48 |  | 51 |  | Aaa |  | AA+
Canada |  | 31 |  | 32 |  | Aaa |  | AAA
Germany |  | 9 |  | 9 |  | Aaa |  | AAA
|  | 1,039 |  | 1,067 |  |  |  |
Floating rate bonds |  |  |  |  |  |  |  |
Germany |  | 181 |  | 181 |  | Aaa |  | AAA
France |  | 77 |  | 77 |  | Aa1 |  | AA
|  | 258 |  | 258 |  |  |  |
Total quoted bonds issued by sovereign states |  | 1,297 |  | 1,325 |  |  |  |
Other bonds |  |  |  |  |  |  |  |
Fixed rate bonds |  |  |  |  |  |  |  |
Quoted bonds issued by industrial companies |  | 1,949 |  | 2,056 |  | from Aaa to Baa3 |  | from AAA to BBB-
Quoted bonds issued by financial and insurance companies |  | 1,033 |  | 1,082 |  | from Aaa to Baa3 |  | from AAA to BBB-
|  | 2,982 |  | 3,138 |  |  |  |
Floating rate bonds |  |  |  |  |  |  |  |
Quoted bonds issued by industrial companies |  | 86 |  | 87 |  | from Aaa to Baa3 |  | from AAA to BBB-
Quoted bonds issued by financial and insurance companies |  | 474 |  | 474 |  | from Aaa to Baa3 |  | from AAA to BBB-
|  | 560 |  | 561 |  |  |  |
Total other bonds |  | 3,542 |  | 3,699 |  |  |  |
Total other financial assets held for trading |  | 4,839 |  | 5,024 |  |  |  |

The breakdown by currency is provided below:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Euro |  | 4,954 |  | 4,996
British pound |  | 37 |  | 16
Swiss franc |  | 13 |  | 12
|  | 5,004 |  | 5,024

The fair value was estimated on the basis of market quotations.

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10 Financial assets available for sale

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Securities held for operating purposes |  |  |  |
Quoted bonds issued by sovereign states |  | 165 |  | 204
Quoted securities issued by financial institutions |  | 37 |  | 40
|  | 202 |  | 244
Securities held for non-operating purposes |  |  |  |
Quoted bonds issued by sovereign states |  |  |  | 6
Quoted securities issued by financial institutions |  | 7 |  | 7
Quoted securities |  | 26 |  |
|  | 33 |  | 13
|  | 235 |  | 257

The breakdown by currency is provided below:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Euro |  | 173 |  | 216
U.S. dollar |  | 58 |  | 39
Indian rupee |  | 4 |  | 2
|  | 235 |  | 257

At December 31, 2014, bonds issued by sovereign states amounted to euro 210 million (euro 165 million at December 31, 2013). A breakdown by Country is presented below:

|  | Nominal value (euro million) |  | Fair value (euro million) |  | Nominal rate of return (%) |  | Maturity date |  | Rating - Moody’s |  | Rating - S&P

Fixed rate bonds |  |  |  |  |  |  |  |  |  |  |  |
Belgium |  | 27 |  | 33 |  | from 3.75 to 4.25 |  | from 2019 to 2021 |  | Aa3 |  | AA
Italy |  | 29 |  | 30 |  | from 1.50 to 5.75 |  | from 2015 to 2018 |  | Baa2 |  | BBB-
Portugal |  | 22 |  | 25 |  | from 3.35 to 4.75 |  | from 2015 to 2019 |  | Ba1 |  | BB
Spain |  | 21 |  | 24 |  | from 3.15 to 4.85 |  | from 2016 to 2020 |  | Baa2 |  | BBB
France |  | 16 |  | 17 |  | from 1.00 to 3.25 |  | from 2018 to 2021 |  | Aa1 |  | AA
Slovakia |  | 15 |  | 16 |  | from 1.50 to 4.20 |  | from 2016 to 2018 |  | A2 |  | A
Ireland |  | 13 |  | 16 |  | from 4.40 to 4.50 |  | from 2019 to 2020 |  | Baa1 |  | A
Finland |  | 9 |  | 9 |  | from 1.13 to 1.75 |  | from 2015 to 2019 |  | Aaa |  | AA+
Czech Republic |  | 7 |  | 8 |  | 3.63 |  | 2021 |  | A1 |  | AA-
Netherlands |  | 6 |  | 7 |  | 4.00 |  | from 2016 to 2018 |  | Aaa |  | AA+
Poland |  | 5 |  | 6 |  | 6.38 |  | 2019 |  | A2 |  | A-
Austria |  | 5 |  | 5 |  | 3.50 |  | 2015 |  | Aaa |  | AA+
Germany |  | 5 |  | 5 |  | 3.25 |  | 2015 |  | Aaa |  | AAA
Canada |  | 5 |  | 5 |  | 1.63 |  | 2019 |  | Aaa |  | AAA
United States |  | 4 |  | 4 |  | 3.13 |  | 2019 |  | Aaa |  | AA+
|  | 189 |  | 210 |  |  |  |  |  |  |  |

Quoted securities amounting to euro 47 million (euro 44 million at December 31, 2013) were issued by financial institutions with a rating ranging from Aaa to A2 (Moody’s) and from AAA to A+ (S&P).

Securities held for operating purposes of euro 244 million (euro 202 million at December 31, 2013) were designated to hedge the loss provisions of the Group’s insurance company Eni Insurance.

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##### Table of Contents

The effects of fair value measurement of securities are set out below:

(euro million) |  | Carrying amount at Dec. 31, 2013 |  | Changes recognized in equity |  | Carrying amount at Dec. 31, 2014

Fair value |  | 6 |  |  | 7 |  |  | 13 |
Deferred tax liabilities |  | (1 | ) |  | (1 | ) |  | (2 | )
Other reserves of shareholders' equity |  | 5 |  |  | 6 |  |  | 11 |

The fair value was estimated on the basis of market quotations.

11 Trade and other receivables

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Trade receivables |  | 21,212 |  | 19,709
Financing receivables: |  |  |  |
- for operating purposes - short-term |  | 403 |  | 423
- for operating purposes - current portion of long-term receivables |  | 481 |  | 839
- for non-operating purposes |  | 129 |  | 555
|  | 1,013 |  | 1,817
Other receivables: |  |  |  |
- from disposals |  | 88 |  | 86
- other |  | 6,577 |  | 6,989
|  | 6,665 |  | 7,075
|  | 28,890 |  | 28,601

The decrease in trade and other receivables of euro 1,503 million primarily related to the Gas & Power segment (euro 726 million) and to the Exploration & Production segment (euro 594 million).

Receivables are stated net of the valuation allowance for doubtful accounts of euro 2,353 million (euro 1,877 million at December 31, 2013):

(euro million) |  | Carrying amount at Dec. 31, 2013 |  | Additions |  | Deductions |  | Other changes |  | Carrying amount at Dec. 31, 2014

Trade receivables |  | 1,291 |  | 518 |  | (154) |  | 19 |  | 1,674
Financing receivables |  | 52 |  |  |  |  |  | 7 |  | 59
Other receivables |  | 534 |  | 48 |  | (9) |  | 47 |  | 620
|  | 1,877 |  | 566 |  | (163) |  | 73 |  | 2,353

Additions to the allowance reserve for doubtful accounts amounted to euro 518 million (euro 384 million in 2013) and primarily related to the Gas & Power segment (euro 380 million), particularly in respect of continuing difficulties in the collection of receivables due by Italian retail customers who were hit by the economic and financial downturn. Eni is implementing all the necessary steps to reduce the receivables past due through a revision of their management process and through factoring arrangements.

Deductions amounted to euro 154 million (euro 158 million in 2013) and related to the Gas & Power segment for euro 55 million and to the Engineering & Construction for euro 53 million.

At the balance sheet date, Eni had in place transactions to transfer to factoring institutions certain trade receivables without recourse for euro 1,375 million, due in 2015 (euro 2,533 million at December 31, 2013, due in 2014). Transferred receivables related to the Gas & Power segment (euro 1,099 million), the Refining & Marketing segment (euro 147 million), the Engineering & Construction segment (euro 92 million) and Versalis (euro 37 million). Furthermore, the Engineering & Construction segment transferred certain trade receivables without recourse due in 2015 for euro 419 million through Eni’s subsidiary Serfactoring SpA (euro 222 million at December 31, 2013, due in 2014).

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Trade receivables amounting to euro 763 million were overdue in the Exploration & Production segment at the balance sheet date and related to hydrocarbons supplies to Egyptian State-owned companies. This amount was fairly reduced from after peaking at (euro 1,195 million) at June 30, 2014, thanks to a stream of reimbursements received during 2014 pursuant to the finalization of certain commercial agreements with the counterparties. In 2015, negotiations will continue with those state-owned companies and other local governmental authorities for the reduction of overdue amounts leveraging on the established relationships with Egyptian counterparties.

The ageing of trade and other receivables is presented below:

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Trade receivables |  | Other receivables |  | Total |  | Trade receivables |  | Other receivables |  | Total

Neither impaired nor past due |  | 16,625 |  | 5,432 |  | 22,057 |  | 15,575 |  | 5,713 |  | 21,288
Impaired (net of the valuation for doubtful accounts) |  | 1,056 |  | 172 |  | 1,228 |  | 1,804 |  | 196 |  | 2,000
Not impaired and past due in the following periods: |  |  |  |  |  |  |  |  |  |  |  |
- within 90 days |  | 1,702 |  | 325 |  | 2,027 |  | 1,088 |  | 232 |  | 1,320
- 3 to 6 months |  | 709 |  | 50 |  | 759 |  | 550 |  | 105 |  | 655
- 6 to 12 months |  | 606 |  | 185 |  | 791 |  | 244 |  | 10 |  | 254
- over 12 months |  | 514 |  | 501 |  | 1,015 |  | 448 |  | 819 |  | 1,267
|  | 3,531 |  | 1,061 |  | 4,592 |  | 2,330 |  | 1,166 |  | 3,496
|  | 21,212 |  | 6,665 |  | 27,877 |  | 19,709 |  | 7,075 |  | 26,784

Trade and other receivables overdue but not impaired primarily pertained to high-credit-rating 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. In the course of 2014, factoring transactions were executed in connection with overdue receivables of certain public administrations. In particular, in December 2014 overdue receivables for about euro 104 million were factored relating to middle and large clients in the Gas & Power segment.

The increase of euro 772 million of receivables impaired net of the valuation for doubtful accounts related to the Gas & Power segment for euro 494 million and the Refining & Marketing segment for euro 255 million. The decrease in receivables not impaired and past due of euro 1,096 million related to the Gas & Power segment for euro 1,026 million.

Trade receivables included amounts withheld to guarantee certain contract work in progress for euro 153 million (euro 209 million at December 31, 2013).

Trade receivables in currencies other than euro amounted to euro 8,066 million (euro 7,611 million at December 31, 2013).

Financing receivables associated with operating purposes of euro 1,262 million (euro 884 million at December 31, 2013) included loans granted to unconsolidated subsidiaries, joint ventures and associates to fund the execution of capital projects for euro 811 million (euro 481 million at December 31, 2013) and cash deposits to hedge the loss provision made by Eni Insurance Ltd for euro 332 million (euro 321 million at December 31, 2013).

Financing receivables not associated with operating activities amounted to euro 555 million (euro 129 million at December 31, 2013) and related to: (i) restricted deposits in escrow for euro 287 million of Eni Trading & Shipping SpA (euro 92 million at December 31, 2013) of which euro 183 million with Citigroup Global Markets Ltd, euro 96 million with BNP Paribas and euro 8 million with ABN AMRO relating to derivatives; (ii) to receivables relating margins on derivatives of Eni Trading & Shipping SpA for euro 203 million (financing debts of euro 15 million at December 31, 2013); and (iii) restricted deposits in escrow of receivables of the Engineering & Construction segment for euro 25 million (same amount as of December 31, 2013).

Financing receivables in currencies other than euro amounted to euro 1,063 million (euro 529 million as of December 31, 2013).

Receivables related to divesting activities of euro 86 million (euro 88 million at December 31, 2013) related for euro 52 million (euro 79 million at December 31, 2013) to the divestment finalized in June 2012 of a 3.25% interest in the Karachaganak project (equal to Eni’s 10% interest) to the Kazakh partner KazMunaiGas as part of an agreement between the Contracting Companies of the Final Production Sharing Agreement (FPSA) and Kazakh

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Authorities which settled disputes on the recovery of the costs incurred by the International Consortium to develop the field, as well as a certain tax claims. Eni agreed to collect the cash consideration in monthly installments starting from July 2012. The receivable accrues interest income at market rates.

Other receivables of euro 6,989 million (euro 6,577 million at December 31, 2013) included: (i) euro 663 million of receivables related to the recovery of costs incurred for two oil projects in the Exploration & Production segment. In the recent years Eni commenced two arbitration proceedings that led to the issuance of a partial award and a favorable final award in the first one and the issuance of a partial award in the second one. For the second proceeding, the final award could be issued by the Arbitration Committee on the condition that the restrictive measure issued by a local court that prevents the continuation of this arbitration will be revoked; (ii) euro 91 million to be paid by gas customers for amounts of gas to be delivered following the triggering of the take-or-pay clause provided for by the relevant long-term contracts; and (iii) euro 1 million relating to receivables for the settlement of tax positions with unconsolidated subsidiaries which are part of the consolidated accounts for Italian tax purposes (euro 8 million at December 31, 2013).

Other receivables were as follows:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Receivables originated from divestments |  | 88 |  | 86
Accounts receivable from: |  |  |  |
- joint venture partners in exploration and production |  | 4,771 |  | 4,837
- prepayments for services |  | 613 |  | 857
- insurance companies |  | 171 |  | 164
- from factoring arrangements |  | 121 |  | 140
- non-Italian oil entities for oil tax refunds |  | 69 |  | 47
- non-financial government entities |  | 17 |  | 18
- other receivables |  | 815 |  | 926
|  | 6,577 |  | 6,989
|  | 6,665 |  | 7,075

Receivables from joint venture partners in exploration and production activities of euro 207 million (euro 264 million at December 31, 2013) included the liability for defined-benefit plans (see note 30 – Provisions for employee benefits).

Receivables from factoring arrangements of euro 140 million (euro 121 million at December 31, 2013) 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 euro 6,004 million (euro 5,674 million at December 31, 2013).

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

Receivables with related parties are described in note 44 – Transactions with related parties.

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12 Inventories

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Crude oil, gas and petroleum products |  | Chemical products |  | Work in progress |  | Other |  | Total |  | Crude oil, gas and petroleum products |  | Chemical products |  | Work in progress |  | Other |  | Total

Raw and auxiliary materials and consumables |  | 714 |  | 209 |  |  |  | 1,848 |  | 2,771 |  | 468 |  | 210 |  |  |  | 2,177 |  | 2,855
Products being processed and semi-finished products |  | 114 |  | 14 |  |  |  | 1 |  | 129 |  | 34 |  | 11 |  |  |  | 1 |  | 46
Work in progress |  |  |  |  |  | 1,627 |  |  |  | 1,627 |  |  |  |  |  | 1,768 |  |  |  | 1,768
Finished products and goods |  | 2,496 |  | 801 |  |  |  | 93 |  | 3,390 |  | 2,022 |  | 699 |  |  |  | 131 |  | 2,852
Certificates and emission rights |  |  |  |  |  |  |  | 22 |  | 22 |  |  |  |  |  |  |  | 34 |  | 34
|  | 3,324 |  | 1,024 |  | 1,627 |  | 1,964 |  | 7,939 |  | 2,524 |  | 920 |  | 1,768 |  | 2,343 |  | 7,555

Contract work in progress for euro 1,768 million (euro 1,627 million at December 31, 2013) related to the Engineering & Construction segment for euro 1,757 million (euro 1,607 million at December 31, 2013) and included additional payments under negotiation (change orders and claims) for euro 801 million (euro 1,018 million at December 31, 2013). More information is provided in note 37 – Revenues. As of December 31, 2014 there were no prepayments from customers offsetting the related contracts work in progress (euro 6 million at December 31, 2013 corresponding to the amount of the works executed and accepted by customers). Certificates and emission rights of euro 34 million (euro 22 million at December 31, 2013) are evaluated at fair value on the basis of market prices.

Inventories of euro 213 million (euro 105 million at December 31, 2013) were pledged as a guarantee for the payment of storage services.

Changes in inventories and in the loss provision were as follows:

(euro million) |  | Carrying amount at the beginning of the year |  | Changes |  | New or increased provisions |  | Deductions |  | Changes in the scope of consolidation |  | Currency translation differences |  | Other changes |  | Carrying amount at the end of the year

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gross carrying amount |  | 8,749 |  |  | (373 | ) |  |  |  |  |  |  | (3 | ) |  | (181 | ) |  | (66 | ) |  | 8,126 |
Loss provision |  | (171 | ) |  |  |  |  | (168 | ) |  | 149 |  |  |  |  | 3 |  |  |  |  |  | (187 | )
Net carrying amount |  | 8,578 |  |  | (373 | ) |  | (168 | ) |  | 149 |  | (3 | ) |  | (178 | ) |  | (66 | ) |  | 7,939 |
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gross carrying amount |  | 8,126 |  |  | (185 | ) |  |  |  |  |  |  | 26 |  |  | 271 |  |  | (211 | ) |  | 8,027 |
Loss provision |  | (187 | ) |  |  |  |  | (371 | ) |  | 57 |  |  |  |  | (8 | ) |  | 37 |  |  | (472 | )
Net carrying amount |  | 7,939 |  |  | (185 | ) |  | (371 | ) |  | 57 |  | 26 |  |  | 263 |  |  | (174 | ) |  | 7,555 |

Negative changes of the year amounting to euro 185 million related to the Refining & Marketing segment for euro 414 million, partially offset by the increase of the Exploration & Production segment for euro 203 million and the Engineering & Construction segment for euro 97 million. Additions of euro 371 million and deductions of euro 57 million of the loss provision related to the Refining & Marketing segment for euro 298 million and euro 17 million, respectively, and related, in particular, to the alignment of the book value of inventories of crude oil and refined products to their net realizable values at year end or to the reduction of refinery throughputs as a result of plant closures.

Other changes of euro 174 million included a reclassification of euro 104 million to assets held for sale.

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13 Current tax assets

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Italian subsidiaries |  | 555 |  | 472
Subsidiaries outside Italy |  | 247 |  | 290
|  | 802 |  | 762

Income taxes are described in note 41 – Income tax expense.

14 Other current tax assets

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

VAT |  | 596 |  | 817
Excise and customs duties |  | 88 |  | 200
Other taxes and duties |  | 151 |  | 192
|  | 835 |  | 1,209

15 Other current assets

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Fair value of cash flow hedge derivatives |  | 14 |  | 41
Fair value of other derivatives |  | 718 |  | 3,258
Other current assets |  | 593 |  | 1,086
|  | 1,325 |  | 4,385

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or alternatively, appropriate valuation methods commonly used in the marketplace.

Fair value of cash flow hedge derivatives of euro 41 million (euro 14 million at December 31, 2013) 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. Negative fair value of contracts expiring by 2015 is disclosed in note 27 – Other current liabilities; positive and negative fair value of contracts expiring beyond 2015 is disclosed in note 22 – Other non-current receivables and in note 32 – Other non-current liabilities. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 34 – Shareholders’ equity and in note 38 – Operating expenses. Purchase and sale commitments of cash flow hedge derivatives amounted to euro 1 million and to euro 543 million, respectively (sale commitments of euro 505 million at December 31, 2013). Information on hedged risks and hedging policies is disclosed in note 36 – Guarantees, commitments and risks - Risk factors.

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##### Table of Contents

The fair value of other derivative contracts is presented below:

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Fair value |  | Purchase commitments |  | Sale commitments |  | Fair value |  | Purchase commitments |  | Sale commitments

Derivatives on exchange rate |  |  |  |  |  |  |  |  |  |  |  |
Interest currency swap |  | 6 |  | 35 |  |  |  |  |  |  |  |
Currency swap |  | 250 |  | 2,320 |  | 6,426 |  | 339 |  | 6,530 |  | 973
Other |  | 1 |  | 68 |  | 73 |  | 83 |  | 966 |  | 45
|  | 257 |  | 2,423 |  | 6,499 |  | 422 |  | 7,496 |  | 1,018
Derivatives on interest rate |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  | 2 |  | 36 |  |  |  | 5 |  | 144 |  |
|  | 2 |  | 36 |  |  |  | 5 |  | 144 |  |
Derivatives on commodities |  |  |  |  |  |  |  |  |  |  |  |
Over the counter |  | 395 |  | 6,558 |  | 9,231 |  | 2,671 |  | 321 |  | 14,058
Options |  |  |  |  |  |  |  | 122 |  | 1,031 |  |
Future |  | 64 |  | 7,666 |  | 6,340 |  | 4 |  | 41 |  |
Other |  |  |  |  |  |  |  | 34 |  |  |  |
|  | 459 |  | 14,224 |  | 15,571 |  | 2,831 |  | 1,393 |  | 14,058
|  | 718 |  | 16,683 |  | 22,070 |  | 3,258 |  | 9,033 |  | 15,076

Fair value of other derivatives of euro 3,258 million (euro 718 million at December 31, 2013) consisted of: (i) euro 978 million (euro 369 million at December 31, 2013) of derivatives that lacked the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to movements in foreign currencies, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; (ii) euro 2,246 million (euro 344 million at December 31, 2013) of commodity derivatives entered by the Gas & Power segment for trading purposes and proprietary trading; (iii) euro 34 million of derivatives embedded in the pricing formulas of certain long-term supply contracts of gas in the Exploration & Production segment; and (iv) euro 5 million as of December 31, 2013 of derivatives related to net settlement agreements, of which euro 7 million of negative fair value hedge derivatives.

Other assets amounted to euro 1,086 million (euro 593 million at December 31, 2013) and included: (i) gas volumes prepayments of euro 496 million 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 twelve months based on its sales plans and the benefits of the latest renegotiations which have been achieved at the closing date. The portion that Eni expects to recover beyond 12 months is provided in note 22 – Other non-current assets; (ii) prepayments and accrued income for euro 124 million (euro 107 million at December 31, 2013); (ii) pre-paid rentals for euro 51 million (euro 63 million at December 31, 2013); and (iii) pre-paid insurance premiums for euro 36 million (euro 53 million at December 31, 2013).

Transactions with related parties are described in note 44 – Transactions with related parties.

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##### Table of Contents

Non-current assets
16 Property, plant and equipment

(euro million) |  | Net book amount at the beginning of the year |  | Additions |  | Depreciation |  | Impairment losses |  | Changes in the scope of consolidation |  | Currency translation differences |  | Reclassification to assets held for sale |  | Other changes |  | Net book amount at the end of the year |  | Gross book amount at the end of the year |  | Provisions for depreciation and impairments

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Land |  | 677 |  | 10 |  |  |  |  | (8 | ) |  |  |  |  | (19 | ) |  | (3 | ) |  | 10 |  |  | 667 |  | 693 |  | 26
Buildings |  | 1,170 |  | 72 |  | (116 | ) |  | (37 | ) |  | 18 |  |  | (29 | ) |  | (7 | ) |  | 197 |  |  | 1,268 |  | 3,404 |  | 2,136
Plant and machinery |  | 40,047 |  | 3,825 |  | (7,071 | ) |  | (1,847 | ) |  |  |  |  | (1,570 | ) |  | (145 | ) |  | 8,334 |  |  | 41,573 |  | 121,429 |  | 79,856
Industrial and commercial equipment |  | 425 |  | 142 |  | (125 | ) |  | (4 | ) |  |  |  |  | (19 | ) |  |  |  |  | 31 |  |  | 450 |  | 1,865 |  | 1,415
Other assets |  | 731 |  | 80 |  | (142 | ) |  | (1 | ) |  | 1 |  |  | (10 | ) |  |  |  |  | (294 | ) |  | 365 |  | 1,953 |  | 1,588
Tangible assets in progress and advances |  | 21,748 |  | 6,784 |  |  |  |  | (219 | ) |  |  |  |  | (996 | ) |  |  |  |  | (7,877 | ) |  | 19,440 |  | 21,424 |  | 1,984
|  | 64,798 |  | 10,913 |  | (7,454 | ) |  | (2,116 | ) |  | 19 |  |  | (2,643 | ) |  | (155 | ) |  | 401 |  |  | 63,763 |  | 150,768 |  | 87,005
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Land |  | 667 |  | 7 |  |  |  |  | (1 | ) |  |  |  |  | 2 |  |  | (51 | ) |  | (9 | ) |  | 615 |  | 642 |  | 27
Buildings |  | 1,268 |  | 129 |  | (126 | ) |  | (20 | ) |  |  |  |  | 40 |  |  | (80 | ) |  | 422 |  |  | 1,633 |  | 4,463 |  | 2,830
Plant and machinery |  | 41,573 |  | 3,763 |  | (7,850 | ) |  | (1,141 | ) |  | 245 |  |  | 3,363 |  |  | (3 | ) |  | 6,795 |  |  | 46,745 |  | 140,353 |  | 93,608
Industrial and commercial equipment |  | 450 |  | 129 |  | (121 | ) |  | (15 | ) |  | (1 | ) |  | 21 |  |  |  |  |  | 127 |  |  | 590 |  | 2,099 |  | 1,509
Other assets |  | 365 |  | 70 |  | (90 | ) |  | (1 | ) |  |  |  |  | 17 |  |  | (3 | ) |  | 100 |  |  | 458 |  | 2,159 |  | 1,701
Tangible assets in progress and advances |  | 19,440 |  | 6,587 |  |  |  |  | (362 | ) |  |  |  |  | 1,652 |  |  | (1 | ) |  | (5,395 | ) |  | 21,921 |  | 24,311 |  | 2,390
|  | 63,763 |  | 10,685 |  | (8,187 | ) |  | (1,540 | ) |  | 244 |  |  | 5,095 |  |  | (138 | ) |  | 2,040 |  |  | 71,962 |  | 174,027 |  | 102,065

Capital expenditures by segment was the following:

(euro million) |  | 2013 |  | 2014

Capital expenditures |  |  |  |  |  |
Exploration & Production |  | 8,754 |  |  | 9,081 |
Gas & Power |  | 149 |  |  | 114 |
Refining & Marketing |  | 664 |  |  | 527 |
Versalis |  | 311 |  |  | 277 |
Engineering & Construction |  | 887 |  |  | 682 |
Corporate and financial companies |  | 130 |  |  | 56 |
Other activities |  | 21 |  |  | 30 |
Elimination of intragroup profits |  | (3 | ) |  | (82 | )
|  | 10,913 |  |  | 10,685 |

Capital expenditures included capitalized finance expenses of euro 161 million (euro 167 million in 2013) and related to the Exploration & Production segment (euro 133 million), the Refining & Marketing segment (euro 22 million) and the Versalis segment (euro 6 million). The interest rates used for capitalizing finance expense ranged from 2.7% to 5.3% (2.6% and 5.3% at December 31, 2013).

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

(%) |  |  |  |  |  |  |  |  |
Buildings |  |  |  |  | 2 |  | - | 10 |
Plant and machinery |  |  |  |  | 2 |  | - | 10 |
Industrial and commercial equipment |  |  |  |  | 4 |  | - | 33 |
Other assets |  |  |  |  | 6 |  | - | 33 |

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##### Table of Contents

A breakdown of impairments losses recorded in 2014 and the associated tax effect is provided below:

(euro million) |  | 2013 |  | 2014

Impairment losses |  |  |  |
Exploration & Production |  | 209 |  | 695
Gas & Power |  | 1,200 |  | 79
Refining & Marketing |  | 633 |  | 234
Versalis |  | 55 |  | 98
Engineering & Construction |  |  |  | 420
Other segments |  | 19 |  | 14
|  | 2,116 |  | 1,540
Tax effects |  |  |  |
Exploration & Production |  | 71 |  | 134
Gas & Power |  | 355 |  | 27
Refining & Marketing |  | 223 |  | 69
Versalis |  | 15 |  | 33
Engineering & Construction |  |  |  |
Other segments |  | 5 |  | 4
|  | 669 |  | 267
Impairments net of the relevant tax effects |  |  |  |
Exploration & Production |  | 138 |  | 561
Gas & Power |  | 845 |  | 52
Refining & Marketing |  | 410 |  | 165
Versalis |  | 40 |  | 65
Engineering & Construction |  |  |  | 420
Other segments |  | 14 |  | 10
|  | 1,447 |  | 1,273

In order to verify the recoverability of the book value of tangible and intangible assets, management assesses whether there are any indications that assets may be impaired including external impairment indicators, such as the carrying amount of the net assets of Eni is more than its market capitalization at year end, 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, and internal impairment indicators, such as underperformance of the reservoir, increase in costs/investments, obsolescence and other factors. In assessing whether impairment is required, the carrying amounts of property, plant and equipment 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. 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 using the value-in-use which is calculated by discounting the estimated cash flows arising from the continuing use of an asset. 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 its CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields whereby technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power segment, in addition to the CGUs to which the goodwill arisen from acquisitions was allocated (see note 18 – Intangible assets), electricity generation plants, international pipelines and minor CGUs have been identified as being individual cash generating units; (iii) in the Refining & Marketing segment, refining plants, retail networks and other distribution facilities itemized by country of operations and type of network (retail outlets located along ordinary routes and, high-ways, and wholesale facilities); (iv) in the Versalis segment, production plants by business/plant and related facilities; and (v) in the Engineering & Construction segment, the business units Offshore E&C, with independent assessment of two floating production units (Leased FPSO), Onshore E&C, Onshore Drilling and each of the rigs employed in the business unit Offshore Drilling.

Recoverable amounts are calculated by discounting the estimated 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 on the basis of the best information available at the time of the assessment deriving: (i) for the first four years of each projection, from the Company’s four-year plan adopted by the top management which provides information on expected oil and 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

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variables, including inflation, nominal interest rates and exchange rates; (ii) beyond the four-year plan horizon, cash flow projections are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and along a time horizon which considers the following factors: (a) for the oil&gas CGUs, the residual life of the reserves and the associated projections of operating costs and development expenditures; (b) for the CGUs of the Refining & Marketing segment, Versalis and the power plants, the economical and technical life of the plants and the associated projections of operating costs, expenditures to support plant efficiency, refining and selling margins and, in the case of chemical plants, operating results before depreciation, interest and taxes, with the adoption of a normalization factor in order to reflect the structural capacity to generate profitability of these CGUs; (c) for the CGUs of the gas market and the Engineering & Construction segment, to which amounts of goodwill have been allocated, management uses the perpetuity method of the last year-plan assuming nominal growth rates ranging from 0% to 2% (which results to a real growth rate negative or equal to zero) also applying a normalization factor of the perpetuity to reflect any cyclicality observed in the business; and d) for each single vessel of Saipem (leased FPSO units and offshore drilling rigs) on the basis of their residual economic and technical life and, in relation to the subsequent years of the plan, on the basis of the projections of utilization of the vessels and daily rates considering existing contracts, or reasonable projections of use and daily rates in line with the management’s expectations about the market trends of client companies (oil companies), normalized days of use and the relevant projections of operating and maintenance costs; and (iii) for the 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 the profitability of capital projects. In particular, in order to assess future cash flows associated with the production of crude oil and natural gas and production and marketing of refined products, the price scenario is subject to the approval of the Board of Directors and, under normal market conditions, is based on the observation of forward prices of commodities for future delivery in the next four years in case the level of liquidity and reliability of future contracts is deemed to be fair, and on assumptions about trends in market fundamentals of demand and supply of crude oil and other commodities for the long term. Considering the strong discontinuity in the markets recorded at the end of 2014, with the aim of fairly weighting short-term volatility, market price benchmarks were assessed over the entire plan horizon, considering the most recent trends observed in forward prices; particularly with reference to the year 2014, management adopted a price scenario which incorporated the latest trends in the forward curves recorded in January 2015, price forecasts made by specialized independent sources and internal forecasts on the evolution of the fundamentals for supply and demand. The scenario adopted for planning purposes and in order to assess the recoverability of the carrying amounts of the Company’s assets in the this annual report 2014 confirmed a long-term price for the Brent crude oil of 90 $/BBL (in real terms in 2018), assuming a gradual recovery in the price over the next four years from the expected value of 55 U.S. dollars in 2015 up to the long-term case (70 U.S. dollars in 2016, 80 U.S. dollars in 2017).

Values in use are estimated by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production, Refining & Marketing and Versalis to the Company’s weighted average cost of capital net of the risk factors attributable to Saipem and the Gas & Power segment which are 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). In 2014, the adjusted post-tax WACC of Eni, which is the driver for calculating each business segment WACC to assess the value-in-use of their respective CGUs, decreased by 110 basis points compared to 2013 driven by a reduced sovereign risk premium incorporated into the yields of Italian bonds with a maturity of ten years, and, to a lesser extent, to a reduction in the beta of the Eni share. The other drivers used in determining the cost of capital – cost of borrowings to Eni, the average premium for country risk, debt-to-equity ratio – were assessed to record only marginal variations. In 2014, the adjusted WACC rates used for impairment test purposes ranged from 5.8% to 10.5% for the Exploration & Production segment, the Refining & Marketing segment and Versalis; 5.7% for the Gas & Power segment; 6.9% for Saipem.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

In 2014, Eni recognized impairment losses for euro 1,540 million and write-off of equipment for euro 138 million, primarily in the Exploration & Production segment.

In Exploration & Production, oil&gas properties were impaired to the amount of euro 695 million mainly driven by the impact of lower price environment in the short to medium term. There were no single large amounts; impaired properties were located mainly in the United States, Congo, Australia, Angola and Italy.

The Engineering & Construction segment recognized impairment losses for a total amount of euro 420 million primarily related to offshore drilling rigs and construction and FPSO vessels driven by expectations of reduced utilization rates against the backdrop of low crude oil prices.

Impairment losses recognized in the Refining & Marketing of euro 234 million related to investments executed in the year for compliance and stay-in-business related to cash generating unit fully impaired in previous reporting periods which were confirmed to lack any profitability prospects, while the book values of the distribution networks

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in the Czech Republic and Slovakia were aligned to their lower expected fair values (more information is disclosed in note 33 – Assets held for sale and liabilities directly associated with assets held for sale).

In the Versalis segment impairment losses amounted to euro 98 million and related to the write-off of the book values of marginal production lines which were shut down and to the write-off of expenditures incurred for safety and plant reliability at assets which were fully impaired in previous reporting periods.

Considering the volatility in the oil scenario and the uncertainty about a recovery in crude oil prices, management assessed the fairness of its assumptions and the outcome of the impairment review through different sensitivity analyses. This additional assessment was considered appropriate because at the reporting date the book value of the net assets of Eni, amounting to approximately euro 60 billion, exceeded by approximately 15% Eni’s market capitalization at the same date. In order to determine the value-in-use of Eni, management selected those CGUs which carrying amounts were not reflective of the underlying fair values; those CGUs related to oil&gas properties; the other CGUs in the Gas & Power, Refining & Marketing and Chemical segments were assessed to have fair values in line with the carrying amounts considering the regular adoption of the impairment test by Eni. The fair values of the oil&gas CGUs which were determined utilizing the impairment test methodology under Eni’s price assumptions at the reporting date, showed a significant headroom over the corresponding book values. It is worth noting that such headroom does not correspond to the one that could be obtained in a hypothetical sale process of the oil&gas CGUs which would comprise the valuation of additional types of resources (contingent, exploration, etc.) that are normally excluded when assessing the recoverability of the carrying amounts of oil&gas properties. In addition, the alignment to the market price of Eni’s interest in Saipem at the end of 2014 did not produce significant effects compared to the underlying book value recognized in the consolidated accounts of Eni. On the basis of this review which showed that the recoverable amount of the Group exceeds the book value of the net assets, management concluded that the undervaluation of Eni at the market price current at the reporting date was attributable to the strong pressure suffered by the oil sector in the financial markets at the end of 2014, coinciding with a bottom in the current oil price downturn and considering a context of sharp volatility. These trends have been progressively absorbed in the first months of 2015. For those reasons, management also performed a sensitivity analysis of the global headroom of Eni’s oil&gas properties by selecting a sample that provided a significant coverage of the global headroom and by considering a 10% reduction in the Brent price over all the plan period and until reservoir depletion, holding all other operating conditions unchanged. Management concluded about the resilience of the headroom of Eni. Even the country risk was subject to a sensitivity analysis for the determination of the discount rate of future cash flows of oil&gas properties by reassessing the country risk score of those countries particularly exposed to the financial risk following the collapse in the oil prices and a worsening of local geopolitical crisis. In particular, the oil&gas properties of Eni in Libya were tested with a discount rate greater than 100 bp compared to the base case (9.2%) and substantially confirmed the headroom. Finally, for some large oil and gas projects the headroom was tested by assuming hypothesis of delay in the start up or in the restart of production, such as the Kashagan project, without significant effects in the dimension of the headroom.

The change in the scope of consolidation of euro 244 million essentially related to the purchase of a 100% interest in Liverpool Bay Ltd.

Foreign currency translation differences of euro 5,095 million primarily related to translations of entities accounts denominated in U.S. dollar (euro 5,351 million) and Pound sterling (euro 137 million), partially offset by translations of entities accounts denominated in Norwegian krone (euro 477 million).

The reclassification to assets held for sale of euro 138 million mainly referred to Eni Ceská Republika Sro, Eni Slovensko Spol Sro and Eni Romania Srl (euro 129 million).

Other changes of euro 2,040 million related to: (i) the initial recognition of assets and change in estimates of costs for dismantling and site restoration of the Exploration & Production segment amounting to euro 2,112 million, primarily as a consequence of changes in the discount rates; and (ii) reversals amounting to euro 64 million.

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Unproved mineral interests included in tangible assets in progress and advances are presented below:

(euro million) |  | Book amount at the beginning of the year |  | Acquisitions |  | Impairment losses |  | Reclassification to proved mineral interest |  | Other changes and currency translation differences |  | Book amount at the end of the year

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Congo |  | 1,254 |  |  |  |  |  |  | (84 | ) |  | (51 | ) |  | 1,119
Nigeria |  | 743 |  |  |  |  |  |  |  |  |  | (32 | ) |  | 711
Turkmenistan |  | 516 |  |  |  |  |  |  | (4 | ) |  | (22 | ) |  | 490
Algeria |  | 355 |  |  |  |  |  |  | (9 | ) |  | (15 | ) |  | 331
United States |  | 146 |  |  |  |  |  |  | (3 | ) |  | (6 | ) |  | 137
Egypt |  |  |  | 45 |  |  |  |  |  |  |  | (1 | ) |  | 44
Other countries |  | 51 |  |  |  | (7 | ) |  | (6 | ) |  | (3 | ) |  | 35
|  | 3,065 |  | 45 |  | (7 | ) |  | (106 | ) |  | (130 | ) |  | 2,867
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Congo |  | 1,119 |  |  |  | (52 | ) |  |  |  |  | 147 |  |  | 1,214
Nigeria |  | 711 |  |  |  |  |  |  |  |  |  | 112 |  |  | 823
Turkmenistan |  | 490 |  |  |  |  |  |  | (30 | ) |  | 64 |  |  | 524
Algeria |  | 331 |  |  |  |  |  |  | (3 | ) |  | 45 |  |  | 373
United States |  | 137 |  |  |  |  |  |  | (30 | ) |  | 16 |  |  | 123
Egypt |  | 44 |  |  |  |  |  |  | (13 | ) |  | 4 |  |  | 35
Other countries |  | 35 |  |  |  | (21 | ) |  | (1 | ) |  | (13 | ) |  |
|  | 2,867 |  |  |  | (73 | ) |  | (77 | ) |  | 375 |  |  | 3,092

Accumulated provisions for impairments amounted to euro 11,684 million (euro 9,885 million at December 31, 2013).

At December 31, 2014, Eni pledged property, plant and equipment for euro 21 million primarily as collateral against certain borrowings (same amount as of December 31, 2013).

Government grants recorded as a decrease of property, plant and equipment amounted to euro 105 million (euro 114 million at December 31, 2013).

Assets acquired under financial lease agreements amounted to euro 58 million (euro 30 million at December 31, 2013) and related to onshore drilling rigs of the Engineering & Construction segment (euro 31 million) and service stations of the Refining & Marketing segment (euro 27 million).

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 36 – Guarantees, commitments and risks - Liquidity risk.

Property, plant and equipment under concession arrangements are described in note 36 – Guarantees, commitments and risks - Asset under concession arrangements.

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Property, plant and equipment by segment

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Property, plant and equipment, gross |  |  |  |  |  |
Exploration & Production |  | 107,329 |  |  | 129,331 |
Gas & Power |  | 5,763 |  |  | 5,982 |
Refining & Marketing |  | 17,383 |  |  | 17,358 |
Versalis |  | 5,898 |  |  | 6,070 |
Engineering & Construction |  | 12,774 |  |  | 13,657 |
Corporate and financial companies |  | 589 |  |  | 653 |
Other activities |  | 1,522 |  |  | 1,548 |
Elimination of intragroup profits |  | (490 | ) |  | (572 | )
|  | 150,768 |  |  | 174,027 |
Accumulated depreciation, amortization and impairment losses |  |  |  |  |  |
Exploration & Production |  | 59,195 |  |  | 72,677 |
Gas & Power |  | 3,794 |  |  | 3,998 |
Refining & Marketing |  | 12,808 |  |  | 12,897 |
Versalis |  | 4,793 |  |  | 4,877 |
Engineering & Construction |  | 4,846 |  |  | 6,041 |
Corporate and financial companies |  | 267 |  |  | 275 |
Other activities |  | 1,450 |  |  | 1,474 |
Elimination of intragroup profits |  | (148 | ) |  | (174 | )
|  | 87,005 |  |  | 102,065 |
Property, plant and equipment, net |  |  |  |  |  |
Exploration & Production |  | 48,134 |  |  | 56,654 |
Gas & Power |  | 1,969 |  |  | 1,984 |
Refining & Marketing |  | 4,575 |  |  | 4,461 |
Versalis |  | 1,105 |  |  | 1,193 |
Engineering & Construction |  | 7,928 |  |  | 7,616 |
Corporate and financial companies |  | 322 |  |  | 378 |
Other activities |  | 72 |  |  | 74 |
Elimination of intragroup profits |  | (342 | ) |  | (398 | )
|  | 63,763 |  |  | 71,962 |

17 Inventory - compulsory stock
Compulsory inventories of euro 1,581 million (euro 2,573 million at December 31, 2013) were net of accumulated provisions for impairments of euro 453 million and were primarily held by Italian subsidiaries for euro 1,566 million (euro 2,550 million at December 31, 2013) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.

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18 Intangible assets

(euro million) |  | Net book amount at the beginning of the year |  | Additions |  | Amortization |  | Impairment losses |  | Changes in the scope of consolidation |  | Currency translation differences |  | Other changes |  | Net book amount at the end of the year |  | Gross book amount at the end of the year |  | Provisions for depreciation and impairments

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Intangible assets with finite useful lives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration expenditures |  | 548 |  | 1,697 |  | (1,764 | ) |  |  |  |  |  |  | (19 | ) |  |  |  |  | 462 |  | 2,712 |  | 2,250 |
Industrial patents and intellectual property rights |  | 138 |  | 31 |  | (55 | ) |  | (2 | ) |  |  |  | (1 | ) |  | 20 |  |  | 131 |  | 1,250 |  | 1,119 |
Concessions, licenses, trademarks and similar items |  | 684 |  | 17 |  | (115 | ) |  | (15 | ) |  |  |  |  |  |  | 5 |  |  | 576 |  | 2,497 |  | 1,921 |
Service concession arrangements |  | 32 |  |  |  | (2 | ) |  |  |  |  |  |  |  |  |  | 2 |  |  | 32 |  | 48 |  | 16 |
Intangible assets in progress and advances |  | 262 |  | 124 |  |  |  |  |  |  |  |  |  |  |  |  | (26 | ) |  | 360 |  | 365 |  | 5 |
Other intangible assets |  | 362 |  | 18 |  | (40 | ) |  | (157 | ) |  |  |  | (1 | ) |  | (13 | ) |  | 169 |  | 2,112 |  | 1,943 |
|  | 2,026 |  | 1,887 |  | (1,976 | ) |  | (174 | ) |  |  |  | (21 | ) |  | (12 | ) |  | 1,730 |  | 8,984 |  | 7,254 |
Intangible assets with indefinite useful lives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Goodwill |  | 2,461 |  |  |  |  |  |  | (333 | ) |  | 34 |  | (17 | ) |  | 1 |  |  | 2,146 |  |  |  |  |
|  | 4,487 |  | 1,887 |  | (1,976 | ) |  | (507 | ) |  | 34 |  | (38 | ) |  | (11 | ) |  | 3,876 |  |  |  |  |
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Intangible assets with finite useful lives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration expenditures |  | 462 |  | 1,422 |  | (1,564 | ) |  |  |  |  |  |  | 37 |  |  | (50 | ) |  | 307 |  | 2,950 |  | 2,643 |
Industrial patents and intellectual property rights |  | 131 |  | 31 |  | (75 | ) |  |  |  |  |  |  | 1 |  |  | 197 |  |  | 285 |  | 1,479 |  | 1,194 |
Concessions, licenses, trademarks and similar items |  | 576 |  | 17 |  | (117 | ) |  | (2 | ) |  |  |  |  |  |  | 5 |  |  | 479 |  | 2,516 |  | 2,037 |
Service concession arrangements |  | 32 |  | 1 |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  | 32 |  | 49 |  | 17 |
Intangible assets in progress and advances |  | 360 |  | 69 |  |  |  |  |  |  |  |  |  |  |  |  | (250 | ) |  | 179 |  | 184 |  | 5 |
Other intangible assets |  | 169 |  | 15 |  | (32 | ) |  |  |  |  |  |  | 2 |  |  | 12 |  |  | 166 |  | 2,299 |  | 2,133 |
|  | 1,730 |  | 1,555 |  | (1,789 | ) |  | (2 | ) |  |  |  | 40 |  |  | (86 | ) |  | 1,448 |  | 9,477 |  | 8,029 |
Intangible assets with indefinite useful lives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Goodwill |  | 2,146 |  |  |  |  |  |  | (51 | ) |  | 67 |  | 36 |  |  | (1 | ) |  | 2,197 |  |  |  |  |
|  | 3,876 |  | 1,555 |  | (1,789 | ) |  | (53 | ) |  | 67 |  | 76 |  |  | (87 | ) |  | 3,645 |  |  |  |  |

Capitalized exploration expenditures of euro 307 million (euro 462 million at December 31, 2013) mainly related to the residual book value of license acquisition costs that are amortized on a straight-line basis over the contractual term of the exploration lease or fully written off against profit and loss upon expiration of terms or management’s decision to cease any exploration activities. Additions of the year of euro 1,422 million (euro 1,697 million in 2013) included exploration drilling expenditures which are fully capitalized to reflect their investment nature and then entirely amortized for euro 1,354 million (euro 1,509 million in 2013) and license acquisition costs of euro 68 million (euro 188 million in 2013) primarily related to the acquisition of new exploration acreage in Egypt, United States and South Africa. Amortizations of euro 1,564 million (euro 1,764 million in 2013) included amortizations of license acquisition costs for euro 260 million (euro 255 million in 2013).

Industrial patents and intellectual property rights of euro 285 million (euro 131 million at December 31, 2013) related to Eni SpA for euro 236 million (euro 87 million at December 31, 2013) and essentially concerned costs for the acquisition and internal development of software and rights for the use of production processes and software.

Concessions, licenses, trademarks and similar items for euro 479 million (euro 576 million at December 31, 2013) primarily comprised transmission rights for natural gas imported from Algeria of euro 423 million (euro 523 million at December 31, 2013) and concessions for mineral exploration of euro 18 million (euro 20 million at December 31, 2013).

Service concession arrangements of euro 32 million primarily pertained to gas distribution activities outside Italy (same amount as of December 31, 2013).

Intangible assets in progress and advances of euro 179 million (euro 360 million at December 31, 2013) related to Eni SpA for euro 79 million (euro 268 million at December 31, 2013) and primarily concerned cost for software development.

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Other intangible assets with finite useful lives of euro 166 million (euro 169 million at December 31, 2013) comprised: (i) royalties for the use of licenses by Versalis SpA amounting to euro 48 million (euro 52 million at December 31, 2013); and (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 euro 31 million (euro 35 million at December 31, 2013) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna.

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

(%) |  |  |  |  |  |  |  |  |
Exploration expenditures |  |  |  |  | 14 |  | - | 33 |
Industrial patents and intellectual property rights |  |  |  |  | 20 |  | - | 33 |
Concessions, licenses, trademarks and similar items |  |  |  |  | 3 |  | - | 33 |
Service concession arrangements |  |  |  |  | 2 |  | - | 4 |
Other intangible assets |  |  |  |  | 4 |  | - | 25 |

Impairment losses of intangible assets with indefinite useful lives (goodwill) amounted to euro 51 million (euro 333 million in 2013) and related to the alignment to the expected sale price of the fuel distribution networks in the Czech Republic and Slovakia (see note 16 – Property, plant and equipment).

Changes in the scope of consolidation of intangible assets with indefinite useful lives (goodwill) of euro 67 million comprised included the 51% acquisition of Acam Clienti SpA (euro 32 million), a company that operates in the distribution and commercialization of natural gas in a focused territory in Italy and the 100% acquisition of Liverpool Bay Ltd (euro 35 million) which owns a 46.1% interest in the Liverpool Bay oil and gas field. Following the acquisition Eni, which already owned a 53.9% of the field, now owns the 100% of the field and acquired the operatorship.

The carrying amount of goodwill at the end of the year was euro 2,197 million (euro 2,146 million at December 31, 2013) net of cumulative impairments amounting to euro 2,353 million (euro 2,396 million at December 31, 2013); the decrease related to a reclassification to assets held for sale.

The breakdown of goodwill by operating segment is as follows:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Gas & Power |  | 991 |  | 1,025
Engineering & Construction |  | 748 |  | 747
Exploration & Production |  | 250 |  | 323
Refining & Marketing |  | 157 |  | 102
|  | 2,146 |  | 2,197

Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition. The recoverable amounts of the CGUs are determined by discounting the future cash flows derived from the continuing use of the CGUs by applying the perpetuity method to assess the terminal value. For the determination of the cash flows see note 16 – Property, plant and equipment. In the Gas & Power segment the adjusted WACC discount rates ranged from 5.3% to 6.3% as the WACC of the segment was adjusted to take into account the specific risks of the countries in which the business is performed. In the Engineering & Construction segment, the rate used was 6.9% and was not adjusted to factor in any specific country risk as the invested capital of the Company mainly refers to movable properties. Both the segments registered a reduction of 90-70 basis points due to the lower risk premium for Italy.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

Goodwill has been allocated to the following CGUs.

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Gas & Power segment

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Domestic gas market |  | 801 |  | 835
Foreign gas market |  | 190 |  | 190
- of which European market |  | 188 |  | 188
|  | 991 |  | 1,025

In the Gas & Power segment, the 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 (euro 706 million). The Company engaged in the retail sale of gas to the residential sector. 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 latest acquisition of which was Acam Clienti SpA finalized in 2014 (with an allocated goodwill of euro 32 million). The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU including the goodwill allocated.

Goodwill allocated to the CGU European gas market, amounting to euro 188 million, was recorded following the business combinations of Altergaz SA (now Eni Gas & Power France SA) in France, Nuon Belgium NV (now merged in Eni Gas & Power NV) in Belgium, which represent two stand-alone CGUs. Also in these cases, the impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of both CGUs including the goodwill allocated.

The assessment of the gas market CGUs was performed discounting to the specific WACC 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.

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 euro 971 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 52% on average in the projected commercial margins; (ii) an increase of 8.4 percentage points in the discount rate; and (iii) a negative nominal growth rate of 14%.

Engineering & Construction segment

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Offshore E&C |  | 415 |  | 415
Onshore E&C |  | 314 |  | 313
Other |  | 19 |  | 19
|  | 748 |  | 747

The segment goodwill of euro 747 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA (euro 710 million) and allocated to the CGUs Offshore E&C and Onshore E&C. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amounts of both those CGUs, including the allocated portions of goodwill.

The key assumptions adopted for assessing the recoverable amounts of those two CGUs which exceeded their respective carrying amounts related to operating results, the discount rate, the growth rates of the perpetuity adopted to determine the terminal value and cash flows from working capital. Information on those drivers were collected from the four-year plan approved by the Company’s management, while the terminal value was estimated by using a perpetual nominal growth rate of 2% applied to the normalized cash flow of the last year of the four-year plan. The value-in-use of both CGUs was assessed by discounting the associated post-tax cash flows at a post-tax rate of 6.9% (7.6% in 2013) which corresponds to pre-tax rates of 9.0% and 11.6% for the Offshore E&C business unit and the Onshore E&C business unit, respectively (10.0% and 11.0%, respectively in 2013). The headroom of the Offshore E&C business unit of euro 5,186 million would be reduced to zero under each of the following alternative changes in the above mentioned assumptions: (i) a decrease of 71% in the operating result flat over all the years of the plan and the terminal value; (ii) an increase of 9.8 percentage points in the discount rate; (iii) negative real growth rate; and (iv) negative cash flows from working capital. The headroom of the CGU E&C Onshore of euro 695 million, including the allocated goodwill, is reduced to zero under either of the following assumptions: (i) a 54% reduction in

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operating profit flat over all the years of the plan and the long-term operating profit of the perpetuity; (ii) an increase of 4.2 percentage points in the discount rate; (iii) a negative real growth rate; and (iv) a negative cash flow from working capital.

The Exploration & Production and the Refining & Marketing segments tested their goodwill, yielding the following results: (i) in the Exploration & Production segment with goodwill amounting to euro 323 million, management believes that there are no reasonably possible changes in the pricing environment and production/cost profiles that would cause the headroom of the relevant CGUs to be reduced to zero. Goodwill mainly refers to the portion of the purchase price that was not allocated to proved or unproved properties in the business combinations Lasmo, Burren Energy (Congo), First Calgary and Liverpool Bay; and (ii) in the Refining & Marketing segment goodwill amounted to euro 102 million at the balance sheet date. Goodwill amounting to euro 86 million pertained to retail networks acquired in previous years in Austria and Hungary for which profitability expectations have remained unchanged from the previous-year impairment review.

19 Investments
Equity-accounted investments

(euro million) |  | Book amount at the beginning of the year |  | Additions |  | 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

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Investments in unconsolidated entities controlled by Eni |  | 215 |  | 9 |  |  |  |  | 37 |  | (9 | ) |  | (24 | ) |  | (19 | ) |  | (6 | ) |  | (2 | ) |  | 201
Joint ventures |  | 1,445 |  | 50 |  | (11 | ) |  | 145 |  | (31 | ) |  | (47 | ) |  |  |  |  | (94 | ) |  | (389 | ) |  | 1,068
Associates |  | 1,793 |  | 230 |  | (1 | ) |  | 131 |  | (65 | ) |  | (195 | ) |  |  |  |  | (73 | ) |  | 64 |  |  | 1,884
|  | 3,453 |  | 289 |  | (12 | ) |  | 313 |  | (105 | ) |  | (266 | ) |  | (19 | ) |  | (173 | ) |  | (327 | ) |  | 3,153
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Investments in unconsolidated entities controlled by Eni |  | 201 |  | 5 |  | (2 | ) |  | 27 |  | (10 | ) |  | (19 | ) |  | 3 |  |  | 18 |  |  | (27 | ) |  | 196
Joint ventures |  | 1,068 |  | 51 |  | (20 | ) |  | 133 |  | (18 | ) |  | (98 | ) |  |  |  |  | 38 |  |  | 61 |  |  | 1,215
Associates |  | 1,884 |  | 316 |  | (461 | ) |  | 55 |  | (58 | ) |  | (78 | ) |  |  |  |  | 189 |  |  | (143 | ) |  | 1,704
|  | 3,153 |  | 372 |  | (483 | ) |  | 215 |  | (86 | ) |  | (195 | ) |  | 3 |  |  | 245 |  |  | (109 | ) |  | 3,115

In 2014, additions of euro 372 million mainly related to capital contributions to joint ventures and associates engaged in the realization of projects in the interest of Eni: Angola LNG Ltd (euro 46 million) which is currently upgrading a liquefaction plant in order to monetize Eni’s gas reserves in that Country (Eni’s interest in the project being 13.6%); South Stream Transport BV (euro 268 million) which is engaged in the economic feasibility, procurement and construction of the offshore section of the South Stream pipeline. The company was sold to Gazprom in December 2014; PetroJunin SA (euro 29 million) which is developing gas and crude oil fields in Venezuela.

Divestments and reimbursements of euro 483 million are stated net of gains on disposals (euro 67 million). In December 2014, Eni divested its 20% stake in South Stream Transport BV to Gazprom. Pursuant to the shareholders agreement, Eni exercised a put option of its stake whereby the Company would recover the capital invested in the project, determined in accordance with existing agreements. In August 2014, Eni divested a 50% stake in EnBW Eni Verwaltungsgesellschaft mbH, a joint venture which controls the companies Gasversorgung Süddeutschland GmbH and Terranets BW operating in the marketing and transport of gas in Germany, to the partner EnBW Energie Baden-Württemberg AG.

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Eni’s share of profit of equity-accounted investments and dividend decrease pertained to the following entities:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

|  | 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 (%)

Unión Fenosa Gas SA |  | 38 |  |  |  | 50.00 |  | 42 |  | 23 |  | 50.00
United Gas Derivatives Co |  | 56 |  | 60 |  | 33.33 |  | 32 |  | 36 |  | 33.33
CARDÓN IV SA |  | 21 |  |  |  | 50.00 |  | 28 |  |  |  | 50.00
Eni BTC Ltd |  | 25 |  | 22 |  | 100.00 |  | 22 |  | 17 |  | 100.00
Unimar Llc |  | 30 |  | 19 |  | 50.00 |  | 19 |  | 46 |  | 50.00
Petromar Lda |  |  |  |  |  |  |  | 14 |  |  |  | 70.00
Eteria Parohis Aeriou Thessalonikis AE |  | 11 |  | 11 |  | 49.00 |  | 9 |  | 10 |  | 49.00
PetroSucre SA |  | 44 |  | 105 |  | 26.00 |  | 6 |  | 29 |  | 26.00
Other investments |  | 88 |  | 49 |  |  |  | 43 |  | 34 |  |
|  | 313 |  | 266 |  |  |  | 215 |  | 195 |  |

Eni’s share of losses of equity-accounted investments related to the following entities:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

|  | Share of loss of equity-accounted investments |  | Eni’s interest (%) |  | Share of loss of equity-accounted investments |  | Eni’s interest (%)

Angola LNG Ltd |  | 42 |  | 13.60 |  | 34 |  | 13.60
South Stream Transport BV |  | 7 |  | 20.00 |  | 20 |  |
Westgasinvest Llc |  | 3 |  | 50.01 |  | 6 |  | 50.01
Petromar Lda |  | 18 |  | 70.00 |  |  |  |
Société Centrale Eletrique du Congo SA |  | 14 |  | 20.00 |  |  |  |
Zagoryanska Petroleum BV |  | 5 |  | 60.00 |  |  |  |
Other investments |  | 16 |  |  |  | 26 |  |
|  | 105 |  |  |  | 86 |  |

Losses at the equity-accounted investment in Angola LNG Ltd (euro 34 million) related to pre-production expenses and operating costs associated with the start-up of a liquefaction plant.

Currency translation differences of euro 245 million were essentially related to translation of entities accounts denominated in U.S. dollar.

Other changes of euro 109 million comprised the reclassification to assets held for sale of Ceská Rafinérská AS, Inversora de Gas Cuyana SA, Distribuidora de Gas Cuyana SA, Inversora de Gas del Centro SA, Distribuidora de Gas del Centro SA and Fertilizantes Nitrogenados de Oriente CEC for euro 104 million.

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List of equity-accounted investments:

(euro million) | Dec. 31, 2013 |  | Dec. 31, 2014

| Net carrying amount |  | Number of shares held |  | Eni’s interest (%) |  | Net carrying amount |  | Number of shares held |  | Eni’s interest (%)

Investments in unconsolidated entities controlled by Eni |  |  |  |  |  |  |  |  |  |  |  |
Eni BTC Ltd |  | 96 |  | 34,000,000 |  | 100.00 |  | 115 |  | 34,000,000 |  | 100.00
Other investments (*) |  | 105 |  |  |  |  |  | 81 |  |  |  |
|  | 201 |  |  |  |  |  | 196 |  |  |  |
Joint ventures |  |  |  |  |  |  |  |  |  |  |  |
Unión Fenosa Gas SA |  | 547 |  | 273,100 |  | 50.00 |  | 577 |  | 273,100 |  | 50.00
CARDÓN IV SA |  | 102 |  | 8,605 |  | 50.00 |  | 146 |  | 8,605 |  | 50.00
Eteria Parohis Aeriou Thessalonikis AE |  | 130 |  | 116,546,500 |  | 49.00 |  | 111 |  | 99,396,500 |  | 49.00
PetroJunin SA |  |  |  |  |  |  |  | 93 |  | 44,424,000 |  | 40.00
Unimar Llc |  | 76 |  | 50 |  | 50.00 |  | 58 |  | 50 |  | 50.00
Eteria Parohis Aeriou Thessalias AE |  | 45 |  | 38,445,008 |  | 49.00 |  | 44 |  | 38,445,008 |  | 49.00
Petromar Lda |  | 22 |  | 1 |  | 70.00 |  | 42 |  | 1 |  | 70.00
Lotte Versalis Elastomers Co Ltd |  | 21 |  | 6,020,000 |  | 50.00 |  | 31 |  | 8,720,000 |  | 50.00
Other investments (*) |  | 125 |  |  |  |  |  | 113 |  |  |  |
|  | 1,068 |  |  |  |  |  | 1,215 |  |  |  |
Associates |  |  |  |  |  |  |  |  |  |  |  |
Angola LNG Ltd |  | 1,067 |  | 1,410,127,664 |  | 13.60 |  | 1,226 |  | 1,471,803,666 |  | 13.60
PetroSucre SA |  | 173 |  | 5,727,800 |  | 26.00 |  | 171 |  | 5,727,800 |  | 26.00
United Gas Derivatives Co |  | 96 |  | 950,000 |  | 33.33 |  | 102 |  | 950,000 |  | 33.33
Novamont SpA |  | 77 |  | 6,667 |  | 25.00 |  | 77 |  | 6,667 |  | 25.00
Rosetti Marino SpA |  | 32 |  | 800,000 |  | 20.00 |  | 31 |  | 800,000 |  | 20.00
EnBW Eni Verwaltungsgesellschaft mbH |  | 179 |  | 1 |  | 50.00 |  |  |  |  |  |
Fertilizantes Nitrogenados de Oriente CEC |  | 68 |  | 1,933,565,443 |  | 20.00 |  |  |  |  |  |
PetroJunin SA |  | 51 |  | 44,424,000 |  | 40.00 |  |  |  |  |  |
South Stream Transport BV |  | 51 |  | 82,396 |  | 20.00 |  |  |  |  |  |
Other investments (*) |  | 90 |  |  |  |  |  | 97 |  |  |  |
|  | 1,884 |  |  |  |  |  | 1,704 |  |  |  |
|  | 3,153 |  |  |  |  |  | 3,115 |  |  |  |

(*) |  | Each individual amount included herein was lower than euro 25 million.

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 euro 238 million which pertained to Unión Fenosa Gas SA (goodwill) for euro 195 million and to Novamont SpA (goodwill) for euro 43 million.

The table below sets out the provisions for losses included in the provisions for contingencies of euro 158 million (euro 151 million at December 31, 2013), primarily related to the following equity-accounted investments:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) |  | 92 |  | 90
VIC CBM Ltd |  | 18 |  | 25
Société Centrale Eletrique du Congo SA |  | 9 |  | 9
Other investments |  | 32 |  | 34
|  | 151 |  | 158

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Other investments

(euro million) |  | `Net book amount at the beginning of the year` |  | `Additions` |  | `Divestments and reimbursement` |  | `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`

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Investments in unconsolidated entities controlled by Eni |  | 15 |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  | 14 |  | 15 |  | 1
Associates |  | 12 |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  | 13 |  | 13 |  |
Other investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- valued at fair value |  | 4,782 |  |  |  | (2,191 | ) |  | 179 |  |  |  |  |  |  |  |  | 2,770 |  | 2,770 |  |
- valued at cost |  | 276 |  | 3 |  | (5 | ) |  |  |  |  | (8 | ) |  | (36 | ) |  | 230 |  | 233 |  | 3
|  | 5,085 |  | 3 |  | (2,196 | ) |  | 179 |  |  | (8 | ) |  | (36 | ) |  | 3,027 |  | 3,031 |  | 4
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Investments in unconsolidated entities controlled by Eni |  | 14 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 14 |  | 14 |  |
Associates |  | 13 |  |  |  | (2 | ) |  |  |  |  | 3 |  |  | (2 | ) |  | 12 |  | 12 |  |
Other investments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- valued at fair value |  | 2,770 |  |  |  | (805 | ) |  | (221 | ) |  |  |  |  |  |  |  | 1,744 |  | 1,744 |  |
- valued at cost |  | 230 |  |  |  | (5 | ) |  |  |  |  | 22 |  |  | (2 | ) |  | 245 |  | 248 |  | 3
|  | 3,027 |  |  |  | (812 | ) |  | (221 | ) |  | 25 |  |  | (4 | ) |  | 2,015 |  | 2,018 |  | 3

Investments in unconsolidated entities controlled by Eni and associates are stated at cost net of impairment losses. Other investments, for which fair value cannot be reliably determined, were recognized at cost and adjusted for impairment losses.

Divestments and reimbursements of euro 812 million are stated net of gains on disposals (euro 19 million) and related to the sale of an interest of 8.15% in Galp Energia SGPS SA for euro 805 million. This disposal was carried out according to two different transactions: (i) a private placement of 58,051,000 ordinary shares, corresponding to approximately 7% of the share capital through an accelerated book-building procedure aimed at qualified institutional investors on March 28, 2014, for a total consideration of euro 702 million, at a price of euro 12.10 per share. A gain of euro 11 million and a reversal of the fair value measurement reserve for euro 66 million was recognized in the profit and loss account; and (ii) spot sales and private placements of approximately 1.15% of the share capital for a total consideration of euro 122 million corresponding to an average price of euro 12.83 per share. A gain of euro 8 million and a reversal of the fair value measurement reserve for euro 11 million was recognized in the profit and loss account.

A fair value adjustment was recognized for euro 221 million relating to a loss of euro 231 million on the interest held in Galp Energia SGPS SA and a gain of euro 10 million on the interest in Snam SpA. Such amounts were reported through profit in application of the fair value option provided by IAS 39 in order to eliminate an accounting mismatch derived from the measurement at fair value through profit of the options embedded in the convertible bonds which led to the recognition of a gain of euro 68 million. More information is provided in note 39 – Finance income (expense).

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The net carrying amount of other investments of euro 2,015 million (euro 3,027 million at December 31, 2013) was related to the following entities:

(euro million) | Dec. 31, 2013 |  | Dec. 31, 2014

| Net carrying amount |  | Number of shares held |  | Eni’s interest (%) |  | Net carrying amount |  | Number of shares held |  | Eni’s interest (%)

Investments in unconsolidated entities controlled by Eni (*) |  | 14 |  |  |  |  |  | 14 |  |  |  |
Associates |  | 13 |  |  |  |  |  | 12 |  |  |  |
Other investments: |  |  |  |  |  |  |  |  |  |  |  |
- Snam SpA |  | 1,174 |  | 288,683,602 |  | 8.54 |  | 1,184 |  | 288,683,602 |  | 8.25
- Galp Energia SGPS SA |  | 1,596 |  | 133,945,630 |  | 16.15 |  | 560 |  | 66,337,592 |  | 8.00
- Nigeria LNG Ltd |  | 86 |  | 118,373 |  | 10.40 |  | 97 |  | 118,373 |  | 10.40
- Darwin LNG Pty Ltd |  | 58 |  | 213,995,164 |  | 10.99 |  | 60 |  | 213,995,164 |  | 10.99
- other (*) |  | 86 |  |  |  |  |  | 88 |  |  |  |
|  | 3,000 |  |  |  |  |  | 1,989 |  |  |  |
|  | 3,027 |  |  |  |  |  | 2,015 |  |  |  |

(*) |  | Each individual amount included herein was lower than euro 25 million.

At December 31, 2014, Eni holds 288,683,602 shares equal to 8.25% of the outstanding share capital of Snam which are underlying a euro 1,250 million convertible bond, issued on January 18, 2013 due on January 18, 2016. At December 31, 2014, the retained interest in Snam was stated at fair value for euro 1,184 million determined at a market price of euro 4.1 per share.

At December 31, 2014, Eni holds 66,337,592 shares equal to approximately 8% of Galp’s outstanding share capital which are underlying a euro 1,028 million convertible bond, issued on November 30, 2012 due on November 30, 2015. At December 31, 2014, the retained interest in Galp was stated at fair value for euro 560 million determined at a market price of euro 8.43 per share.

The additional information required is included in note 45 – Other information about investments.

20 Other financial assets

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Receivables held for operating purposes |  | 778 |  | 946
Securities held for operating purposes |  | 80 |  | 76
|  | 858 |  | 1,022

Financing receivables held for operating purposes are stated net of the valuation allowance for doubtful accounts of euro 134 million (euro 66 million at December 31, 2013).

Financing receivables held for operating purposes of euro 946 million (euro 778 million at December 31, 2013) primarily pertained to loans granted by the Exploration & Production segment (euro 632 million), the Gas & Power segment (euro 157 million) and Versalis (euro 70 million). Financing receivables granted to unconsolidated subsidiaries, joint ventures and associates amounted to euro 239 million.

Financing receivables held for operating purposes in currencies other than euro amounted to euro 791 million (euro 729 million at December 31, 2013).

Financing receivables held for operating purposes due beyond five years amounted to euro 516 million (euro 474 million at December 31, 2013).

The valuation at fair value of financing receivables of euro 978 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from 0.2% to 2.7% (0.5% and 4.2% at December 31, 2013). The fair value hierarchy is level 2.

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Securities of euro 76 million (euro 80 million at December 31, 2013) were designated as held-to-maturity and related to listed bonds issued by sovereign states for euro 69 million (same amount as of December 31, 2013) and by the European Investment Bank for euro 7 million (euro 8 million at December 31, 2013) and, as of December 31, 2013, by financial institution euro 3 million.

Securities amounting to euro 20 million (same amount as of December 31, 2013) were pledged as guarantee of the deposit for gas cylinders as provided for by the Italian law.

The following table analyses securities per issuing entity:

|  | Amortized cost (euro million) |  | Nominal value (euro million) |  | Fair value (euro million) |  | Nominal rate of return (%) |  | Maturity date |  | Rating - Moody’s |  | Rating - S&P

Sovereign states |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate bonds |  |  |  |  |  |  |  |  |  |  |  |  |  |
Italy |  | 24 |  | 24 |  | 26 |  | from 1.50 to 5.75 |  | from 2015 to 2021 |  | Baa2 |  | BBB-
Ireland |  | 9 |  | 8 |  | 9 |  | from 4.40 to 4.50 |  | from 2018 to 2019 |  | Baa1 |  | A
Spain |  | 6 |  | 5 |  | 6 |  | from 3.00 to 4.30 |  | from 2015 to 2019 |  | Baa2 |  | BBB
Belgium |  | 2 |  | 2 |  | 2 |  | 1.25 |  | 2018 |  | Aa3 |  | AA
Floating rate bonds |  |  |  |  |  |  |  |  |  |  |  |  |  |
Italy |  | 12 |  | 13 |  | 13 |  |  |  | from 2015 to 2016 |  | Baa2 |  | BBB-
Belgium |  | 7 |  | 7 |  | 7 |  |  |  | 2016 |  | Aa3 |  | AA
Spain |  | 7 |  | 7 |  | 7 |  |  |  | 2015 |  | Baa2 |  | BBB
Slovakia |  | 2 |  | 2 |  | 2 |  |  |  | 2015 |  | A2 |  | A
Total sovereign states |  | 69 |  | 68 |  | 72 |  |  |  |  |  |  |  |
Floating rate bonds |  |  |  |  |  |  |  |  |  |  |  |  |  |
European Investment Bank |  | 7 |  | 7 |  | 7 |  |  |  | from 2016 to 2018 |  | Aaa |  | AAA
|  | 76 |  | 75 |  | 79 |  |  |  |  |  |  |  |

Securities with a maturity beyond five years amounted to euro 4 million.

The fair value of securities was derived from market prices.

Receivables with related parties are described in note 44 – Transactions with related parties.

21 Deferred tax assets

Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for euro 3,915 million (euro 3,562 million at December 31, 2013).

(euro million) | Amount at Dec. 31, 2013 |  | Additions |  | Deductions |  | Currency translation differences |  | Other changes |  | Amount at Dec. 31, 2014

|  | 4,658 |  | 1,585 |  | (1,253) |  | 540 |  | (299) |  | 5,231

Deferred tax assets related to the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes for euro 2,929 million (euro 2,653 million at December 31, 2013) were recognized on the operating losses recorded in the year and upon the recognition of expenses which are deductible in future years. Deferred tax assets were recognized within the limits of the amounts expected to be recovered in future years based on the expected future profit before income taxes.

The decrease of euro 1,253 million in the Group deferred tax assets mainly comprised a write-off recognized by Italian subsidiaries for euro 976 million due to: (i) the projections of lower future taxable profit (euro 500 million) determined on the basis of the four-year plan approved by the Board of Directors and, for the subsequent years, and on the projections of future taxable profit only in the Italian Exploration & Production activities; and (ii) the prospective abrogation of an Italian windfall tax (euro 476 million) which was levied on Italian energy companies (the so-called Robin Tax) in 2008 as provided by Article 81 of the Legislative Decree No. 112, resulting in the redetermination of the deferred tax assets on future deductible costs and tax loss carryforwards with a statutory tax rate of 27.5% instead of 34%. The abrogation is the consequence of the statement of illegitimacy of this tax issued by the Italian Constitutional Court in February 2015. For the first time, a sentence has stated the illegitimacy of a tax

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rule prospectively, denying any reimbursement right. The effect was considered to be an adjusting event of 2014 results, on the basis of the best review of the matter currently available, considering the recent pronouncement of the sentence.

Deferred tax assets are further described in note 31 – Deferred tax liabilities.

Income taxes are described in note 41 – Income tax expense.

22 Other non-current receivables

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Tax receivables from: |  |  |  |
- Italian Tax Authorities |  |  |  |
. income tax |  | 133 |  | 864
. interest on tax credits |  | 65 |  | 94
|  | 198 |  | 958
- foreign tax authorities |  | 267 |  | 265
|  | 465 |  | 1,223
Other receivables: |  |  |  |
- related to divestments |  | 702 |  | 636
- other non-current |  | 148 |  | 153
|  | 850 |  | 789
Fair value of non-hedging derivatives |  | 256 |  | 196
Fair value of cash flow hedge derivative instruments |  | 6 |  |
Other asset |  | 2,099 |  | 565
|  | 3,676 |  | 2,773

The increase in tax receivables from Italian Fiscal Authorities of euro 731 million include the recognition of a tax gain of euro 824 million due to the settlement of a tax dispute with the Italian Fiscal Authorities regarding how to determine a tax surcharge of 4% due by the parent company Eni SpA as provided by Law No. 7/2009 (the so-called Libyan tax) since 2009.

Receivables originated from divestments amounted to euro 636 million (euro 702 million at December 31, 2013) and included: (i) the long-term portion of a receivable of euro 401 million related to the divestment of the 1.71% interest in the Kashagan project to the local partner KazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea PSA and the Kazakh Government, which became effective from January 1, 2008. The reimbursement of the receivable is provided for in three annual installments starting from the date when the production will reach a commercial level. The receivable accrues interest income at market rates; and (ii) the residual outstanding amount of euro 123 million recognized following the compensation agreed with the Republic of Venezuela for the expropriated Dación oilfield in 2006. The receivable accrues interests at market conditions as the collection has been fractionated in installments. In 2014, reimbursements amounted to euro 64 million (US$ 86 million). Negotiations are ongoing to define further repayments of the outstanding receivable.

Receivables with related parties are described in note 44 – Transactions with related parties.

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The fair value of non-hedging derivative contracts was as follows:

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Fair value |  | Purchase commitments |  | Sale commitments |  | Fair value |  | Purchase commitments |  | Sale commitments

Derivatives on exchange rate |  |  |  |  |  |  |  |  |  |  |  |
Interest currency swap |  | 138 |  | 754 |  | 271 |  | 139 |  | 594 |  | 392
Currency swap |  | 47 |  | 194 |  | 509 |  | 10 |  | 324 |  |
|  | 185 |  | 948 |  | 780 |  | 149 |  | 918 |  | 392
Derivatives on interest rate |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  | 58 |  | 642 |  | 6 |  | 47 |  | 550 |  |
|  | 58 |  | 642 |  | 6 |  | 47 |  | 550 |  |
Derivatives on commodities |  |  |  |  |  |  |  |  |  |  |  |
Over the counter |  | 13 |  | 94 |  | 46 |  |  |  |  |  |
|  | 13 |  | 94 |  | 46 |  |  |  |  |  |
|  | 256 |  | 1,684 |  | 832 |  | 196 |  | 1,468 |  | 392

Derivative fair values are calculated basing on market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques generally adopted in the marketplace.

Fair values of non-hedging derivatives of euro 196 million (euro 256 million at December 31, 2013) 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 value of cash flow hedge derivatives of euro 6 million at December 31, 2013 related to hedges entered by the Gas & Power segment. Further information is disclosed in note 15 – Other current assets. Fair value related to the contracts expiring beyond 2015 is disclosed in note 32 – Other non-current liabilities; fair value related to the contracts expiring in 2015 is disclosed in note 15 – Other current assets and in note 27 – Other current liabilities. The effects of fair value measurement of cash flow hedges are disclosed in note 34 – Shareholders’ equity and note 38 – Operating expenses.

Nominal values of cash flow hedge derivatives for sale commitments amounted to euro 132 million at December 31, 2013.

Information on the hedged risks and the hedging policies is disclosed in note 36 – Guarantees, commitments and risks - Risk factors.

Other non-current assets amounted to euro 565 million (euro 2,099 million at December 31, 2013), of which euro 395 million (euro 1,892 million at December 31, 2013) were deferred costs relating to the obligation to pay in advance 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. In accordance with those arrangements, the Company is contractually required to collect minimum annual quantities of gas, or in case of failure, is contractually obliged to pay the whole price or a fraction of it for the uncollected volumes up to the minimum annual quantity. 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-years impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. In 2014, based on this accounting principle was recorded an impairment loss of euro 54 million. The reduction of approximately euro 1.5 billion from the previous year is due to the make-up of part of the pre-paid gas volumes as a result of the renegotiation of certain long-term contracts and other optimizations performed during the period. A portion of these deferred costs were reclassified as current assets, as the Company plans to lift the prepaid quantities in 2015 (euro 496 million). The residual deferred costs were classified as non-current assets, as the Company plans to lift the prepaid quantities beyond the term of 12 months. Despite the weak market conditions in the European gas sector due to declining demand and strong competitive pressures fuelled by oversupplies, management plans to recover those prepaid volumes within the plan horizon by leveraging on an improved competitiveness of the Company in the gas market, the renegotiations whereby the Company achieved a reduction in annual minimum quantities and other actions of commercial optimizations as a result of the Company’s simultaneous presence in different markets and the availability of assets (logistics capacity, transportation rights).

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Current liabilities
23 Short-term debt

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Commercial papers |  | 1,767 |  | 1,926
Banks |  | 306 |  | 435
Other financial institutions |  | 480 |  | 355
|  | 2,553 |  | 2,716

The increase in short-term debt of euro 163 million included net assumptions for euro 207 million, partially offset by foreign currency translation differences of euro 36 million. Commercial papers of euro 1,926 million (euro 1,767 million at December 31, 2013) were issued by the Group’s financial subsidiaries Eni Finance USA Inc (euro 1,749 million) and Eni Finance International SA (euro 177 million).

The breakdown by currency of short-term debt is provided below:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Euro |  | 485 |  | 453
U.S. dollar |  | 1,845 |  | 1,987
Other currencies |  | 223 |  | 276
|  | 2,553 |  | 2,716

As of December 31, 2014, the weighted average interest rate on short-term debt was 1.5% (1.1% as of December 31, 2013).

As of December 31, 2014, Eni had undrawn committed and uncommitted borrowing facilities amounting to euro 41 million and euro 12,657 million, respectively (euro 2,141 million and euro 12,187 million at December 31, 2013, respectively). Those facilities bore interest rates reflecting prevailing conditions in the marketplace. Charges for unutilized facilities were immaterial.

As of December 31, 2014, Eni was in compliance with covenants and other contractual provisions in relation to borrowing facilities.

The fair value of short-term debt and loans matched their respective carrying amounts considering the short term maturity and conditions of remuneration.

Payables due to related parties are described in note 44 – Transactions with related parties.

24 Trade and other payables

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Trade payables |  | 15,584 |  | 15,015
Advances |  | 2,462 |  | 2,278
Other payables: |  |  |  |
- related to capital expenditures |  | 2,045 |  | 2,693
- others |  | 3,610 |  | 3,717
|  | 5,655 |  | 6,410
|  | 23,701 |  | 23,703

The decrease in trade payables amounting to euro 569 million primarily related to the decrease in the Refining & Marketing segment (euro 796 million) and the Gas & Power segment (euro 444 million) partially offset by the increase in the Engineering & Construction segment (euro 560 million).

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Down payments and advances20 for euro 2,278 million (euro 2,462 million at December 31, 2013) related to contract work in progress in the Engineering & Construction segment for euro 1,314 million and euro 620 million, respectively (euro 1,231 million and euro 825 million at December 31, 2013, respectively).

Other payables were as follows

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Payables related to capital expenditures due to |  |  |  |
Suppliers in relation to investing activities |  | 1,479 |  | 2,301
Joint venture operators in exploration and production activities |  | 479 |  | 252
Other |  | 87 |  | 140
|  | 2,045 |  | 2,693
Other payables |  |  |  |
Joint venture operators in exploration and production activities |  | 2,160 |  | 2,117
Employees |  | 391 |  | 485
Social security entities |  | 179 |  | 182
Non-financial government entities |  | 229 |  | 238
Other |  | 651 |  | 695
|  | 3,610 |  | 3,717
|  | 5,655 |  | 6,410

Other payables of euro 3,717 million (euro 3,610 million at December 31, 2013) included euro 12 million (the same amount as of December 31, 2013) relating to debt for the settlement of tax positions with unconsolidated subsidiaries which are part of the consolidated accounts for Italian tax purposes.

The fair value of trade and other payables matched their respective carrying amounts considering the short-term maturity of trade payables.

Payables to related parties are described in note 44 – Transactions with related parties.

25 Income taxes payable

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Italian subsidiaries |  | 69 |  | 73
Subsidiaries outside Italy |  | 686 |  | 461
|  | 755 |  | 534

Income tax expenses are described in note 41 – Income taxes.

26 Other taxes payable

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Excise and customs duties |  | 1,256 |  | 971
Other taxes and duties |  | 1,035 |  | 902
|  | 2,291 |  | 1,873

(20) |  | Down payments received for long-term contracts in progress correspond to the amounts invoiced to customers in excess of the work accrued at the end of the reporting period based on the percentage of completion. Advances on long-term contracts in progress include advanced payments made by customers and contractually agreed; these advanced payments are used during the contract execution in connection with the invoicing of the works performed.

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27 Other current liabilities

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Fair value of cash flow hedge derivatives |  | 213 |  | 510
Fair value of other derivatives |  | 782 |  | 3,601
Other liabilities |  | 442 |  | 378
|  | 1,437 |  | 4,489

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or alternatively, appropriate valuation techniques commonly used on the marketplace.

The fair value of cash flow hedge derivatives amounted to euro 510 million (euro 213 million at December 31, 2013) and essentially pertained to hedges entered by the Gas & Power segment for euro 502 million. Those derivatives were designated to hedge exchange rate and commodity risk exposures as described in note 15 – Other current assets. Fair value of contracts expiring by end of 2015 is disclosed in note 15 – Other current assets; fair value of contracts expiring beyond 2015 is disclosed in note 32 – Other non-current liabilities and in note 22 – Other non-current receivables. The effects of the measurement at fair value of cash flow hedge derivatives are disclosed in note 34 – Shareholders’ equity and in note 38 – Operating expenses. The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for euro 3,686 million and euro 29 million, respectively (euro 3,689 million and euro 1,393 million at December 31, 2013, respectively).

The fair value of other derivative contracts is presented below:

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Fair value |  | Purchase commitments |  | Sale commitments |  | Fair value |  | Purchase commitments |  | Sale commitments

Derivatives on exchange rate |  |  |  |  |  |  |  |  |  |  |  |
Currency swap |  | 177 |  | 6,963 |  | 893 |  | 715 |  | 1,424 |  | 11,410
Outright |  | 102 |  | 1,983 |  |  |  | 12 |  | 48 |  | 130
Interest currency swap |  |  |  |  |  |  |  | 6 |  | 69 |  |
|  | 279 |  | 8,946 |  | 893 |  | 733 |  | 1,541 |  | 11,540
Derivatives on interest rate |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  | 1 |  |  |  | 121 |  | 1 |  | 16 |  | 5
|  | 1 |  |  |  | 121 |  | 1 |  | 16 |  | 5
Derivatives on commodities |  |  |  |  |  |  |  |  |  |  |  |
Over the counter |  | 488 |  | 6,187 |  | 995 |  | 2,663 |  | 18,744 |  | 1,631
Future |  | 12 |  | 181 |  | 37 |  | 81 |  | 11,276 |  | 13,018
Options |  | 2 |  |  |  | 2 |  | 123 |  |  |  | 1,264
|  | 502 |  | 6,368 |  | 1,034 |  | 2,867 |  | 30,020 |  | 15,913
|  | 782 |  | 15,314 |  | 2,048 |  | 3,601 |  | 31,577 |  | 27,458

Fair values of other derivatives of euro 3,601 million (euro 782 million at December 31, 2013) consisted of: (i) euro 792 million (euro 376 million at December 31, 2013) of derivatives that lacked the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to movements in foreign currencies, interest rates or commodity prices; (ii) euro 2,670 million (euro 405 million at December 31, 2013) of commodity derivatives entered for trading purposes and proprietary trading; (iii) derivative financial instruments subject to net settlement agreements amounted to euro 138 million, of which euro 81 million related to non-hedging derivatives and euro 57 million related to trading derivatives; and (iv) euro 1 million (same amount as of December 31, 2013) related to fair value hedge derivatives.

Information on hedged risks and hedging policies is disclosed in note 36 – Guarantees, commitments and risks – Risk factors.

Other current liabilities of euro 378 million (euro 442 million at December 31, 2013) included advances recovered from gas customers who off-took lower volumes than the contractual minimum take provided by the relevant long-term supply contract (euro 31 million) and the current portion of advances received from Suez following a long-term agreement for supplying natural gas and electricity for euro 78 million (euro 111 million at December 31, 2013). The non-current portion is disclosed in note 32 – Other non-current liabilities.

Transactions with related parties are described in note 44 – Transactions with related parties.

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Non-current liabilities
28 Long-term debt and current portion of long-term debt

(euro million) |  | At December 31, |  |  |  | Long-term maturity

|  | Maturity range |  | 2013 |  | 2014 |  | Current maturity 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 |  | After |  | Total

Banks |  | 2015-2032 |  | 2,390 |  | 2,772 |  | 236 |  | 429 |  | 498 |  | 226 |  | 223 |  | 1,160 |  | 2,536
Ordinary bonds |  | 2015-2043 |  | 18,151 |  | 17,924 |  | 2,565 |  | 1,498 |  | 2,660 |  | 1,190 |  | 2,514 |  | 7,497 |  | 15,359
Convertible bonds |  | 2015-2016 |  | 2,240 |  | 2,263 |  | 1,024 |  | 1,239 |  |  |  |  |  |  |  |  |  | 1,239
Other financial institutions |  | 2015-2028 |  | 226 |  | 216 |  | 34 |  | 38 |  | 40 |  | 41 |  | 44 |  | 19 |  | 182
|  |  |  | 23,007 |  | 23,175 |  | 3,859 |  | 3,204 |  | 3,198 |  | 1,457 |  | 2,781 |  | 8,676 |  | 19,316

Long-term debt and current portion of long-term debt of euro 23,175 million (euro 23,007 million at December 31, 2013) increased by euro 168 million. The increase comprised new issuance of euro 1,916 million net of repayments made for euro 2,751 million and currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for euro 752 million.

Debt due to banks of euro 2,772 million (euro 2,390 million at December 31, 2013) included amounts against committed borrowing facilities for euro 1 million (euro 3 million at December 31, 2013).

Debt due to other financial institutions of euro 216 million (euro 226 million at December 31, 2013) included euro 28 million of finance lease transactions (euro 31 million at December 31, 2013).

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 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, 2014 debts subjected to restrictive covenants amounted to euro 2,314 million (euro 1,782 million at December 31, 2013). A possible non-compliance with those covenants would be immaterial to the Company’s ability to finance its operations. Eni was in compliance with those covenants. Furthermore, Saipem entered into borrowing facilities for euro 250 million which are subject to the maintenance of certain financial ratios based on the Consolidated Financial Statements of Saipem. The compliance with the agreed conditions is verified starting from the interim financial report 2015.

Ordinary bonds of euro 17,924 million (euro 18,151 million at December 31, 2013) consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 13,591 million and other bonds for a total of euro 4,333 million.

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The following table provides a breakdown of bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2014:

|  | Amount |  | Discount on bond issue and accrued expense |  | Total |  | Currency |  | Maturity |  | Rate %

(euro million) |  |  |  |  |  |  |  |  |  | from |  | to |  | from |  | to

Issuing entity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Euro Medium Term Notes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni SpA |  | 1,500 |  | 67 |  |  | 1,567 |  | EUR |  |  |  | 2016 |  |  |  | 5.000
Eni SpA |  | 1,500 |  | 12 |  |  | 1,512 |  | EUR |  |  |  | 2019 |  |  |  | 4.125
Eni SpA |  | 1,250 |  | 3 |  |  | 1,253 |  | EUR |  |  |  | 2017 |  |  |  | 4.750
Eni SpA |  | 1,200 |  | 18 |  |  | 1,218 |  | EUR |  |  |  | 2025 |  |  |  | 3.750
Eni SpA |  | 1,000 |  | 34 |  |  | 1,034 |  | EUR |  |  |  | 2020 |  |  |  | 4.250
Eni SpA |  | 1,000 |  | 30 |  |  | 1,030 |  | EUR |  |  |  | 2018 |  |  |  | 3.500
Eni SpA |  | 1,000 |  | 25 |  |  | 1,025 |  | EUR |  |  |  | 2029 |  |  |  | 3.625
Eni SpA |  | 1,000 |  | 18 |  |  | 1,018 |  | EUR |  |  |  | 2020 |  |  |  | 4.000
Eni SpA |  | 1,000 |  | 4 |  |  | 1,004 |  | EUR |  |  |  | 2023 |  |  |  | 3.250
Eni SpA |  | 800 |  | 1 |  |  | 801 |  | EUR |  |  |  | 2021 |  |  |  | 2.625
Eni SpA |  | 750 |  | 11 |  |  | 761 |  | EUR |  |  |  | 2019 |  |  |  | 3.750
Eni Finance International SA |  | 578 |  | 14 |  |  | 592 |  | GBP |  | 2018 |  | 2021 |  | 4.750 |  | 6.125
Eni Finance International SA |  | 395 |  | 5 |  |  | 400 |  | EUR |  | 2017 |  | 2043 |  | 3.750 |  | 5.441
Eni Finance International SA |  | 213 |  | 1 |  |  | 214 |  | YEN |  | 2015 |  | 2037 |  | 1.530 |  | 2.810
Eni Finance International SA |  | 144 |  | 2 |  |  | 146 |  | USD |  |  |  | 2015 |  | 4.450 |  | 4.800
Eni Finance International SA |  | 16 |  |  |  |  | 16 |  | EUR |  |  |  | 2015 |  |  |  | variable
|  | 13,346 |  | 245 |  |  | 13,591 |  |  |  |  |  |  |  |  |  |
Other bonds |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eni SpA |  | 1,109 |  | 3 |  |  | 1,112 |  | EUR |  |  |  | 2017 |  |  |  | 4.875
Eni SpA |  | 1,000 |  | 19 |  |  | 1,019 |  | EUR |  |  |  | 2015 |  |  |  | 4.000
Eni SpA |  | 1,000 |  | (1 | ) |  | 999 |  | EUR |  |  |  | 2015 |  |  |  | variable
Eni SpA |  | 371 |  | 2 |  |  | 373 |  | USD |  |  |  | 2020 |  |  |  | 4.150
Eni SpA |  | 289 |  | (1 | ) |  | 288 |  | USD |  |  |  | 2040 |  |  |  | 5.700
Eni SpA |  | 215 |  |  |  |  | 215 |  | EUR |  |  |  | 2017 |  |  |  | variable
Eni USA Inc |  | 329 |  | (2 | ) |  | 327 |  | USD |  |  |  | 2027 |  |  |  | 7.300
|  | 4,313 |  | 20 |  |  | 4,333 |  |  |  |  |  |  |  |  |  |
|  | 17,659 |  | 265 |  |  | 17,924 |  |  |  |  |  |  |  |  |  |

As of December 31, 2014, ordinary bonds maturing within 18 months (euro 3,816 million) were issued by Eni SpA (euro 3,585 million) and Eni Finance International SA (euro 231 million). During 2014, new bonds for euro 1,025 million were issued by Eni SpA.

The following table provides a breakdown of convertible bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2014:

(euro million) | Amount |  | Discount on bond issue and accrued expense |  | Total |  | Currency |  | Maturity |  | Rate %

Issuing entity |  |  |  |  |  |  |  |  |  |  |  |
Eni SpA |  | 1,250 |  | (3) |  | 1,247 |  | EUR |  | 2016 |  | 0.625
Eni SpA |  | 1,028 |  | (12) |  | 1,016 |  | EUR |  | 2015 |  | 0.250
|  | 2,278 |  | (15) |  | 2,263 |  |  |  |  |  |

A bond amounting to euro 1,247 million (nominal value of euro 1,250 million) is convertible into ordinary shares of Snam SpA. The underlying shares are 288.7 million ordinary shares, corresponding to the 8.25% of the current outstanding share capital of Snam at a strike price of approximately euro 4.33 a share. As of the balance sheet date, the call option was out of the money.

A bond amounting to euro 1,016 million (nominal value of euro 1,028 million) is convertible into ordinary shares of Galp Energia SGPS SA. The underlying share are approximately 66.3 million ordinary shares of Galp, corresponding to the 8% of the current outstanding share capital of Galp at a strike price of approximately euro 15.50 a share. As of the balance sheet date, the call option was out of the money.

Those convertible bonds are stated at amortized cost, while the call option embedded in the bonds is measured at fair value through profit. Changes in fair value of the shares underlying the bonds were reported through profit as opposed to equity based on the fair value option provided by IAS 39 from inception.

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The following table provides a breakdown by currency of long-term debt and its current portion and the related weighted average interest rates.

|  | Dec. 31, 2013 (euro million) |  | Average rate (%) |  | Dec. 31, 2014 (euro million) |  | Average rate (%)

Euro |  | 20,537 |  | 3.4 |  | 20,625 |  | 3.2
U.S. dollar |  | 1,668 |  | 5.4 |  | 1,744 |  | 5.4
British pound |  | 552 |  | 5.3 |  | 592 |  | 5.3
Japanese yen |  | 250 |  | 2.2 |  | 214 |  | 2.3
|  | 23,007 |  |  |  | 23,175 |  |

As of December 31, 2014, Eni had undrawn long-term committed borrowing facilities of euro 6,598 million (euro 4,719 million at December 31, 2013). Those facilities bore interest rates and charges for unutilized facilities reflecting prevailing conditions on the marketplace.

Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which euro 13.3 billion were drawn as of December 31, 2014.

The Group has the following credit ratings: (i) A and A-1, respectively for long and short-term debt assigned by Standard & Poor’s, such rating is currently under review for possible downgrade (Credit Watch Negative); and (ii) A3 and P-2 for long and short-term debt assigned by Moody’s, outlook stable. 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. On the basis of 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 and make it more likely that the credit rating of the notes or other debt instruments issued by the Company could be downgraded.

Fair value of long-term debt, including the current portion of long-term debt amounted to euro 25,364 million (euro 22,891 million at December 31, 2013):

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Ordinary bonds |  | 18,071 |  | 19,910
Convertible bonds |  | 2,188 |  | 2,344
Banks |  | 2,382 |  | 2,864
Other financial institutions |  | 250 |  | 246
|  | 22,891 |  | 25,364

Fair value was estimated by discounting the expected future cash flows at discount rates ranging from 0.2% to 2.7% (0.5% to 4.2% at December 31, 2013). The fair value hierarchy is level 2.

At December 31, 2014, 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 and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. 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

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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.

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

|  | Current |  | Non-current |  | Total |  | Current |  | Non-current |  | Total

A. | Cash and cash equivalents |  | 5,431 |  |  |  | 5,431 |  | 6,614 |  |  |  | 6,614
B. | Held-for-trading financial assets |  | 5,004 |  |  |  | 5,004 |  | 5,024 |  |  |  | 5,024
C. | Available-for-sale financial assets |  | 33 |  |  |  | 33 |  | 13 |  |  |  | 13
D. | Liquidity (A+B+C) |  | 10,468 |  |  |  | 10,468 |  | 11,651 |  |  |  | 11,651
E. | Financing receivables |  | 129 |  |  |  | 129 |  | 555 |  |  |  | 555
F. | Short-term debt towards banks |  | 306 |  |  |  | 306 |  | 435 |  |  |  | 435
G. | Long-term debt towards banks |  | 397 |  | 1,993 |  | 2,390 |  | 236 |  | 2,536 |  | 2,772
H. | Bonds |  | 1,706 |  | 18,685 |  | 20,391 |  | 3,589 |  | 16,598 |  | 20,187
I. | Short-term debt towards related parties |  | 264 |  |  |  | 264 |  | 181 |  |  |  | 181
L. | Other short-term liabilities |  | 1,983 |  |  |  | 1,983 |  | 2,100 |  |  |  | 2,100
M. | Other long-term liabilities |  | 29 |  | 197 |  | 226 |  | 34 |  | 182 |  | 216
N. | Total borrowings (F+G+H+I+L+M) |  | 4,685 |  | 20,875 |  | 25,560 |  | 6,575 |  | 19,316 |  | 25,891
O. | Net borrowings (N-D-E) |  | (5,912) |  | 20,875 |  | 14,963 |  | (5,631) |  | 19,316 |  | 13,685

Financial assets held for trading of euro 5,024 million (euro 5,004 million at December 31, 2013) were maintained by Eni SpA. For further information see note 9 – Financial assets held for trading.

Available-for-sale securities of euro 13 million (euro 33 million at December 31, 2013) were held for non-operating purposes. The Company held at the reporting date certain held-to-maturity and available-for-sale securities which were destined to operating purposes amounting to euro 320 million (euro 282 million at December 31, 2013), of which euro 244 million (euro 202 million at December 31, 2013) were held to hedge the loss reserve of Eni Insurance Ltd. Those securities are excluded from the calculation above.

Financing receivables of euro 555 million (euro 129 million at December 31, 2013) were held for non-operating purposes. The Company held at the reporting date certain financing receivables which were destined to operating purposes amounting to euro 1,262 million (euro 884 million at December 31, 2013), of which euro 811 million (euro 481 million at December 31, 2013) were in respect of financing granted to unconsolidated entities which executed capital projects and investments on behalf of Eni’s Group companies and a euro 332 million cash deposit (euro 321 million at December 31, 2013) to hedge the loss reserve of Eni Insurance Ltd. Those financing receivables are excluded from the calculation above.

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29 Provisions for contingencies

(euro million) |  | Carrying amount at Dec. 31, 2013 |  | New or increased provisions |  | Initial recognition and changes in estimates |  | Accretion discount |  | Reversal of utilized provisions |  | Reversal of unutilized provisions |  | Currency translation differences |  | Other changes |  | Carrying amount at Dec. 31, 2014

Provision for site restoration, abandonment and social projects |  | 6,899 |  |  |  | 2,087 |  | 258 |  | (358 | ) |  | (1 | ) |  | 466 |  |  | 114 |  |  | 9,465
Environmental provision |  | 2,862 |  | 206 |  |  |  | 22 |  | (242 | ) |  | (29 | ) |  | (1 | ) |  | (7 | ) |  | 2,811
Provision for legal and other proceedings |  | 858 |  | 607 |  |  |  |  |  | (137 | ) |  | (71 | ) |  | 68 |  |  | 10 |  |  | 1,335
Provision for taxes |  | 477 |  | 63 |  |  |  |  |  | (50 | ) |  | (12 | ) |  | 50 |  |  | (40 | ) |  | 488
Loss adjustments and actuarial provisions for Eni's insurance companies |  | 358 |  | 134 |  |  |  |  |  | (148 | ) |  |  |  |  |  |  |  | 24 |  |  | 368
Provision for onerous contracts |  | 372 |  | 12 |  |  |  |  |  | (87 | ) |  | (49 | ) |  | 28 |  |  | 51 |  |  | 327
Provision for redundancy incentives |  | 407 |  | 12 |  |  |  | 13 |  | (110 | ) |  | (85 | ) |  |  |  |  | (2 | ) |  | 235
Provision for green certificates |  | 255 |  | 44 |  |  |  |  |  | (73 | ) |  |  |  |  |  |  |  |  |  |  | 226
Provision for losses on investments |  | 163 |  | 11 |  |  |  |  |  |  |  |  | (6 | ) |  | 6 |  |  | (7 | ) |  | 167
Provision for long-term construction contracts |  | 83 |  | 63 |  |  |  |  |  | (48 | ) |  |  |  |  | 3 |  |  |  |  |  | 101
Provision for disposal and restructuring |  | 96 |  | 20 |  |  |  |  |  | (27 | ) |  |  |  |  | 3 |  |  | 1 |  |  | 93
Provision for OIL insurance cover |  | 93 |  | 1 |  |  |  |  |  |  |  |  | (11 | ) |  | 1 |  |  | (7 | ) |  | 77
Other (*) |  | 197 |  | 86 |  |  |  |  |  | (158 | ) |  | (23 | ) |  | 10 |  |  | 93 |  |  | 205
|  | 13,120 |  | 1,259 |  | 2,087 |  | 293 |  | (1,438 | ) |  | (287 | ) |  | 634 |  |  | 230 |  |  | 15,898

(*) |  | Each individual amount included herein was lower than euro 50 million.

Provisions for site restoration, abandonment and social projects amounted to euro 9,465 million. Those provisions comprised the discounted estimated costs that the Company expects to incur for decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration (euro 9,106 million). Initial recognition and changes in estimates amounted to euro 2,087 million and were primarily due to changes in discount rates, secondly to estimates’ revisions of decommissioning costs, and new liabilities of the year for abandonment and social projects in the Exploration & Production segment. The accretion discount recognized in the profit and loss account for euro 258 million was determined by adopting discount rates ranging from 0.6% to 5.3% (from 0.7% to 9.4% at December 31, 2013). Main expenditures associated with site restoration and decommissioning operations are expected to be incurred over a 40-year period.

Provisions for environmental risks of euro 2,811 million included the estimated costs for environmental remediation and restoration of the soil and the groundwater areas owned or under concession mostly abandoned or under renovation for which at balance sheet date there is a legal or constructive obligation for Eni to carry out the operations, including charges for strict liability related to the 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. The provision includes the estimation of the so-called “environmental damage” related to the loss of value of the areas caused by the pollution. 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, 2014, environmental provision primarily related to Syndial SpA (euro 2,300 million) and the Refining & Marketing segment (euro 385 million). Additions of euro 206 million primarily related to the Refining & Marketing segment (euro 113 million) and Syndial SpA (euro 66 million). Utilizations of euro 242 million primarily related to Refining & Marketing segment (euro 111 million) and Syndial SpA (euro 104 million).

Provisions for legal and other proceedings of euro 1,335 million comprised the expected liabilities due to failure to perform certain contractual obligations and estimated future losses on pending litigation including legal risks of liability, antitrust proceedings, administrative matters and commercial arbitration proceedings. 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 (euro 853 million) and Syndial SpA (euro 133 million). Additions and utilizations of euro 607 million and euro 137 million, respectively, mainly related to the Gas & Power segment and were recognized to take account of gas price revisions at both long-term supply and sale contracts, including the settlement of certain arbitrations. Reversals of unutilized provision of euro 71 million were primarily made by the Gas & Power segment.

Provisions for taxes of euro 488 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

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subsidiaries in the Exploration & Production segment (euro 423 million) and the Engineering & Construction segment (euro 48 million).

Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance Ltd of euro 368 million represented the estimated liabilities accrued on the basis for third parties claims. Against such liability was recorded a receivable of euro 135 million recognized towards insurance companies for reinsurance contracts.

Provisions for onerous contracts of euro 327 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 a re-gasification project and on an unutilized infrastructure for gas transportation.

Provisions for redundancy incentives of euro 235 million were recognized due to a restructuring program involving the Italian personnel for the period 2010-2011 and 2013-2014 in compliance with Law No. 223/1991. Reversals of unutilized provision were mainly due to lower costs incurred as a consequence of the personnel who joined the program 2013-2014 and the revision of the estimates for the program 2010-2011.

Provisions for green certificates of euro 226 million included additional charges that electric power producers must sustain for using non-renewable sources of energy.

Provisions for losses on investments of euro 167 million were made with respect to certain investees for which expected or incurred losses exceeded carrying amounts.

Provisions for long-term construction contracts of euro 101 million related to the Engineering & Construction segment.

Provisions for disposal and restructuring of euro 93 million essentially related to the Versalis segment (euro 59 million) and Syndial SpA (euro 22 million).

Provisions for the OIL mutual insurance scheme of euro 77 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.

30 Provisions for employee benefits

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

TFR |  | 350 |  | 376
Foreign defined benefit plans |  | 615 |  | 572
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans |  | 136 |  | 174
Other long-term benefit plans |  | 178 |  | 191
|  | 1,279 |  | 1,313

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.

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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 and jubilee awards. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses which 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.

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

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Other long-term benefit plans |  | Total |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Other long-term benefit plans |  | Total

Present value of benefit liabilities at beginning of year |  | 357 |  |  | 1,320 |  |  | 143 |  |  | 206 |  |  | 2,026 |  |  | 350 |  |  | 1,257 |  |  | 136 |  |  | 178 |  |  | 1,921 |
Current cost |  |  |  |  | 58 |  |  | 3 |  |  | 48 |  |  | 109 |  |  |  |  |  | 52 |  |  | 3 |  |  | 47 |  |  | 102 |
Interest cost |  | 11 |  |  | 46 |  |  | 4 |  |  | 3 |  |  | 64 |  |  | 10 |  |  | 47 |  |  | 5 |  |  | 3 |  |  | 65 |
Remeasurements: |  | (5 | ) |  | (51 | ) |  | (7 | ) |  | (25 | ) |  | (88 | ) |  | 36 |  |  | 48 |  |  | 16 |  |  | (1 | ) |  | 99 |
- actuarial (gains) losses due to changes in demographic assumptions |  | (3 | ) |  | 6 |  |  | (4 | ) |  | 1 |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |
- actuarial (gains) losses due to changes in financial assumptions |  |  |  |  | (45 | ) |  | (2 | ) |  | (21 | ) |  | (68 | ) |  | 43 |  |  | 57 |  |  | 18 |  |  | 5 |  |  | 123 |
- experience (gains) losses |  | (2 | ) |  | (12 | ) |  | (1 | ) |  | (5 | ) |  | (20 | ) |  | (7 | ) |  | (10 | ) |  | (2 | ) |  | (6 | ) |  | (25 | )
Past service cost and (gains) losses settlements |  |  |  |  | 5 |  |  |  |  |  | (2 | ) |  | 3 |  |  |  |  |  | (4 | ) |  |  |  |  | 3 |  |  | (1 | )
Plan contributions: |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |
- employee contributions |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |
Benefits paid |  | (14 | ) |  | (34 | ) |  | (7 | ) |  | (48 | ) |  | (103 | ) |  | (19 | ) |  | (46 | ) |  | (7 | ) |  | (51 | ) |  | (123 | )
Changes in the scope of consolidation |  | 1 |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  | 1 |  |  |  |  |  |  |  |  |  |  |  | 1 |
Currency translation differences and other changes |  |  |  |  | (88 | ) |  |  |  |  | (4 | ) |  | (92 | ) |  | (2 | ) |  | (73 | ) |  | 21 |  |  | 12 |  |  | (42 | )
Present value of benefit liabilities at end of year (a) |  | 350 |  |  | 1,257 |  |  | 136 |  |  | 178 |  |  | 1,921 |  |  | 376 |  |  | 1,282 |  |  | 174 |  |  | 191 |  |  | 2,023 |
Plan assets at beginning of year |  |  |  |  | 619 |  |  |  |  |  |  |  |  | 619 |  |  |  |  |  | 642 |  |  |  |  |  |  |  |  | 642 |
Interest income |  |  |  |  | 22 |  |  |  |  |  |  |  |  | 22 |  |  |  |  |  | 26 |  |  |  |  |  |  |  |  | 26 |
Return on plan assets |  |  |  |  | 2 |  |  |  |  |  |  |  |  | 2 |  |  |  |  |  | 18 |  |  |  |  |  |  |  |  | 18 |
Past service cost and (gains) losses settlements |  |  |  |  | (1 | ) |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Administration expenses paid |  |  |  |  | (1 | ) |  |  |  |  |  |  |  | (1 | ) |  |  |  |  | (1 | ) |  |  |  |  |  |  |  | (1 | )
Plan contributions: |  |  |  |  | 39 |  |  |  |  |  |  |  |  | 39 |  |  |  |  |  | 35 |  |  |  |  |  |  |  |  | 35 |
- employee contributions |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 1 |
- employer contributions |  |  |  |  | 38 |  |  |  |  |  |  |  |  | 38 |  |  |  |  |  | 34 |  |  |  |  |  |  |  |  | 34 |
Benefits paid |  |  |  |  | (16 | ) |  |  |  |  |  |  |  | (16 | ) |  |  |  |  | (25 | ) |  |  |  |  |  |  |  | (25 | )
Currency translation differences and other changes |  |  |  |  | (22 | ) |  |  |  |  |  |  |  | (22 | ) |  |  |  |  | 15 |  |  |  |  |  |  |  |  | 15 |
Plan assets at end of year (b) |  |  |  |  | 642 |  |  |  |  |  |  |  |  | 642 |  |  |  |  |  | 710 |  |  |  |  |  |  |  |  | 710 |
Net liability recognized at end of year (a-b) |  | 350 |  |  | 615 |  |  | 136 |  |  | 178 |  |  | 1,279 |  |  | 376 |  |  | 572 |  |  | 174 |  |  | 191 |  |  | 1,313 |

Foreign defined benefit plans amounting to euro 572 million (euro 615 million at December 31, 2013) primarily related to pension plans for euro 381 million (euro 424 million at December 31, 2013).

Net liability relating to foreign defined benefit plans included the liability attributable to joint venture partners operating in exploration and production activities of euro 207 million (euro 264 million at December 31, 2013). Eni recorded a receivable for an amount equivalent to such liability.

Other long-term employee benefit plans of euro 191 million (euro 178 million at December 31, 2013) related to deferred monetary incentive plans for euro 83 million (euro 86 million at December 31, 2013), jubilee awards for euro 47 million (euro 48 million at December 31, 2013), the long-term incentive plan for euro 12 million (euro 8 million at December 31, 2013) and other foreign long-term plans for euro 49 million (euro 36 million at December 31, 2013).

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Costs charged to the profit and loss account consisted of the following:

(euro million) |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Other long-term benefit plans |  | Total

2013 |  |  |  |  |  |  |  |  |  |  |  |  |
Current cost |  |  |  | 58 |  |  | 3 |  | 48 |  |  | 109 |
Past service cost and (gains) losses on settlements |  |  |  | 6 |  |  |  |  | (2 | ) |  | 4 |
Interest cost (income), net: |  |  |  |  |  |  |  |  |  |  |  |  |
- interest cost on liabilities |  | 11 |  | 46 |  |  | 4 |  | 3 |  |  | 64 |
- interest income on plan assets |  |  |  | (22 | ) |  |  |  |  |  |  | (22 | )
Total interest cost (income), net |  | 11 |  | 24 |  |  | 4 |  | 3 |  |  | 42 |
- of which recognized in "Payroll and related cost" |  |  |  |  |  |  |  |  | 3 |  |  | 3 |
- of which recognized in "Financial income (expense)" |  | 11 |  | 24 |  |  | 4 |  |  |  |  | 39 |
Remeasurements for long-term plans |  |  |  |  |  |  |  |  | (25 | ) |  | (25 | )
Other costs/Administration expenses paid |  |  |  | 1 |  |  |  |  |  |  |  | 1 |
Total |  | 11 |  | 89 |  |  | 7 |  | 24 |  |  | 131 |
- of which recognized in "Payroll and related cost" |  |  |  | 65 |  |  | 3 |  | 24 |  |  | 92 |
- of which recognized in "Financial income (expense)" |  | 11 |  | 24 |  |  | 4 |  |  |  |  | 39 |
2014 |  |  |  |  |  |  |  |  |  |  |  |  |
Current cost |  |  |  | 52 |  |  | 3 |  | 47 |  |  | 102 |
Past service cost and (gains) losses on settlements |  |  |  | (4 | ) |  |  |  | 3 |  |  | (1 | )
Interest cost (income), net: |  |  |  |  |  |  |  |  |  |  |  |  |
- interest cost on liabilities |  | 10 |  | 47 |  |  | 5 |  | 3 |  |  | 65 |
- interest income on plan assets |  |  |  | (26 | ) |  |  |  |  |  |  | (26 | )
Total interest cost (income), net |  | 10 |  | 21 |  |  | 5 |  | 3 |  |  | 39 |
- of which recognized in "Payroll and related cost" |  |  |  |  |  |  |  |  | 3 |  |  | 3 |
- of which recognized in "Financial income (expense)" |  | 10 |  | 21 |  |  | 5 |  |  |  |  | 36 |
Remeasurements for long-term plans |  |  |  |  |  |  |  |  | (1 | ) |  | (1 | )
Other costs/Administration expenses paid |  |  |  | 1 |  |  |  |  |  |  |  | 1 |
Total |  | 10 |  | 70 |  |  | 8 |  | 52 |  |  | 140 |
- of which recognized in "Payroll and related cost" |  |  |  | 49 |  |  | 3 |  | 52 |  |  | 104 |
- of which recognized in "Financial income (expense)" |  | 10 |  | 21 |  |  | 5 |  |  |  |  | 36 |

Costs recognized in other comprehensive income consisted of the following:

|  | 2013 |  | 2014

(euro million) |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Total |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Total

Remeasurements |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Actuarial (gains)/losses due to changes in demographic assumptions |  | (3 | ) |  | 6 |  |  | (4 | ) |  | (1 | ) |  |  |  |  | 1 |  |  |  |  |  | 1 |
Actuarial (gains)/losses due to changes in financial assumptions |  |  |  |  | (45 | ) |  | (2 | ) |  | (47 | ) |  | 43 |  |  | 57 |  |  | 18 |  |  | 118 |
Experience (gains) losses |  | (2 | ) |  | (12 | ) |  | (1 | ) |  | (15 | ) |  | (7 | ) |  | (10 | ) |  | (2 | ) |  | (19 | )
Return on plan assets |  |  |  |  | (2 | ) |  |  |  |  | (2 | ) |  |  |  |  | (18 | ) |  |  |  |  | (18 | )
|  | (5 | ) |  | (53 | ) |  | (7 | ) |  | (65 | ) |  | 36 |  |  | 30 |  |  | 16 |  |  | 82 |

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Plan assets consisted of the following:

(euro million) |  | Cash and cash equivalents |  | Equity securities |  | Debt securities |  | Real estate |  | Derivatives |  | Investment funds |  | Assets held by insurance company |  | Other |  | Total

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Plan assets with a quoted market price |  | 20 |  | 88 |  | 412 |  | 9 |  | 5 |  | 2 |  | 1 |  | 85 |  | 622
Plan assets without a quoted market price |  | 2 |  |  |  | 7 |  | 2 |  |  |  | 1 |  | 5 |  | 3 |  | 20
|  | 22 |  | 88 |  | 419 |  | 11 |  | 5 |  | 3 |  | 6 |  | 88 |  | 642
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Plan assets with a quoted market price |  | 114 |  | 98 |  | 393 |  | 9 |  | 1 |  | 3 |  | 8 |  | 70 |  | 696
Plan assets without a quoted market price |  | 2 |  |  |  | 1 |  | 1 |  |  |  |  |  | 7 |  | 3 |  | 14
|  | 116 |  | 98 |  | 394 |  | 10 |  | 1 |  | 3 |  | 15 |  | 73 |  | 710

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 2015 consisted of the following:

|  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Other long-term benefit plans

2013 |  |  |  |  |  |  |  |  |  |
Discount rate |  | (%) |  | 3.0 |  | 2.1-13.5 |  | 3.0 |  | 1.1-3.0
Rate of compensation increase |  | (%) |  | 3.0 |  | 2.0-14.0 |  |  |  |
Rate of price inflation |  | (%) |  | 2.0 |  | 0.6-11.0 |  | 2.0 |  | 2.0
Life expectations on retirement at age 65 |  | (years) |  |  |  | 15-24 |  | 24 |  |
2014 |  |  |  |  |  |  |  |  |  |
Discount rate |  | (%) |  | 2.0 |  | 1.2-15.0 |  | 2.0 |  | 0.5-2.0
Rate of compensation increase |  | (%) |  | 3.0 |  | 2.0-14.0 |  |  |  |
Rate of price inflation |  | (%) |  | 2.0 |  | 0.6-11.1 |  | 2.0 |  | 2.0
Life expectations on retirement at age 65 |  | (years) |  |  |  | 13-24 |  | 24 |  |

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

|  | Euro area |  | Rest of Europe |  | Africa |  | Other areas |  | Foreign defined benefit plans

2013 |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  | (%) |  | 2.9-3.3 |  | 2.1-4.4 |  | 3.5-13.5 |  | 2.5-7.8 |  | 2.1-13.5
Rate of compensation increase |  | (%) |  | 2.0-3.1 |  | 2.5-4.9 |  | 5.0-14.0 |  | 5.0-10.0 |  | 2.0-14.0
Rate of price inflation |  | (%) |  | 2.0 |  | 0.6-3.4 |  | 3.5-11.0 |  | 3.0-5.5 |  | 0.6-11.0
Life expectations on retirement at age 65 |  | (years) |  | 21 |  | 22-24 |  | 15 |  |  |  | 15-24
2014 |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  | (%) |  | 2.0 |  | 1.2-3.6 |  | 3.5-15.0 |  | 2.6-13.0 |  | 1.2-15.0
Rate of compensation increase |  | (%) |  | 2.0-3.2 |  | 2.5-4.6 |  | 5.0-14.0 |  | 5.0-13.0 |  | 2.0-14.0
Rate of price inflation |  | (%) |  | 2.0 |  | 0.6-3.0 |  | 3.5-11.1 |  | 3.0-8.2 |  | 0.6-11.1
Life expectations on retirement at age 65 |  | (years) |  | 21 |  | 22-24 |  | 13-15 |  |  |  | 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 was determined by considering the long-term forecasts issued by national or international banks.

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The effects of a possible change in the main actuarial assumptions at the end of the year are listed below:

(euro million) |  | Discount rate |  | Rate of price inflation |  | Rate of increases in pensionable salaries |  | Healthcare cost trend rate |  | Rate of increases to pensions in payment

|  | 0.5% increase |  | 0.5% decrease |  | 0.5% increase |  | 0.5% increase |  | 0.5% increase |  | 0.5% increase

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |
Effect on DBO |  |  |  |  |  |  |  |  |  |  |  |
TFR |  | (20) |  | 23 |  | 15 |  |  |  |  |  |
Foreign defined benefit plans |  | (79) |  | 80 |  | 38 |  | 26 |  |  |  | 28
FISDE and other foreign medical plans |  | (8) |  | 9 |  |  |  |  |  | 9 |  |
Other long-term benefit plans |  | (3) |  | 3 |  | 1 |  |  |  |  |  |
December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |
Effect on DBO |  |  |  |  |  |  |  |  |  |  |  |
TFR |  | (22) |  | 24 |  | 16 |  |  |  |  |  |
Foreign defined benefit plans |  | (83) |  | 88 |  | 42 |  | 32 |  |  |  | 48
FISDE and other foreign medical plans |  | (10) |  | 11 |  |  |  |  |  | 11 |  |
Other long-term benefit plans |  | (4) |  | 4 |  | 3 |  |  |  |  |  |

The sensitivity analysis was performed on the basis of 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 euro 119 million, of which euro 67 million related to defined benefit plans.

The following is an analysis by maturity date of the liabilities for employee benefit plans:

(euro million) |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Other long-term benefits

December 31, 2013 |  |  |  |  |  |  |  |
2014 |  | 7 |  | 36 |  | 7 |  | 44
2015 |  | 6 |  | 40 |  | 7 |  | 46
2016 |  | 7 |  | 44 |  | 7 |  | 49
2017 |  | 9 |  | 41 |  | 7 |  | 5
2018 |  | 12 |  | 59 |  | 7 |  | 3
2019 and thereafter |  | 309 |  | 395 |  | 101 |  | 54
December 31, 2014 |  |  |  |  |  |  |  |
2015 |  | 6 |  | 46 |  | 7 |  | 52
2016 |  | 6 |  | 42 |  | 7 |  | 42
2017 |  | 9 |  | 45 |  | 7 |  | 48
2018 |  | 12 |  | 56 |  | 7 |  | 4
2019 |  | 15 |  | 50 |  | 7 |  | 4
2020 and thereafter |  | 328 |  | 335 |  | 138 |  | 67

The weighted average duration of the liabilities for employee benefit plans was the following:

(years) |  | TFR |  | Foreign defined benefit plans |  | FISDE and other foreign medical plans |  | Other long-term benefits

2013 |  |  |  |  |  |  |  |
Weighted average duration |  | 12.7 |  | 18.6 |  | 13.1 |  | 4.4
2014 |  |  |  |  |  |  |  |
Weighted average duration |  | 13.3 |  | 18.1 |  | 14.3 |  | 4.6

Transactions with related parties are described in note 44 – Transactions with related parties.

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31 Deferred tax liabilities
Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for euro 3,915 million (euro 3,562 million at December 31, 2013).

(euro million) | Amount at Dec. 31, 2013 |  | Additions |  | Deductions |  | Currency translation differences |  | Other changes |  | Amount at Dec. 31, 2014

| 6,750 |  | 1,309 |  | (769) |  | 918 |  | (361) |  | 7,847

Deferred tax assets and liabilities consisted of the following:

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Deferred tax liabilities |  | 10,312 |  |  | 11,762 |
Deferred tax assets available for offset |  | (3,562 | ) |  | (3,915 | )
|  | 6,750 |  |  | 7,847 |
Deferred tax assets not available for offset |  | (4,658 | ) |  | (5,231 | )
Net deferred tax liabilities |  | 2,092 |  |  | 2,616 |

Net deferred tax liabilities of euro 2,616 million (euro 2,092 million at December 31, 2013) 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 assets for euro 100 million); (ii) the revaluation of defined benefit plans (deferred tax assets for euro 36 million); and (iii) the fair value measurement of available-for-sale securities (deferred tax liabilities for euro 2 million).

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

(euro million) | Carrying amount at Dec. 31, 2013 |  | Additions |  | Deductions |  | Currency translation differences |  | Other changes |  | Carrying amount at Dec. 31, 2014

Deferred tax liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accelerated tax depreciation |  | 7,625 |  |  | 339 |  |  | (214 | ) |  | 725 |  |  | (155 | ) |  | 8,320 |
Difference between the fair value and the carrying amount of assets acquired following business combinations |  | 1,295 |  |  | 7 |  |  | (38 | ) |  | 166 |  |  | 50 |  |  | 1,480 |
Site restoration and abandonment (tangible assets) |  | 387 |  |  | 416 |  |  | (40 | ) |  | (30 | ) |  | 80 |  |  | 813 |
Application of the weighted average cost method in evaluation of inventories |  | 111 |  |  | 3 |  |  | (92 | ) |  | 3 |  |  | 28 |  |  | 53 |
Capitalized interest expense |  | 14 |  |  |  |  |  | (13 | ) |  | 1 |  |  |  |  |  | 2 |
Other |  | 880 |  |  | 544 |  |  | (372 | ) |  | 53 |  |  | (11 | ) |  | 1,094 |
|  | 10,312 |  |  | 1,309 |  |  | (769 | ) |  | 918 |  |  | (8 | ) |  | 11,762 |
Deferred tax assets, gross |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Carry-forward tax losses |  | (2,346 | ) |  | (687 | ) |  | 141 |  |  | (104 | ) |  | 74 |  |  | (2,922 | )
Site restoration and abandonment (provisions for contingencies) |  | (1,896 | ) |  | (238 | ) |  | 25 |  |  | (170 | ) |  | (93 | ) |  | (2,372 | )
Accruals for impairment losses and provisions for contingencies |  | (1,692 | ) |  | (295 | ) |  | 288 |  |  | (2 | ) |  | 10 |  |  | (1,691 | )
Timing differences on depreciation and amortization |  | (1,623 | ) |  | (334 | ) |  | 70 |  |  | (205 | ) |  | (11 | ) |  | (2,103 | )
Impairment losses |  | (1,190 | ) |  | (59 | ) |  | 181 |  |  | 2 |  |  | 4 |  |  | (1,062 | )
Unrealized intercompany profits |  | (468 | ) |  | 15 |  |  | 129 |  |  | (3 | ) |  | 18 |  |  | (309 | )
Other |  | (1,575 | ) |  | (664 | ) |  | 421 |  |  | (112 | ) |  | (57 | ) |  | (1,987 | )
|  | (10,790 | ) |  | (2,262 | ) |  | 1,255 |  |  | (594 | ) |  | (55 | ) |  | (12,446 | )
Impairments of deferred tax assets |  | 2,570 |  |  | 677 |  |  | (2 | ) |  | 54 |  |  | 1 |  |  | 3,300 |
Deferred tax assets, net |  | (8,220 | ) |  | (1,585 | ) |  | 1,253 |  |  | (540 | ) |  | (54 | ) |  | (9,146 | )
Net deferred tax liabilities |  | 2,092 |  |  | (276 | ) |  | 484 |  |  | 378 |  |  | (62 | ) |  | 2,616 |

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Italian taxation law allows the carry-forward tax losses indefinitely. Foreign taxation laws generally allow the carry-forward tax losses over a period longer than five years, and in many cases, indefinitely. An average tax rate of 27.5% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses which will be used in future years to offset the expected taxable profit. The corresponding rate for foreign subsidiaries was 30.7%.

Carry-forward tax losses amounted to euro 10,294 million and can be used indefinitely for euro 8,875 million. Carry-forward tax losses regarded Italian companies for euro 6,140 million and foreign companies for euro 4,154 million. Carry-forward tax losses amounted to euro 8,305 million which are likely to be utilized against future taxable profit and were in respect of Italian companies for euro 5,682 million and foreign subsidiaries for euro 2,623 million. Deferred tax assets recognized on these losses amounted to euro 1,563 million and euro 804 million, respectively.

32 Other non-current liabilities

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Fair value of non-hedging derivatives |  | 282 |  | 143
Fair value of cash flow hedge derivatives |  | 1 |  |
Current income tax liabilities |  | 20 |  | 20
Other payables towards tax authorities |  | 2 |  | 5
Other payables |  | 74 |  | 104
Other liabilities |  | 1,880 |  | 2,013
|  | 2,259 |  | 2,285

Derivative fair values were estimated on the basis of market prices provided by primary info-provider, or alternatively, appropriate valuation techniques commonly used in the marketplace.

The fair value of non-hedging derivative contracts and is presented below:

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Fair value |  | Purchase commitments |  | Sale commitments |  | Fair value |  | Purchase commitments |  | Sale commitments

Derivatives on exchange rate |  |  |  |  |  |  |  |  |  |  |  |
Currency swap |  | 53 |  | 1,075 |  | 130 |  | 55 |  | 49 |  | 608
Outright |  | 36 |  | 878 |  |  |  |  |  |  |  |
Interest currency swap |  | 3 |  |  |  | 74 |  | 1 |  | 128 |  |
|  | 92 |  | 1,953 |  | 204 |  | 56 |  | 177 |  | 608
Derivatives on interest rate |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  | 40 |  | 50 |  | 390 |  | 28 |  |  |  | 272
|  | 40 |  | 50 |  | 390 |  | 28 |  |  |  | 272
Derivatives on commodities |  |  |  |  |  |  |  |  |  |  |  |
Over the counter |  | 23 |  | 31 |  | 159 |  |  |  |  |  |
|  | 23 |  | 31 |  | 159 |  |  |  |  |  |
Options embedded in convertible bonds |  | 127 |  |  |  |  |  | 59 |  |  |  |
|  | 282 |  | 2,034 |  | 753 |  | 143 |  | 177 |  | 880

Fair value of non-hedging derivatives of euro 143 million (euro 282 million at December 31, 2013) consisted of: (i) euro 84 million (euro 155 million at December 31, 2013) of derivatives that lacked the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net business exposures to foreign currency exchange rates, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; (ii) euro 59 million related to the call option embedded in the bonds convertible into Snam SpA ordinary shares (euro 127 million at December 31, 2013, of which euro 81 million related to Snam SpA and euro 46 million related to Galp Energia SGPS SA) (further information is disclosed in note 28 – Long-term debt and current portion of long-term debt).

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Fair value of cash flow hedge derivatives amounting to euro 1 million at December 31, 2013 pertained to hedges entered by the Gas & Power segment. Those derivatives were designated to hedge exchange rate and commodity risk exposures as described in note 15 – Other current assets. Fair value of contracts expiring beyond 2015 is disclosed in note 22 – Other non-current receivables; fair value of contracts expiring by 2015 is disclosed in note 27 – Other current liabilities and in note 15 – Other current assets. The effects of fair value measurement of cash flow hedge derivatives are disclosed in note 34 – Shareholders’ equity and in note 38 – Operating expenses. The nominal value of these derivatives referred to purchase and sale commitments at December 31, 2013 amounted to euro 1 million and euro 24 million, respectively.

Information on the hedged risks and the hedging policies is shown in note 36 – Guarantees, commitments and risks - Risk factors.

Other liabilities of euro 2,013 million (euro 1,880 million at December 31, 2013) included: (i) advances received from Suez following a long-term agreement for supplying natural gas and electricity of euro 812 million (euro 876 million at December 31, 2013), the current portion is indicated in note 27 – Other current liabilities; and (ii) advances relating to amounts of gas of euro 281 million (euro 149 million at December 31, 2013) which were collected for amounts lower than the minimum take for the year by certain of Eni’s clients, reflecting take-or-pay clauses contained in the long-term sale contracts. Management believes that the underlying gas volumes will be collected beyond the twelve-month time horizon.

Transactions with related parties are described in note 44 – Transactions with related parties.

33 Assets held for sale and liabilities directly associated with assets held for sale
Assets held for sale and liabilities directly associated with assets held for sale of euro 456 million and euro 165 million, respectively, related to: (i) the sale of 100% stake of the subsidiaries Eni Ceská Republika Sro, Eni Slovensko Spol Sro and Eni Romania Srl, companies operating in the Refining & Marketing segment, with activities in Czech Republic, Slovakia and Romania, respectively and the sale of 32.445% stake (entire stake own) in Ceská Rafinérská AS (CRC), a refining company in the Czech Republic. These three subsidiaries and the investment in CRC were classified as assets held for sale following a preliminary agreement signed by Eni with MOL Group, a Hungarian oil&gas company in May 2014. The other partner of CRC, Unipetrol, exercised its pre-emptive right at the same conditions as agreed with MOL. The completion of these agreements is subject to certain conditions, including prior approval by the competent European Antitrust Authorities. The carrying amount of assets held for sale and liabilities directly associated with assets held for sale was aligned at the lower between the book value and the expected sale price and amounted to euro 367 million (of which euro 207 million of current assets) and euro 165 million (of which euro 148 million of current liabilities), respectively. Eni will continue to operate in those countries through the wholesale marketing of lubricants; (ii) the sale of a 20% stake (matching Eni’s entire stake) in Fertilizantes Nitrogenados de Oriente CEC and Fertilizantes Nitrogenados de Oriente SA, companies operating in the production of fertilizers in Venezuela. The carrying amount of the investments amounted to euro 69 million; and (iii) 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 (matching Eni’s entire stake), 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), companies operating in the distribution and commercialization of natural gas in Argentina. The carrying amount of the investments amounted to euro 10 million.

During the course of 2014, Eni closed the sale of its interest in Artic Russia BV for a carrying amount of euro 2,131 million.

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34 Shareholders’ equity
Non-controlling interest

(euro million) |  | Net profit |  | Shareholders’ equity

|  | 2013 |  | 2014 |  | Dec. 31, 2013 |  | Dec. 31, 2014

Saipem SpA |  | (190) |  | (345) |  | 2,748 |  | 2,398
Others |  | (11) |  | (96) |  | 91 |  | 57
|  | (201) |  | (441) |  | 2,839 |  | 2,455

Eni shareholders’ equity

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Share capital |  | 4,005 |  |  | 4,005 |
Legal reserve |  | 959 |  |  | 959 |
Reserve for treasury shares |  | 6,201 |  |  | 6,201 |
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect |  | (154 | ) |  | (284 | )
Reserve related to the fair value of available-for-sale securities net of the tax effect |  | 81 |  |  | 11 |
Reserve related to the defined benefit plans net of tax effect |  | (72 | ) |  | (122 | )
Other reserves |  | 296 |  |  | 207 |
Cumulative currency translation differences |  | (698 | ) |  | 4,020 |
Treasury shares |  | (201 | ) |  | (581 | )
Retained earnings |  | 44,626 |  |  | 46,067 |
Interim dividend |  | (1,993 | ) |  | (2,020 | )
Net profit for the year |  | 5,160 |  |  | 1,291 |
|  | 58,210 |  |  | 59,754 |

Share capital
At December 31, 2014, the parent company’s issued share capital consisted of euro 4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (same amounts as of December 31, 2013).

On May 8, 2014, Eni’s Shareholders’ Meeting declared: (i) to distribute a dividend of euro 0.55 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2013 dividend of euro 1.10 per share, of which euro 0.55 per share paid as interim dividend. The balance was paid on May 22, 2014, to shareholders on the register on May 19, 2014, record date on May 21, 2014; (ii) to cancel, for the portion not yet implemented as of the date of the Shareholders’ Meeting, the authorization for the Board of Directors to acquire treasury shares as resolved at the Shareholders’ Meeting of May 10, 2013; and (iii) to authorize the Board of Directors to purchase on the Mercato Telematico Azionario – in one or more transactions and in any case within 18 months from the date of the resolution – up to a maximum number of 363,000,000 ordinary Eni shares, for a price of no less than euro 1.102 and not more than the official price reported by the Borsa Italiana for the shares on the trading day prior to each individual transaction, plus 5%, and in any case up to a total amount of euro 6,000 million, in accordance with the procedures established in the Rules of the Markets organized and managed by Borsa Italiana SpA. In order to respect the limit envisaged in the third paragraph of Article 2357 of the Italian Civil Code, the number of shares to be acquired and the relative amount shall take into account the number and amount of Eni shares already held in the portfolio.

Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

Reserve for treasury shares
The reserve for treasury shares represents the reserve which was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings. The amount of euro 6,201 million (same amount as of December 31, 2013) included the book value of treasury shares purchased of euro 581 million.

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Reserves related to the fair value measurement of cash flow hedging derivatives, available-for-sale financial assets and defined benefit plans
The measurement at fair value of cash flow hedging derivatives, available-for-sale financial instruments and defined benefit plans, net of the related tax effect, consisted of the following:

|  | Cash flow hedge derivatives |  | Available-for-sale financial instruments |  | Defined benefit plans |  | Total

(euro million) |  | Gross reserve |  | Deferred tax liabilities |  | Net reserve |  | Gross reserve |  | Deferred tax liabilities |  | Net reserve |  | Gross reserve |  | Deferred tax liabilities |  | Net reserve |  | Gross reserve |  | Deferred tax liabilities |  | Net reserve

Reserve as of December 31, 2012 |  | (25 | ) |  | 9 |  |  | (16 | ) |  | 148 |  |  | (4 | ) |  | 144 |  |  | (138 | ) |  | 50 |  |  | (88 | ) |  | (15 | ) |  | 55 |  |  | 40 |
Changes of the year 2013 |  | (301 | ) |  | 93 |  |  | (208 | ) |  | 9 |  |  |  |  |  | 9 |  |  | 55 |  |  | (38 | ) |  | 17 |  |  | (237 | ) |  | 55 |  |  | (182 | )
Foreign currency translation differences |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2 | ) |  | 1 |  |  | (1 | ) |  | (2 | ) |  | 1 |  |  | (1 | )
Amount recognized in the profit and loss account |  | 102 |  |  | (32 | ) |  | 70 |  |  | (74 | ) |  | 2 |  |  | (72 | ) |  |  |  |  |  |  |  |  |  |  | 28 |  |  | (30 | ) |  | (2 | )
Reserve as of December 31, 2013 |  | (224 | ) |  | 70 |  |  | (154 | ) |  | 83 |  |  | (2 | ) |  | 81 |  |  | (85 | ) |  | 13 |  |  | (72 | ) |  | (226 | ) |  | 81 |  |  | (145 | )
Changes of the year 2014 |  | (69 | ) |  | 12 |  |  | (57 | ) |  | 7 |  |  | (1 | ) |  | 6 |  |  | (68 | ) |  | 19 |  |  | (49 | ) |  | (130 | ) |  | 30 |  |  | (100 | )
Foreign currency translation differences |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  | (1 | ) |  | (1 | ) |  |  |  |  | (1 | )
Amount recognized in the profit and loss account |  | (91 | ) |  | 18 |  |  | (73 | ) |  | (77 | ) |  | 1 |  |  | (76 | ) |  |  |  |  |  |  |  |  |  |  | (168 | ) |  | 19 |  |  | (149 | )
Reserve as of December 31, 2014 |  | (384 | ) |  | 100 |  |  | (284 | ) |  | 13 |  |  | (2 | ) |  | 11 |  |  | (154 | ) |  | 32 |  |  | (122 | ) |  | (525 | ) |  | 130 |  |  | (395 | )

Reserve for available-for-sale financial instruments net of tax effect of euro 11 million (euro 5 million at December 31, 2013) related to the fair value measurement of securities. The amount of the reserve as of December 31, 2013 of euro 76 million relating to the fair value measurement of Galp Energia SGPS SA was reversed in 2014 to the profit and loss account following the sale of 8.15% share capital (further information is disclosed in note 19 – Investments).

Negative reserve for defined-benefit plans of euro 122 million (negative for euro 72 million at December 31, 2013), net of the related tax effect, related to investments accounted for under the equity method for euro 1 million (negative for euro 1 million at December 31, 2013).

Other reserves Other reserves amounted to euro 207 million (euro 296 million at December 31, 2013) and related to:

• |  | a reserve of euro 247 million represented 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, 2013);

• |  | a reserve of euro 63 million deriving from Eni SpA’s equity (euro 157 million at December 31, 2013);
• |  | a reserve of euro 18 million related to the sale of treasury shares to Saipem managers upon exercise of stock options (same amount as of December 31, 2013);
• |  | a reserve of euro 5 million represented the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 47.60% in the subsidiary Tigáz Zrt (same amount as of December 31, 2013);
• |  | a negative reserve of euro 2 million related to the share of "Other comprehensive income" on equity-accounted entities (a negative reserve of euro 7 million at December 31, 2013); and
• |  | a negative reserve of euro 124 million represented the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 45.97% in the subsidiary Altergaz SA, now Eni Gas & Power France SA (same amount as of December 31, 2013).

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

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Treasury shares
A total of 33,045,197 Eni’s ordinary shares (11,388,287 at December 31, 2013) were held in treasury for a total cost of euro 581 million (euro 201 million at December 31, 2013).

Interim dividend
The interim dividend for the year 2014 amounted to euro 2,020 million corresponding to euro 0.56 per share, as resolved by the Board of Directors on September 17, 2014, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 22, 2014.

Distributable reserves
At December 31, 2014, Eni shareholders’ equity included distributable reserves of approximately euro 49.3 billion.

Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity

|  | Net profit |  | Shareholders’ equity

(euro million) |  | 2013 |  | 2014 |  | Dec. 31, 2013 |  | Dec. 31, 2014

As recorded in Eni SpA's Financial Statements |  | 4,414 |  |  | 4,455 |  |  | 40,743 |  |  | 40,529 |
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company |  | 1,519 |  |  | (3,548 | ) |  | 21,093 |  |  | 22,913 |
Consolidation adjustments: |  |  |  |  |  |  |  |  |  |  |  |
- difference between purchase cost and underlying carrying amounts of net equity |  | (499 | ) |  | (16 | ) |  | 324 |  |  | 383 |
- adjustments to comply with Group account policies |  | (256 | ) |  | (573 | ) |  | 948 |  |  | (44 | )
- elimination of unrealized intercompany profits |  | 218 |  |  | 770 |  |  | (2,366 | ) |  | (1,604 | )
- deferred taxation |  | (440 | ) |  | (238 | ) |  | 295 |  |  | 18 |
- other adjustments |  | 3 |  |  |  |  |  | 12 |  |  | 14 |
|  | 4,959 |  |  | 850 |  |  | 61,049 |  |  | 62,209 |
Non-controlling interest |  | 201 |  |  | 441 |  |  | (2,839 | ) |  | (2,455 | )
As recorded in Consolidated Financial Statements |  | 5,160 |  |  | 1,291 |  |  | 58,210 |  |  | 59,754 |

35 Other information
Main acquisitions

Acam Clienti SpA
In 2014, Eni purchased a 51% share in the company Acam Clienti SpA. The company operates in the distribution and commercialization of natural gas primarily in the province of La Spezia. Following the acquisition, Eni now owns the 100% stake of the company. The allocation to assets and liabilities of the total value of the investment for euro 30 million was made on a definitive basis.

Liverpool Bay Ltd
In 2014, Eni purchased a 100% share in the company Liverpool Bay Ltd which owns a 46.1% interest in the Liverpool Bay oil and gas field. This acquisition does not represent a step acquisition as Eni, already owned a 53.9% of the field through the companies Eni ULX Ltd and Eni AEP Ltd. Following the acquisition Eni now owns the 100% of the field and acquired the operatorship. The allocation to assets and liabilities of the total value of the investment for euro 21 million was made on a definitive basis.

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The final allocation of the purchase costs is disclosed below:

|  | Acam Clienti SpA |  | Liverpool Bay Ltd

(euro million) |  | Carrying value |  | Fair value |  | Carrying value |  | Fair value

Current assets |  | 60 |  |  | 60 |  |  | 36 |  |  | 36
Goodwill |  | 8 |  |  | 32 |  |  |  |  |  | 35
Other non-current assets |  |  |  |  |  |  |  | 320 |  |  | 320
Assets acquired |  | 68 |  |  | 92 |  |  | 356 |  |  | 391
Current liabilities |  | 61 |  |  | 61 |  |  | 34 |  |  | 34
Net deferred tax liabilities |  |  |  |  |  |  |  | 48 |  |  | 48
Provisions for contingencies |  |  |  |  |  |  |  | 288 |  |  | 288
Other non-current liabilities |  | 1 |  |  | 1 |  |  |  |  |  |
Liabilities acquired |  | 62 |  |  | 62 |  |  | 370 |  |  | 370
Fair value of the investment held before the acquisition of control |  | (3 | ) |  | (15 | ) |  |  |  |  |
Eni's shareholders equity |  | 3 |  |  | 15 |  |  | (14 | ) |  | 21

Supplemental cash flow information

(euro million) |  | 2012 |  | 2013 |  | 2014

Effect of investment of companies included in consolidation and businesses |  |  |  |  |  |  |  |  |
Current assets |  | 108 |  |  | 51 |  |  | 96 |
Non-current assets |  | 171 |  |  | 39 |  |  | 265 |
Net borrowings |  | 46 |  |  | (12 | ) |  | (19 | )
Current and non-current liabilities |  | (99 | ) |  | (36 | ) |  | (291 | )
Net effect of investments |  | 226 |  |  | 42 |  |  | 51 |
Fair value of investments held before the acquisition of control |  |  |  |  | (8 | ) |  | (15 | )
Purchase price |  | 226 |  |  | 34 |  |  | 36 |
less: |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | (48 | ) |  | (9 | ) |  |  |
Cash flow on investments |  | 178 |  |  | 25 |  |  | 36 |
Effect of disposal of consolidated subsidiaries and businesses |  |  |  |  |  |  |  |  |
Current assets |  | 2,112 |  |  | 47 |  |  | 5 |
Non-current assets |  | 18,740 |  |  | 41 |  |  | 2 |
Net borrowings |  | (12,443 | ) |  | 23 |  |  |  |
Current and non-current liabilities |  | (4,123 | ) |  | (69 | ) |  | (2 | )
Net effect of disposals |  | 4,286 |  |  | 42 |  |  | 5 |
Fair value of share capital held after the sale of control |  | (943 | ) |  |  |  |  |  |
Gain on disposal |  | 2,021 |  |  | 3,359 |  |  | (5 | )
Non-controlling interest |  | (1,840 | ) |  |  |  |  |  |
Selling price |  | 3,524 |  |  | 3,401 |  |  |  |
less: |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | (3 | ) |  |  |  |  |  |
Cash flow on disposals |  | 3,521 |  |  | 3,401 |  |  |  |

Investments of 2014 related to the acquisition of 51% stake in Acam Clienti SpA and 100% stake of Liverpool Bay Ltd. Divestments of 2014 related to the sale of a business.

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36 Guarantees, commitments and risks
Guarantees

|  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Unsecured guarantees |  | Other guarantees |  | Total |  | Unsecured guarantees |  | Other guarantees |  | Total

Consolidated subsidiaries |  |  |  | 11,930 |  | 11,930 |  |  |  | 13,214 |  | 13,214
Unconsolidated subsidiaries |  |  |  | 160 |  | 160 |  |  |  | 180 |  | 180
Consolidated joint operations |  |  |  | 48 |  | 48 |  |  |  | 14 |  | 14
Joint ventures and associates |  | 6,272 |  | 124 |  | 6,396 |  | 6,272 |  | 99 |  | 6,371
Others |  | 2 |  | 174 |  | 176 |  | 2 |  | 197 |  | 199
|  | 6,274 |  | 12,436 |  | 18,710 |  | 6,274 |  | 13,704 |  | 19,978

Other guarantees issued on behalf of consolidated subsidiaries of euro 13,214 million (euro 11,930 million at December 31, 2013) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 9,074 million (euro 7,858 million at December 31, 2013), of which euro 5,945 million related to the Engineering & Construction segment (euro 4,920 million at December 31, 2013); (ii) VAT recoverable from tax authorities for euro 1,567 million (euro 1,387 million at December 31, 2013); and (iii) insurance risk for euro 179 million reinsured by Eni (euro 293 million at December 31, 2013). At December 31, 2014, the underlying commitment covered by such guarantees was euro 13,162 million (euro 11,749 million at December 31, 2013).

Other guarantees issued on behalf of unconsolidated subsidiaries of euro 180 million (euro 160 million at December 31, 2013) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for euro 167 million (euro 147 million at December 31, 2013). At December 31, 2014, the underlying commitment covered by such guarantees was euro 21 million (euro 29 million at December 31, 2013).

Other guarantees issued on behalf of consolidated joint operations of euro 14 million (euro 48 million at December 31, 2013) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 5 million (euro 31 million at December 31, 2013) related to the Engineering & Construction segment; and (ii) VAT recoverable from tax authorities for euro 3 million (euro 11 million at December 31, 2013). At December 31, 2014, the underlying commitment covered by such guarantees was euro 14 million (euro 48 million at December 31, 2013).

Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of euro 6,371 million (euro 6,396 million at December 31, 2013) primarily consisted of: (i) an unsecured guarantee of euro 6,122 million (same amount as of December 31, 2013) 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; consortium members, excluding entities controlled by Eni, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) unsecured guarantees and other guarantees given to banks in relation to loans and lines of credit received for euro 171 million (euro 170 million at December 31, 2013); and (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for euro 21 million (euro 31 million at December 31, 2013). At December 31, 2014, the underlying commitment covered by such guarantees was euro 247 million (euro 284 million at December 31, 2013).

Unsecured and other guarantees given on behalf of third parties of euro 199 million (euro 176 million at December 31, 2013) primarily consisted of: (i) 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 re-gasification activity for euro 168 million (euro 147 million at December 31, 2013); and (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit for euro 8 million on behalf of minor investments or companies sold (euro 10 million at December 31, 2013). At December 31, 2014, the underlying commitment covered by such guarantees was euro 186 million (euro 162 million at December 31, 2013).

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Commitments and risks

(euro million) |  | Dec. 31, 2013 |  | Dec. 31, 2014

Commitments |  | 14,200 |  | 15,276
Risks |  | 377 |  | 415
|  | 14,577 |  | 15,691

Other commitments of euro 15,276 million (euro 14,200 million at December 31, 2013) 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 euro 11,112 million (euro 9,804 million at December 31, 2013); (ii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Angola LNG Supply Service for the acquisition of re-gasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031). The expected commitment has been estimated at euro 2,431 million (euro 2,228 million at December 31, 2013) and it has included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk"; (iii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Gulf LNG Energy for the acquisition of re-gasification capacity at the Pascagoula terminal (5.8 BCM/y) over a twenty-year period (until 2031). The expected commitment has been estimated at euro 1,137 million (euro 1,059 million at December 31, 2013) and it has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk"; (iv) purchase and sale commitments of financial derivatives on currency with a fair value equal to zero at December 31, 2014 for euro 120 million and euro 116 million, respectively; (v) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Cameron LNG Llc, a company belonging to Sempra Group, for the acquisition of re-gasification capacity at the Cameron plant (United States) for 6 BCM/y until 2017. The future expected commitment has been estimated at euro 200 million (euro 942 million at December 31, 2013) and it has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk". The reduction of the commitment was due to the revision of the contractual agreements with Cameron LNG Llc that determined the early termination from 2029 to 2017 of the commitment of Eni’s following approval in 2014 by the U.S. Authorities to Cameron LNG Llc to export LNG and the conversion of the regasification plant into a liquefaction plant. Based on the new agreements with Sempra, the provision for risks on expected contractual losses was partially utilized for redundancy; and (vi) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 130 million 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 (euro 138 million at December 31, 2013). The commitment has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk".

Risks of euro 415 million (euro 377 million at December 31, 2013) primarily concerned potential risks associated with contractual assurances given to acquirers of certain investments and businesses of Eni for euro 351 million (euro 287 million at December 31, 2013) and the value of assets of third parties under the custody of Eni for euro 64 million (euro 90 million at December 31, 2013).

Non-quantifiable commitments
A parent company guarantee was issued on behalf of CARDÓN IV (Eni’s interest 50%), a joint venture operating in the Perla oilfield located in Venezuela, for the supplying to PDVSA GAS of gas quantities until 2036 (end of the concession agreement). This guarantee can not be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective as a result of the revision of the contractual agreements. In case of non-fulfillment the maximum value of the guarantee will be determined by applying the local legislation. Gas expected to be provided for by Eni amounted to a total of $10 billion. As well as not corresponding to an effective valuation of the guarantee issued, such amount represents the maximum exposure 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 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 of Eni’s 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

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operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity.

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 Divisions or subsidiaries) is pooled and managed by the Midstream Department 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 on the basis of the relevant asset class expertises. 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; (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 Value at Risk, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s guidelines define rules to manage the commodity risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of Value at Risk, limits of revision strategy, stop loss and volumes in connection with exposure deriving from commercial activities, centrally managed by the Midstream Department, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trading & Shipping. Internal mandates to manage the commodity

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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 Midstream Department 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. Such reserve is managed by Eni’s finance department with the aim of optimizing the efficiency and ensuring maximum protection of the capital 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 through the use of certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value on the basis of 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 in accordance with IAS 39. 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. Borrowing requirements of Group companies are pooled by the Group’s central finance department in order to manage net positions and the funding of portfolio developments consistently with management’s plans while maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value on the basis of 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 in accordance with IAS 39. Value at Risk deriving from interest rate exposure is measured daily on the basis of a variance/covariance model, with a 99% confidence level and a 20-day holding period.

Market risk - Commodity
Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil and 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 and 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 on the basis of risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, stop loss). In particular, the

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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, Thresholds of strategy review, 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 unit (Eni’s Divisions or subsidiaries) is pooled and managed by the Portfolio Management unit of the Midstream Department for commodities, and by Eni’s finance department for exchange rate requirements. The Midstream Department manages business units’ 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) with the underlying commodities being crude oil, refined products, electricity or emission certificates. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable valuation techniques. Value at Risk deriving from commodity exposure is measured daily on the basis of 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 impact 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.

Strategic liquidity management is regulated in terms of Value at Risk (measured on the basis of 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 year 2014, the investment portfolio has maintained an average credit rating of A/A-, in line with the rating of Eni.

The following table shows amounts in terms of Value at Risk, recorded in 2014 (compared with 2013) relating to interest rate and exchange rate risks in the first section and commodity risk.

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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%)

|  | 2013 |  | 2014

(euro million) |  | High |  | Low |  | Average |  | At year end |  | High |  | Low |  | Average |  | At year end

Interest rate (a) |  | 3.67 |  | 1.49 |  | 2.07 |  | 2.15 |  | 4.42 |  | 1.29 |  | 2.05 |  | 2.49
Exchange rate (a) |  | 0.37 |  | 0.07 |  | 0.14 |  | 0.24 |  | 0.23 |  | 0.03 |  | 0.09 |  | 0.12

(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%)

|  | 2013 |  | 2014

(euro million) |  | High |  | Low |  | Average |  | At year end |  | High |  | Low |  | Average |  | At year end

Commercial exposures - Management Portfolio (a) |  | 108.13 |  | 36.59 |  | 59.92 |  | 66.44 |  | 44.20 |  | 4.02 |  | 21.46 |  | 4.02
Trading (b) |  | 7.50 |  | 1.36 |  | 4.11 |  | 2.93 |  | 5.57 |  | 0.46 |  | 3.04 |  | 0.87

(a) |  | Refers to the Midstream Department (risk exposure from Refining & Marketing Division and Gas & Power Division), Versalis, Eni Trading & Shipping and the subsidiaries outside Italy pertaining to the Division. 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.
(b) |  | Cross-commodity proprietary trading, both for commodity contracts and financial derivatives, refers to Eni Trading & Shipping SpA (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston).

(Sensitivity - Dollar value of 1 basis point - DVBP)

|  | 2013 |  | 2014

(euro million) |  | High |  | Low |  | Average |  | At year end |  | High |  | Low |  | Average |  | At year end

Strategic liquidity (a) |  | 0.12 |  | 0.02 |  | 0.10 |  | 0.11 |  | 0.28 |  | 0.09 |  | 0.14 |  | 0.26

(a) |  | The management of the strategic liquidity portfolio started 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. The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also 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.

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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. 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: (a) 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, limitations in profitable acquisitions); (b) 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; (c) ensuring the availability of an adequate level of financial flexibility to support the Group’s development plans; and (d) maintaining/improving the current credit rating. The financial asset reserve is employed in short-term marketable financial instruments, favoring investments with very low risk profile. At present, the Group believes to have access to sufficient funding to meet the current foreseeable borrowing requirements as a consequence of the availability of 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 euro 15 billion, of which about euro 13.3 billion were drawn as of December 31, 2014.

The Group has credit ratings of A and A-1, respectively for long and short-term debt, under review for possible downgrade (Credit Watch Negative), assigned by Standard & Poor’s and A3 and P-2, respectively for long and short-term debt, outlook stable, 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. On the basis of 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. The Company, through a constant monitoring of the international economic environment and continuing dialogue with financial investors and rating agencies, believes to be ready to perceive emerging critical issues screened by the financial community and to be able to react quickly to any changes in the financial and the global macroeconomic environment and implement the necessary actions to mitigate such risks, coherently with Company strategies.

In the course of the 2014, Eni issued a bond amounting to euro 1 billion related to the Euro Medium Term Notes Program.

As of December 31, 2014, Eni maintained short-term unused borrowing facilities of euro 12,698 million, of which euro 41 million committed. Long-term committed borrowing facilities amounted to euro 6,598 million, of which euro 647 million were due within 12 months, which were completely undrawn at the balance sheet date. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.

The tables below summarize the Group main contractual obligations (undiscounted) for finance debt repayments, including expected payments for interest charges, and trade and other payables maturities outstanding at period end.

Finance debt repayments including expected payments for interest charges and derivatives
The tables below summarize the Group main contractual obligations for finance liability repayments, including expected payments for interest charges and derivatives.

(euro million) |  | Maturity year

|  | 2014 |  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 and thereafter |  | Total

December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Non-current liabilities |  | 1,737 |  | 3,700 |  | 3,211 |  | 2,937 |  | 1,392 |  | 9,781 |  | 22,758
Current financial liabilities |  | 2,553 |  |  |  |  |  |  |  |  |  |  |  | 2,553
Fair value of derivative instruments |  | 995 |  | 243 |  | 1 |  | 5 |  |  |  | 34 |  | 1,278
|  | 5,285 |  | 3,943 |  | 3,212 |  | 2,942 |  | 1,392 |  | 9,815 |  | 26,589
Interest on finance debt |  | 818 |  | 710 |  | 650 |  | 557 |  | 429 |  | 1,695 |  | 4,859
Financial guarantees |  | 172 |  |  |  |  |  |  |  |  |  |  |  | 172

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(euro million) |  | Maturity year

|  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 |  | 2020 and thereafter |  | Total

December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Non-current liabilities |  | 3,533 |  | 3,226 |  | 3,217 |  | 1,462 |  | 2,795 |  | 8,709 |  | 22,942
Current financial liabilities |  | 2,716 |  |  |  |  |  |  |  |  |  |  |  | 2,716
Fair value of derivative instruments |  | 4,111 |  | 101 |  | 17 |  |  |  | 25 |  |  |  | 4,254
|  | 10,360 |  | 3,327 |  | 3,234 |  | 1,462 |  | 2,820 |  | 8,709 |  | 29,912
Interest on finance debt |  | 792 |  | 702 |  | 609 |  | 478 |  | 413 |  | 1,781 |  | 4,775
Financial guarantees |  | 173 |  |  |  |  |  |  |  |  |  |  |  | 173

Trade and other payables
The tables below summarize the Group trade and other payables by maturity.

(euro million) |  | Maturity year

|  | 2014 |  | 2015-2018 |  | 2019 and thereafter |  | Total

December 31, 2013 |  |  |  |  |  |  |  |
Trade payables |  | 15,584 |  |  |  |  |  | 15,584
Other payables and advances |  | 8,117 |  | 18 |  | 56 |  | 8,191
|  | 23,701 |  | 18 |  | 56 |  | 23,775

(euro million) |  | Maturity year

|  | 2015 |  | 2016-2019 |  | 2020 and thereafter |  | Total

December 31, 2014 |  |  |  |  |  |  |  |
Trade payables |  | 15,015 |  |  |  |  |  | 15,015
Other payables and advances |  | 8,688 |  | 82 |  | 22 |  | 8,792
|  | 23,703 |  | 82 |  | 22 |  | 23,807

Expected payments by period under contractual obligations and commercial commitments
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.

(euro million) |  | Maturity year

|  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 |  | 2020 and thereafter |  | Total

Operating lease obligations (a) |  | 606 |  | 468 |  | 398 |  | 314 |  | 242 |  | 957 |  | 2,985
Decommissioning liabilities (b) |  | 217 |  | 191 |  | 194 |  | 326 |  | 264 |  | 15,378 |  | 16,570
Environmental liabilities (c) |  | 300 |  | 283 |  | 234 |  | 298 |  | 177 |  | 373 |  | 1,665
Purchase obligations (d) |  | 19,317 |  | 16,346 |  | 15,622 |  | 15,201 |  | 14,645 |  | 142,795 |  | 223,926
- Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |
. take-or-pay contracts |  | 16,479 |  | 14,725 |  | 14,034 |  | 14,078 |  | 13,616 |  | 137,866 |  | 210,798
. ship-or-pay contracts |  | 1,771 |  | 1,212 |  | 1,184 |  | 934 |  | 843 |  | 3,618 |  | 9,562
- Other take-or-pay or ship-or-pay obligations |  | 123 |  | 118 |  | 106 |  | 98 |  | 97 |  | 423 |  | 965
- Other purchase obligations (e) |  | 944 |  | 291 |  | 298 |  | 91 |  | 89 |  | 888 |  | 2,601
Other obligations |  | 3 |  | 3 |  | 3 |  | 3 |  | 2 |  | 116 |  | 130
- Memorandum of intent relating Val d’Agri |  | 3 |  | 3 |  | 3 |  | 3 |  | 2 |  | 116 |  | 130
|  | 20,443 |  | 17,291 |  | 16,451 |  | 16,142 |  | 15,330 |  | 159,619 |  | 245,276

(a) |  | 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.
(b) |  | 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.
(c) |  | Environmental liabilities do not include the environmental charge of 2010 amounting to euro 1,109 million for the proposal to the Italian Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment are not reasonably estimable.
(d) |  | Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(e) |  | Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States (euro 1,317 million).

Capital investment and capital expenditure commitments
In the next four years Eni expects capital investments and capital expenditures of euro 47.8 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties.

The amounts shown in the table below include committed expenditures to execute certain environmental projects.

|  | Maturity year

(euro million) |  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019 and thereafter |  | Total

Committed projects |  | 10,376 |  | 8,188 |  | 5,039 |  | 3,103 |  | 5,420 |  | 32,126

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Other information about financial instruments
The carrying amount of financial instruments and relevant economic and equity effect as of and for the years ended December 31, 2013 and 2014 consisted of the following:

|  | 2013 |  | 2014

|  | Finance income (expense) recognized in |  | Finance income (expense) recognized in

(euro million) |  | Carrying amount |  | Profit and loss account |  | Other comprehensive income |  | Carrying amount |  | Profit and loss account |  | Other comprehensive income

Held-for-trading financial instruments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Securities (a) |  | 5,004 |  |  | 4 |  |  |  |  |  | 5,024 |  |  | 24 |  |  |  |
Non-hedging derivatives (b) |  | (21 | ) |  | (180 | ) |  |  |  |  | 192 |  |  | 421 |  |  |  |
Trading derivatives (b) |  | (61 | ) |  | (8 | ) |  |  |  |  | (481 | ) |  | 27 |  |  |  |
Held-to-maturity financial instruments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Securities (a) |  | 80 |  |  | 1 |  |  |  |  |  | 76 |  |  | 1 |  |  |  |
Available-for-sale financial instruments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Securities (a) |  | 235 |  |  | 7 |  |  | (1 | ) |  | 257 |  |  | 7 |  |  | 7 |
Investments valued at fair value |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current investments (c) |  | 2,770 |  |  | 456 |  |  | (64 | ) |  | 1,744 |  |  | (60 | ) |  | (77 | )
Other non-current investments - held-for-sale investments (c) |  | 2,131 |  |  | 1,702 |  |  |  |  |  |  |  |  |  |  |  |  |
Receivables and payables and other assets/liabilities valued at amortized cost |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Trade receivables and other (d) |  | 28,727 |  |  | (277 | ) |  |  |  |  | 27,573 |  |  | (116 | ) |  |  |
Financing receivables (a) |  | 1,791 |  |  | 1 |  |  |  |  |  | 2,763 |  |  | 108 |  |  |  |
Trade payables and other (e) |  | 23,775 |  |  | 28 |  |  |  |  |  | 23,807 |  |  | (188 | ) |  |  |
Financing payables (a) |  | 25,560 |  |  | (844 | ) |  |  |  |  | 25,891 |  |  | (1,201 | ) |  |  |
Net assets (liabilities) for hedging derivatives (f) |  | (202 | ) |  | (501 | ) |  | (198 | ) |  | (470 | ) |  | (497 | ) |  | (167 | )

(a) |  | Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(b) | i | In the profit and loss account, economic effects were recognized as income within "Other operating income (loss)" for euro 286 million (loss for euro 96 million in 2013) and as income within "Finance income (expense)" for euro 162 million (expense for euro 92 million in 2013).
(c) |  | Income was recognized as expense in the profit and loss account within "Income (expense) from investments" for euro 60 million (income for euro 2,158 million in 2013).
(d) |  | In the profit and loss account, economic effects were essentially recognized as expense within "Purchase, services and other" for euro 464 million (expense for euro 311 million in 2013) (impairments net of reversal) and as income for euro 348 million within "Finance income (expense)" (income for euro 34 million in 2013) (exchange rate differences at year-end and amortized cost).
(e) |  | 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)".
(f) | i | In the profit and loss account, income or expense were recognized within "Net sales from operations" and "Purchase, services and other" as expense for euro 356 million (expense for euro 526 million at December 31, 2013) and as expense within "Finance income (expense)" for euro 141 million (income for euro 25 million in 2013) (time value component).

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Disclosures about the offsetting of financial instruments
The table below summarizes the disclosures about the offsetting of financial instruments.

(euro 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, 2013 |  |  |  |  |  |
Financial assets |  |  |  |  |  |
Trade and other receivables |  | 30,285 |  | 1,395 |  | 28,890
Other current assets |  | 1,620 |  | 295 |  | 1,325
Other non-current assets |  | 3,711 |  | 35 |  | 3,676
Financial liabilities |  |  |  |  |  |
Trade and other liabilities |  | 25,096 |  | 1,395 |  | 23,701
Other current liabilities |  | 1,741 |  | 304 |  | 1,437
Other non-current liabilities |  | 2,285 |  | 26 |  | 2,259
December 31, 2014 |  |  |  |  |  |
Financial assets |  |  |  |  |  |
Trade and other receivables |  | 29,667 |  | 1,066 |  | 28,601
Other current assets |  | 7,639 |  | 3,254 |  | 4,385
Other non-current assets |  | 3,329 |  | 556 |  | 2,773
Financial liabilities |  |  |  |  |  |
Trade and other liabilities |  | 24,769 |  | 1,066 |  | 23,703
Other current liabilities |  | 7,926 |  | 3,437 |  | 4,489
Other non-current liabilities |  | 2,658 |  | 373 |  | 2,285

The offsetting of financial assets and liabilities of euro 4,876 million (euro 1,725 million at December 31, 2013) related to assets and liabilities for financial derivatives pertaining to Eni Trading & Shipping SpA for euro 3,810 million (euro 641 million at December 31, 2013) and to the offsetting of receivables and debts pertaining to the Exploration & Production segment towards state entities for euro 1,066 million (euro 1,084 million at December 31, 2013).

Disclosures on fair value of financial instruments Following the classification of financial assets and liabilities, measured at fair value in the balance sheet, is provided according to the fair value hierarchy defined on the basis of the relevance of the inputs used in the measurement process. In particular, on the basis of the features of the inputs used in making the measurements, the fair value hierarchy shall have the following levels:

a) |  | Level 1: quoted prices (unadjusted) in active markets for identical financial assets or liabilities;
b) |  | Level 2: measurements based on the basis of inputs, other than quoted prices above, which, for assets and liabilities that have to be measured, can be observable directly (e.g. prices) or indirectly (e.g. deriving from prices); and
c) |  | Level 3: inputs not based on observable market data.

Financial instruments measured at fair value in the balance sheet as of at December 31, 2014, were classified as follows: (i) level 1 “Quoted financial assets held for trading”, “Financial assets available for sale”, “Inventories - Certificates and emission rights”, “Derivatives - Futures” and “Other investments” measured at fair value; and (ii) level 2 “Non-quoted financial assets held for trading”, “Derivative financial instruments other than futures” included in “Other current assets”, “Other non-current assets”, “Other current liabilities” and “Other non-current liabilities”.

During the 2014, there were no transfers between the different hierarchy levels of fair value.

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The table below summarizes the amount of financial instruments measured at fair value:

(euro million) |  | Note |  | Dec. 31, 2013 |  | Dec. 31, 2014

|  |  |  | Level 1 |  | Level 2 |  | Level 1 |  | Level 2

Current assets |  |  |  |  |  |  |  |  |  |
Quoted financial assets held for trading |  | (9) |  | 4,461 |  |  |  | 5,024 |  |
Non-quoted financial assets held for trading |  | (9) |  |  |  | 543 |  |  |  |
Financial assets available for sale |  | (10) |  | 235 |  |  |  | 257 |  |
Inventories - Certificates and emission rights |  | (12) |  | 22 |  |  |  | 34 |  |
Derivatives - Future |  | (15) |  | 64 |  |  |  | 4 |  |
Cash flow hedge derivatives |  | (15) |  |  |  | 14 |  |  |  | 41
Non-hedging and trading derivatives |  | (15) |  |  |  | 654 |  |  |  | 3,254
Non-current assets |  |  |  |  |  |  |  |  |  |
Other investments valued at fair value |  | (19) |  | 2,770 |  |  |  | 1,744 |  |
Other investments valued at fair value held for sale |  | (33) |  |  |  | 2,131 |  |  |  |
Cash flow hedge derivatives |  | (22) |  |  |  | 6 |  |  |  |
Non-hedging derivatives |  | (22) |  |  |  | 256 |  |  |  | 196
Current liabilities |  |  |  |  |  |  |  |  |  |
Derivatives - Futures |  | (27) |  | 12 |  |  |  | 81 |  |
Cash flow hedge derivatives |  | (27) |  |  |  | 213 |  |  |  | 510
Non-hedging and trading derivatives |  | (27) |  |  |  | 770 |  |  |  | 3,520
Non-current liabilities |  |  |  |  |  |  |  |  |  |
Cash flow hedge derivatives |  | (32) |  |  |  | 1 |  |  |  |
Non-hedging derivatives |  | (32) |  |  |  | 282 |  |  |  | 143

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.

A description of the most significant proceedings currently pending is provided in the following paragraph. Unless otherwise indicated below, 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) Fatal accident Truck Center Molfetta - Prosecuting body: Public Prosecutor of Trani. On May 11, 2010, Eni SpA, eight employees of the Company and a former employee were notified of closing of the investigation into alleged manslaughter, grievous bodily harm and illegal disposal of waste materials 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 owned by a company part of the Italian Railways Group. The tank was used for the transportation of liquid sulphur produced by Eni in the Refinery of Taranto. On December 5, 2011, the Judge pronounced an acquittal sentence for the individuals involved and for Eni SpA, as the indictment is groundless. The first hearing of the appeal filed by the Public Prosecutor has yet to be scheduled.

(ii) 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 till 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 which have owned and managed the landfill since 1991. An assessment was performed by independent consultants and the proceeding is still pending.

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(iii) Eni SpA - Gas & Power Division - 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 which those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. On the basis of 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. On December 19, 2014, the Tribunal issued an acquittal sentence for all defendants, as the indictment was found groundless. The next step will be the filing of the outcomes of the judgment.

(iv) Syndial SpA and Versalis SpA - Porto Torres dock - Prosecuting body: Public Prosecutor of Sassari. 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 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 proceeding is still pending.

(v) Syndial SpA - Public Prosecutor of Gela. An investigation before the Public Prosecutor of Gela is pending regarding a number of former Eni employees. In particular, the proceeding involves 17 former managers of the companies ANIC SpA, EniChem SpA, EniChem Anic SpA, Anic Agricoltura SpA, Agip Petroli SpA and Praoil Aromatici e Raffinazione Srl who were previously in charge of conducting operations and granting security at a plant for the production of chlorine and caustic soda in Gela. The proceeding regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged diseases which those persons may have contracted at the above mentioned plant. Alleged crimes relate to the period from 1969, when the 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 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. The outcomes of the assessment are being assessed by the Public Prosecutor.

(vi) 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 seized by the Judicial Authority pending an 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 which 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 and Syndial entered into an agreement with the Municipality of Cerchiara to settle all damages caused by the unauthorized waste disposal in the landfills to the territory of the Municipality. The Municipality of Cerchiara renounced all claims in relation to the circumstances investigated in the criminal proceeding. Eni’s subsidiary has also arranged a similar transaction with the Municipality of Cassano. Syndial is performing clean-up and remediation activities. The criminal proceeding is still pending.

(vii) 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 75 affected victims. The plaintiffs include relatives of the alleged victims and 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. On February 6, 2014 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. The proceeding is entering the hearing phase.

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1.2 Civil and administrative proceedings in the matters of environment, health and safety

(i) Syndial SpA (former EniChem 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 (former EniChem) 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 euro 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. 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 such outcome was questioned by the Board of State Lawyers. The Appeal court of Turin summoned the parties and indicated in the subpoena an interpretation of the environmental damage which seemed to mirror the position of the Eni’s subsidiary.

(ii) Action commenced by the Municipality of Carrara for the remediation and reestablishment of previous environmental conditions at the Avenza site and payment of environmental damage. The Municipality of Carrara commenced an action before the Court of Genoa requesting Syndial SpA to remediate and restore previous environmental conditions at the Avenza site and the payment of environmental damage (amounting to euro 139 million), further damages of various types (e.g. damage to the natural beauty of this site) amounting to euro 80 million, as well as damages relating to loss of profit and property amounting to approximately euro 16 million. This request is related to an accident that occurred in 1984, as a consequence of which EniChem Agricoltura SpA (later merged into Syndial SpA), at the time owner of the site, carried out safety and remediation works. The Ministry for the Environment joined the action and requested environmental damage payment – from a minimum of euro 53.5 million to a maximum of euro 93.3 million – to be broken down among the various companies that ran the plant in the past. With a sentence of March 2008, the Court of Genoa rejected all claims made by the Municipality of Carrara and the Ministry for the Environment. The Second Instance Court also confirmed the decision issued in the first judgment and rejected all the claims made by the plaintiffs. The Ministry for the Environment filed an appeal before a third instance court on the belief that Syndial is to be held responsible for the environmental damage as the Eni subsidiary took over the site from the previous owners assuming all existing liabilities; it was responsible for managing the plant and inadequately remediating the site after the occurrence of an incident in 1984 and for omitted clean-up. Syndial established itself as defendant.

(iii) 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 which is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above mentioned companies opposed said 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.

(iv) 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 18 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 the Gela Refinery 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. A technical appraisal of the matter is pending.

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(v) Environmental claim relating to the Municipality of Cengio - Plaintiffs: the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio. The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio 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.

(vi) 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 fauna of the industrial port of Porto Torres. The trial before a jurisdictional body of the Italian criminal law which is charged with judging the most serious crimes, was annulled as that jurisdictional body did not recognize the gravity elements justifying its judgment due to a different crime allegation in the notice of conclusion of the preliminary investigation with respect to the crime allegation presented in the request of trial filed by the Public Prosecutor. In February 2013, the Prosecutor of Sassari has notified the conclusion of preliminary investigations and requested a new imputation for negligent behavior instead of illicit conduct. In the conclusions of the preliminary hearing, the GUP of Sassari dismissed the accusation as a result of the statute of limitations. The Public Prosecutor filed an appeal before a Third Instance Court.

(vii) Kashagan. On March 7, 2014, the Atyrau Region Environmental Department (ARED) launched a series of civil claims against the Consortium developing the Kashagan field. These proceedings allege to certain emissions associated with gas flaring occurring during commissioning have resulted in infringements of environmental laws and environmental damages. The aggregate value of the civil claims is approximately $730 million (KZT 134 billion), of which Eni’s share would be approximately $123 million (KZT 22.5 billion). The Kashagan project’s consortium disputes these allegations. In 2014, the Consortium paid part of the claim amounting to $55 million (KZT 8.5 billion), $9 million being Eni’s share (KZT 1.4 billion) and commenced a legal dispute before a Kazakh court. Also considering a settlement agreement defined between the Consortium and the Kazakh Republic in December 2014, the Consortium is expecting that the amount of the claim will be significantly reduced and will not be higher than the amount already paid in 2014.

(viii) 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, Versalis and SMA.RI Srl for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the arraignment concerns the responsibilities of Syndial and Versalis for the production of waste, acting in quality of commissioners, because the source of the dangerous waste (in particular, the waste with high mercury concentration and railway sleepers no longer in use) would have been allegedly traced back to the Priolo and Gela industrial sites that are managed by the above mentioned Eni’s subsidiaries. This proceeding is part of a larger criminal procedure which took place in 2001-2003 with regard to the so-called “the Red Sea case”. Such waste would have been illegally disposed at the SMA.RI’s unauthorized landfill (this landfill is located about 2 kilometers from the town of Melilli). The damage is estimated at euro 500 million or another amount which will be defined during the trial. The proceeding is still pending.

2. Court inquiries and of other Regulatory Authorities

(i) Fos Cavaou. An arbitration proceeding before the International Chamber of Commerce of Paris between the client company Société du Terminal Méthanier Fos Cavaou (now FOSMAX LNG) and the contractor STS – a French consortium participated by Saipem SA (50%), Technimont SpA (49%) and Sofregaz SA (1%) – is pending. The memorandum filed by FOSMAX LNG supporting the arbitration proceeding claimed the payment of euro 264 million for damage payment, delay penalties and costs incurred for the termination of the works. Approximately euro 142 million of the total amount requested related to loss of profit, which is an item that cannot be compensated based on the existing contractual provisions with the exception of fraudulent and serious culpable behavior. STS filed counterclaim for a total amount of approximately euro 338 million as damage repayment due to the alleged

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excessive interference of FOSMAX LNG in the execution of the works and payment of extra works not recognized by the client. Both parties filed their memoranda. The arbitrators issued a final ruling on February 13, 2015 and established that FOSMAX LNG would pay an amount of euro 69.8 million to the STS consortium, including interest accrued over the period. Saipem’s share of the award is 50%.

(ii) Eni SpA - Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe - Prosecuting body: Delegated Commissioner. In March 2009, Eni and its subsidiary Sofid (now Eni Adfin) were notified of a bankruptcy claw back as part of a reorganization procedure filed by the airlines companies Volare Group, Volare Airlines and Air Europe which commenced under the provisions of Ministry of Production Activities, on November 30, 2004. The request regarded the override of all the payments made by those entities to Eni and Eni Adfin, as Eni agent for the receivables collection, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, for a total estimated amount of euro 46 million plus interest. Eni and Eni Adfin were admitted as defendants. After the conclusion of the investigation, a court ruled against the claims made by the commissioners of the reorganization procedures. The relevant ruling was filed on March 1, 2012. The commissioners filed a counterclaim against the first degree sentence.

(iii) 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 euro 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 euro 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 euro 131 million. An alternative assessment of the overall damage made by Alitalia stands at euro 395 million of which euro 334 million of higher purchase costs for jet fuel and euro 61 million of lower profitability due to the reduced competitive position on the marketplace. The proceeding of first instance is at a preliminary stage, as a number of pre-trial issues have caused a substantial delay.

3. Antitrust, EU Proceedings, Actions of the Authority for Electricity Gas and Water and of other Regulatory Authorities

(i) Investigation by the Italian Antitrust about Eni’s determination of Italian market share of the Italian gas wholesale market. On August 1, 2014, the Italian Antitrust commenced an investigation to review Eni’s determination about its share of Italian gas wholesaler market. This market share must comply with certain limits set by the Italian Law Decree No. 130/2010 and the relevant determination was filed with the Antitrust in May 2014. In case Eni filed an unfair determination of the market share it might be fined. In addition, in case Eni’s market share in the Italian wholesaler gas sector exceeds the regulatory thresholds, the Italian Antitrust might open a competitive procedure whereby the Company is obliged to dispose of certain gas volumes (the so-called gas release) in accordance with terms and conditions established by the Italian Ministry for Economic Development and the Italian Authority for Electricity Gas and Water.

(ii) Consob decision No. 18949 of June 18, 2014. With decision No. 18949 of June 14, 2014 the Italian commission for securities and exchange (Consob) fined Eni’s subsidiary Saipem by an amount of euro 80,000 in connection with alleged delay in issuing the profit warning which was disseminated by Saipem on January 29, 2013. A second degree court in Milan confirmed Consob decision. Saipem is planning to file recourse before a third degree court. In connection with those allegations of delay in issuing a profit warning, certain shareholders and former shareholders expressed their intention to file a complaint seeking possible damages. Saipem believes that those claims are groundless.

4. Court inquiries

(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

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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, 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 on the basis of a pronouncement made by a Supreme Court which 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 filed the ground of the judgment in December 19, 2011. The condemned parties filed an appeal against the above mentioned decision. The Appeal Court issued a ruling which substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. An appeal is still pending before a third degree court.

(ii) TSKJ Consortium Investigations by U.S., Italian, and other Authorities. Snamprogetti Netherlands BV has a 25% participation in the TSKJ Consortium companies. The remaining participations are held in equal shares of 25% by KBR, Technip, and JGC. Beginning in 1994, the TSKJ Consortium was involved in the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti SpA, the holding company of Snamprogetti Netherlands BV, was a wholly-owned subsidiary of Eni until February 2006, when an agreement was entered into for the sale of Snamprogetti to Saipem SpA and Snamprogetti was merged into Saipem as of October 1, 2008. Eni holds a 43% participation in Saipem. In connection with the sale of Snamprogetti to Saipem, Eni agreed to indemnify Saipem for a variety of matters, including potential losses and charges resulting from the investigations into the TSKJ matter referred to below, even in relation to Snamprogetti subsidiaries. In recent years the proceeding was settled with the U.S. Authorities and certain Nigerian Authorities, which had been investing into the matter.

The proceedings in the United States: following an investigation that lasted several years, in 2010 the Department of Justice and the SEC entered into settlements with each of the TSKJ Consortium members. In particular, in July 2010, Snamprogetti Netherlands BV entered into a deferred prosecution agreement with the DoJ, consented to the filing of criminal information, and agreed to pay a fine of $240 million. In addition, Snamprogetti Netherlands BV and Eni reached an agreement with the SEC to resolve the investigation and jointly agreed to pay disgorgement to the SEC of $125 million. All amounts due to the U.S. Authorities were paid by Eni in accordance with the indemnity granted by Eni in connection with its sale of Snamprogetti to Saipem. Following the two-year period set out in the deferred prosecution agreement, in September 2012, the DoJ dismissed the criminal information filed against Snamprogetti Netherlands BV, thereby dismissing the criminal proceeding against Snamprogetti Netherlands BV.

The proceedings in Italy: the events under investigation covered the period since 1994 and also concerned the period of time subsequent to the June 8, 2001, enactment of Italian Legislative Decree No. 231 concerning the liability of legal entities. The proceeding set by the Public Prosecutor of Milan investigated Eni SpA and Saipem SpA for liability of legal entities arising from offences involving alleged international corruption charged to former managers of Snamprogetti SpA. The Public Prosecutor of Milan requested Eni SpA and Saipem SpA to be debarred from activities involving – directly or indirectly – any agreement with the Nigerian National Petroleum Corp and its subsidiaries. Subsequently, the Public Prosecutor of Milan, with respect to the guarantee payment amounting to euro 24,530,580 even in the interest of Saipem SpA, renounced to contest the decision of rejection of precautionary measures of disqualification for Eni SpA and Saipem SpA. The charged crimes involved alleged corruptive events that have occurred in Nigeria after July 31, 2004. It is also stated the aggravating circumstance that Snamprogetti SpA reported a relevant profit (estimated at approximately $65 million). The Public Prosecutor requested five former employees of Snamprogetti SpA (now Saipem) and Saipem SpA (as legal entity incorporating Snamprogetti) to stand trial. In the course of the proceeding, the Court dismissed the case with respect to the position of the

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individuals who were acting as defendants for the expiration of the statute of limitations while the proceeding continued for Saipem SpA. Afterwards, the Court condemned Saipem SpA to pay a fine amounting to euro 600,000 and the disgorgement of the guarantee payment of euro 24,530,580, made by Snamprogetti Netherlands BV. Saipem filed an appeal against the sentence issued by the First Instance Court. The Appeal Court confirmed the first degree sentence on February 19, 2015. The Eni’s subsidiary is planning to file recourse with a third degree court. Eni accrued a provision in respect to this proceeding.

(iii) Algeria - Corruption investigation. Authorities in Italy and in other countries are investigating allegations of corrupt payments in connection with the award of certain contracts to Saipem. 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, the notification was forwarded by Eni 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. Subsequently, on November 30, 2012, Saipem was served a notice of seizure, then, on December 18, 2012, a request for documentation and finally, on January 16, 2013, 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. The investigation relates to alleged corruption which, according to the Public Prosecutor, had occurred with regard to certain contracts awarded to Saipem in Algeria up until March 2010. The former CEO of Saipem, who was resigned from the office at the end of 2012, and the former COO of the business unit Engineering & Construction of Saipem, who was fired at the beginning of 2013, as well as other Saipem employees and former employees are under investigation. On February 7, 2013, on mandate from the Public Prosecutor of Milan, the Italian financial 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. He departed from Eni in connection with the bribery investigation. Saipem, which is fully cooperating with the Judicial Authority since the beginning of the investigation, has also promptly undertaken management and administrative changes. Saipem has commenced an internal investigation in relation to the contracts in question with the support of external advisors; such internal investigation is conducted in agreement with the statutory bodies deputed to the Company’s control. In addition, in the course of 2013, Saipem has completed a review aimed at verifying the correct application of internal procedures and controls relating to anti-corruption and prevention of illicit activities, with the assistance of external consultants. Saipem provided the Judicial Authority and Eni with the findings of its internal review; Eni was informed in view of exercising its control and coordination with respect to the subsidiary. Moreover, Saipem’s Board resolved to initiate legal action to protect the interests of the Company against certain former employees and suppliers, reserving any further action if additional factors emerge. Eni, albeit denying any involvement in the matter, has commenced 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. To date, subject further investigation if necessary, the following preliminary results have been reached: (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 have 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. That review 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). The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. Furthermore, with the assistance of external consultants, Eni has been reviewing 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. On October 24, 2014, Eni SpA and Saipem 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 Engineering & Construction of Saipem and the former President and General Manager

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of Saipem Contracting Algérie. The hearing for admitting the evidence to be used in the trial was held in December 2014. 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 has requested its consultants to perform additional analysis and investigation, the results of which will be provided to the competent Judicial Authorities. On February 5, 2015, the Investigative Tax Police of Milan started a tax audit against Saipem in relation to: (i) matters arising the relevant aspects resulted from the criminal proceeding with respect to the tax years from January 1, 2008 to December 31, 2010; and (ii) economic transactions with non-EU companies operating in countries with privileged tax regimes for to the tax year 2010. The prosecutor has filed the request for trial for all the defendants of the crimes listed above. Eni has contacted the U.S. Authorities – the DoJ and the U.S. SEC – in order to voluntary inform them about this matter, considering the developments in the Italian prosecutors’ investigations since the end of 2012. Following this informal contact between Eni and the U.S. Authorities, 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. Investigations are also ongoing in Algeria in relation to the assignment of the contract GK3 from Sonatrach (the so-called “Sonatrach 1” investigation) where the bank accounts of a Saipem’s subsidiary, Saipem Contracting Algérie SpA, have been blocked by the Algerian Authorities with a balance equivalent to about euro 90 million at current exchange rates. Those bank accounts related to two ongoing projects in Algeria. In 2012, a notice of investigation was served to Saipem Contracting Algérie SpA. The company is alleged to have taken advantage of the Authority or influence of representatives of a government owned industrial and trading company in order to inflate prices in relation to a contract (GK3) awarded by said company. In January 2013, the Judicial Authority in Algeria ordered Saipem’s Algerian subsidiary to stand trial and reaffirmed the blockage of the above mentioned bank accounts. Saipem Contracting Algérie SpA has lodged an appeal against this decision before the Supreme Court which reaffirmed the blockage of the bank accounts. The proceeding started on March 15, 2015 and should be concluded in the course of 2015. Furthermore, also the parent company Saipem is being investigated by the Judicial Authority in Algeria for alleged corrupt payments (the so-called “Sonatrach 2” investigation).

(iv) 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 as a consequence 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

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Court. Also based on this decision, on March 13, 2014, the Eni legal team requested to the Public Prosecutor to dismiss the proceeding.

(v) Alleged international corruption in the acquisition of Block OPL 245 Nigeria - Prosecuting body: Public Prosecutor in Milan. On July 2, 2014, the Italian Public Prosecutor in 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. According to the notice, the Prosecutor has commenced investigations involving a third party external to the Group and other unidentified persons. 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 which 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 reported the matter to the U.S. Department of Justice and the U.S. SEC. Finally, the Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage outside consultants, experts in anti-corruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. The findings of this review which is ongoing will be promptly provided to the Judicial Authorities. On September 10, 2014, the Public Prosecutor notified Eni of a restraining order issued by a British judge who ruled the seizure of a bank account domiciled at a British bank following a request from the Italian Public Prosecutor. The order was also communicated 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 deduced that such Eni’s officers and former officers are under investigation by the Italian Public Prosecutor. During a hearing before a British court, Eni and its current executive officers gave evidence of their non-involvement in this matter regarding the seized bank account. Following the hearing, the Court issued a variation order regarding certain formal issues and reaffirmed its ruling.

(vi) 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 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 with promptness. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. After the ending of the investigation, the Fiscal Police from Frosinone, along with the local Customs Agency, in November 2013 issued a claim related to the evasion of the payment of excise taxes in the 2007-2012 periods for euro 1.55 million. In May 2014, the Customs Agency of Rome issued a payment notice relating to the above mentioned claim which 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. Moreover, at the Company’s request, the national association of refiners asked the Italian Customs Agency to provide its advice on the correctness of the operating models adopted by Eni. 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.

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5. Tax Proceedings

Italy

(i) Eni SpA - Dispute for the omitted payment of a municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. With a formal assessment presented in December 1999, the Municipality of Pineto (Teramo) claimed Eni SpA omitted payment of a municipal tax on real estate for the period from 1993 to 1998 on four oil platforms located in the Adriatic Sea which constitute municipal waters. Eni was requested to pay a total of approximately euro 17 million including interest and a fine. Eni filed a counterclaim stating that the sea where the platforms are located is not part of the municipal territory and the tax application as requested by the Municipality lacked objective fundamentals. The claim has been accepted in the first two degrees of judgment at the Provincial and Regional Tax Commissions. However, the Supreme Degree Court overturned both judgments,

declaring that a Municipality can consider requesting a tax on real estate in the sea facing its territory and with the decision of February 2005 sent the proceeding to another section of the Regional Tax Commission in order to rule on the matters of the proceeding. This commission requested an independent consultant to assess the tax and technical aspects of the matter. The independent consultant confirmed that Eni’s offshore installations lack any ground to be subject to the municipal tax that was claimed by the local Municipality. Those findings were accepted by the Regional Tax Commission with a ruling made on January 19, 2009. On January 25, 2011, the Municipality notified Eni of an appeal to the Supreme Degree Court for the cancellation of the above mentioned ruling. Also on December 28, 2005, the Municipality of Pineto presented similar claims relating to the same Eni platforms for the years 1999 to 2004. The total amount requested was euro 25 million including interest and penalties. Eni filed a counterclaim which was accepted by the First Degree Judge with a decision of December 4, 2007. Also a second degree court ruled in favor of Eni’s recourses with a sentence filed on June 2012. Terms are pending to file a counterclaim before a third degree court. Similar formal assessments related to Eni oil and gas offshore platforms were presented by the Municipalities of Pedaso, Cupra Marittima and also from 2009 the Gela Municipality.

(ii) Refund of tax surcharge as provided for by Article 3 of the Law No. 7 enacted on February 6, 2009. With the aim of financing infrastructure projects, as provided for by the Treaty of Friendship, Partnership and Cooperation between Italy and Libya signed in 2008, the Law No. 7/2009 introduced a tax surcharge of 4% applicable to the pre-tax profit should the effective tax role is lower than 19%. This tax is payable for the years 2009-2028. In 2009, Eni requested the recognition of the right for tax refund to the relevant courts by objecting to, in particular, an effect of double taxation on the dividends distributed by subsidiaries located in the European Union in contrast to the so-called parent-subsidiary directive. In December 2013, the Second Degree Court recognized the right to Eni to be refunded. The Italian Tax Authority did not appeal against this sentence which, consequently, became final in June 2014. The sentence concerned the right to reimbursement of the first tax installment relating to 2009 for an amount of euro 75 million, approximately. Eni filed an instance to the Italian Revenue Agency requesting the confirmation that for the determination of the tax surcharge, the taxable amount is to be decreased by an amount equal to 95% of the dividends distributed by subsidiaries located in EU. On September 26, 2014, the Italian Revenue Agency confirmed the exclusion of the above mentioned amount of dividends from the taxable base relating to the tax surcharge for the tax declaration yet submitted. Given the positive outcome of the Ruling request, Eni redetermined the tax due for the year 2012 by submitting a supplementary tax statement and the tax surcharge due for the year 2013 according to the new method of calculation. The correctness of the claims already submitted was confirmed for the second tax installment for the year 2009 and for the years 2010 and 2011. The effect through profit and loss was a tax gain of euro 824 million (and interests for approximately euro 40 million) which also includes higher taxes paid in previous years for which the recoverability was assessed in accordance with the international accounting standard IAS 12. In December 2014, the Italian Tax Authority paid the amount requested by Eni for the year 2009.

Outside Italy

(i) 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. Eni accrued a provision with respect to this proceeding.

(ii) Eni’s subsidiary in Indonesia. A tax proceeding is pending against Eni’s subsidiary Lasmo Sanga Sanga Ltd as the Tax Administration of Indonesia has questioned the application of a tax rate of 10% on the profit earned by the local branch. Eni’s subsidiary, which is resident in the United Kingdom for tax purposes, believes that the 10% tax rate is warranted by the current treaty for the avoidance of double taxation. On the contrary, the Tax Administration of Indonesia has claimed the application of the local tax rate of 20%. The greater taxes due in

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accordance to the latter rate have been disbursed amounting to $148 million including interest expense. Eni’s subsidiary has filed an appeal to the relevant tax authorities and accrued a provision with respect of this proceeding.

6. Settled legal proceedings

(i) Inquiries in relation to alleged anti competitive agreements in the area of elastomers. On November 29, 2006, the European Commission claimed alleged anti competitive agreements in the field of BR and ESBR elastomers and fined Eni and its subsidiary Versalis SpA (former Polimeri Europa SpA) for an amount of euro 272.25 million. Eni and its subsidiary filed claims against this decision before the European Court of First Instance which reduced the above mentioned fine to the amount of euro 181.5 million. This amount was accrued in Eni’s Consolidated Financial Statements in a previous reporting period and subsequently paid to the European Commission. The proceeding has been terminated. With regard to the alleged anti competitive practices in the sector of CR elastomers, in December 2012, the First Instance Court of the European Union reduced to euro 106 million the fine imposed to Eni and its subsidiary Polimeri Europa from the original amount of euro 132.16 million sanctioned on December 5, 2007. A recent sentence of the European Justice Court reaffirmed the reduced amount of the fine thus terminating this proceeding. The amount was accrued in Eni’s Consolidated Financial Statements in a previous reporting period.

(ii) Eni SpA - Investigation of the Italian Authority for Electricity Gas and Water (AEEGSI ) about the invoicing to retail clients of gas and electricity. With the resolution 477/2013/S/Com of October 31, 2013, the Italian AEEGSI resolved to commence a preliminary investigation to ascertain whether Eni violated certain administrative provisions that regulate the periodical invoicing in the retail selling of gas and electricity. The investigation also includes alleged delays in the invoice of certain documentation which is required in case of change of supplier. Eni filed certain proposals of commitments with the AEEGSI . In case the AEEGSI accepts those commitments, the AEEGSI would close the investigation without ascertaining any wrongdoing on part of Eni and without imposing any fine on the Company. The AEEGSI requested a market test and Eni modified its commitments in response to the AEEGSI review and suggestions from market participants. In 2014, the AEEGSI accepted Eni’s commitments and closed the investigation without formulating any charge against Eni.

Assets under concession arrangements
Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing segment. In the Exploration & Production segment contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. Pursuant to the assignment of mineral 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 on the basis of 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 segment 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 “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 remedial 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 the ongoing surveys and the other possible effects of statements required by Legislative Decree No. 152/2006 of the Ministry for the Environment; (iii) new

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developments in environmental regulation; (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
In 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. Phase three sees a turn in the main method of assignment of the permits that change from allocation for no consideration on the base of historical emissions to allocation through auctioning. For the period 2013-2020, the assignment for no consideration of the permits is done using European benchmarks specific to each industrial segment, except for the thermoelectric sector which is not eligible for allocations for no consideration. This new 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 through the market. In 2014, the emissions of carbon dioxide from Eni’s plants were higher than the permits assigned. Against emissions of carbon dioxide amounting to approximately 19.16 million tonnes were assigned to Eni emission permits for a total amount of 8.80 million tonnes, determining a deficit of 10.36 million tonnes. This deficit was entirely offset through acquisitions in the emission market.

37 Revenues
Following is a summary of the main components of "Revenues".

Net sales from operations

(euro million) |  | 2012 |  | 2013 |  | 2014

Revenues from sales and services |  | 126,364 |  | 114,549 |  | 109,760
Change in contract work in progress |  | 745 |  | 148 |  | 87
|  | 127,109 |  | 114,697 |  | 109,847

Revenues from sales and services were stated net of the following items:

(euro million) |  | 2012 |  | 2013 |  | 2014

Excise taxes |  | 13,823 |  | 12,650 |  | 12,289
Exchanges of oil sales (excluding excise taxes) |  | 2,177 |  | 2,018 |  | 1,586
Services billed to joint venture partners |  | 4,422 |  | 5,459 |  | 5,191
Sales to service station managers for sales billed to holders of credit cards |  | 2,010 |  | 1,909 |  | 1,804
|  | 22,432 |  | 22,036 |  | 20,870

Revenues from sales and services of euro 109,760 million (euro 126,364 million and euro 114,549 million in 2012 and 2013, respectively) included project income the Engineering & Construction segment for euro 11,504 million (euro 10,935 million and euro 10,427 million in 2012 and 2013, respectively), related to additional payments under negotiation (change orders and claims). The cumulative amount of additional payments based on project progress totaled euro 1,018 million and euro 801 million at December 31, 2013 and December 31, 2014, respectively. Saipem SpA also acquired technical and legal opinions of independent experts for the evaluation of projects having additional income exceeding euro 50 million.

Net sales from operations by industry segment and geographical area of destination are disclosed in note 43 – Information by industry segment and by geographical area.

Net sales from operations with related parties are disclosed in note 44 – Transactions with related parties.

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Other income and revenues

(euro million) |  | 2012 |  | 2013 |  | 2014

Gains on price adjustments under overlifting/underlifting transactions |  | 67 |  | 44 |  | 390
Gains from sale of assets |  | 701 |  | 370 |  | 92
Lease and rental income |  | 95 |  | 88 |  | 92
Compensation for damages |  | 56 |  | 65 |  | 44
Contract penalties and other trade revenues |  | 69 |  | 35 |  | 37
Other proceeds (*) |  | 560 |  | 785 |  | 446
|  | 1,548 |  | 1,387 |  | 1,101

(*) |  | Each individual amount included herein was lower than euro 50 million.

Gains from sale of assets of euro 92 million related for euro 83 million to the Exploration & Production segment.

Other income and revenues with related parties are disclosed in note 44 – Transactions with related parties.

38 Operating expenses
Following is a summary of the main components of "Operating expenses".

Purchase, services and other

(euro million) |  | 2012 |  | 2013 |  | 2014

Production costs - raw, ancillary and consumable materials and goods |  | 74,643 |  |  | 67,004 |  |  | 63,605 |
Production costs - services |  | 15,142 |  |  | 17,711 |  |  | 16,979 |
Operating leases and other |  | 3,440 |  |  | 3,678 |  |  | 4,080 |
Net provisions for contingencies |  | 856 |  |  | 850 |  |  | 494 |
Other expenses |  | 1,358 |  |  | 1,147 |  |  | 1,516 |
|  | 95,439 |  |  | 90,390 |  |  | 86,674 |
less: |  |  |  |  |  |  |  |  |
- capitalized direct costs associated with self-constructed assets - tangible assets |  | (326 | ) |  | (311 | ) |  | (253 | )
- capitalized direct costs associated with self-constructed assets - intangible assets |  | (79 | ) |  | (76 | ) |  | (81 | )
|  | 95,034 |  |  | 90,003 |  |  | 86,340 |

Services included brokerage fees related to the Engineering & Construction segment for euro 4 million (euro 6 million and euro 5 million in 2012 and 2013, 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 euro 186 million (euro 211 million and euro 197 million in 2012 and 2013, respectively).

Operating leases and other comprised operating leases for euro 1,965 million (euro 1,432 million and euro 1,592 million in 2012 and 2013, respectively) and royalties on the extraction of hydrocarbons for euro 1,278 million (euro 1,555 million and euro 1,413 million in 2012 and 2013, respectively).

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Other expenses of euro 1,516 million included: (i) expenses for changes in selling prices for overlifting and underlifting operations for euro 409 million (euro 57 million and euro 50 million in 2012 and 2013, respectively); and (ii) losses on disposal of tangible and intangible assets for euro 160 million, of which euro 144 million related to the Exploration & Production segment.

Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below:

(euro million) |  | 2012 |  | 2013 |  | 2014

To be paid: |  |  |  |  |  |
- within 1 year |  | 722 |  | 706 |  | 606
- between 2 and 5 years |  | 1,289 |  | 1,212 |  | 1,422
- beyond 5 years |  | 560 |  | 349 |  | 957
|  | 2,571 |  | 2,267 |  | 2,985

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 which may limit the ability of Eni to pay dividends, use assets or take on new borrowings.

Risk provisions net of reversal of unused provisions amounted to euro 494 million (euro 856 million and euro 850 million in 2012 and 2013, respectively) and mainly related to provisions for legal and other proceedings amounting to euro 536 million (net provisions of euro 688 million and euro 222 million in 2012 and 2013, respectively) and to environmental liabilities amounting to euro 177 million (net provisions of euro 67 million and euro 127 million in 2012 and 2013, respectively). More information is provided in note 29 – Provisions for contingencies.

Payroll and related costs

(euro million) |  | 2012 |  | 2013 |  | 2014

Wages and salaries |  | 3,904 |  |  | 4,395 |  |  | 4,645 |
Social security contributions |  | 679 |  |  | 657 |  |  | 709 |
Cost related to employee benefits plans |  | 110 |  |  | 92 |  |  | 104 |
Other costs |  | 184 |  |  | 411 |  |  | 235 |
|  | 4,877 |  |  | 5,555 |  |  | 5,693 |
less: |  |  |  |  |  |  |  |  |
- capitalized direct costs associated with self-constructed assets - tangible assets |  | (182 | ) |  | (194 | ) |  | (295 | )
- capitalized direct costs associated with self-constructed assets - intangible assets |  | (55 | ) |  | (60 | ) |  | (61 | )
|  | 4,640 |  |  | 5,301 |  |  | 5,337 |

Other costs of euro 235 million (euro 184 million and euro 411 million in 2012 and 2013, respectively) comprised provisions for redundancy incentives of euro 10 million (euro 64 million and euro 279 million in 2012 and 2013, respectively) and costs for defined contribution plans of euro 110 million (euro 100 million and euro 109 million in 2012 and 2013, respectively).

Cost related to employee benefit plans are described in note 30 – Provisions for employee benefits.

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Average number of employees
The Group average number and breakdown of employees by category is reported below:

(number) |  | 2012 |  | 2013 |  | 2014

|  | Subsidiaries |  | Joint operations |  | Subsidiaries |  | Joint operations |  | Subsidiaries |  | Joint operations

Senior managers |  | 1,463 |  | 37 |  | 1,466 |  | 38 |  | 1,467 |  | 27
Junior managers |  | 12,936 |  | 143 |  | 13,368 |  | 156 |  | 13,727 |  | 136
Employees |  | 37,135 |  | 824 |  | 39,067 |  | 860 |  | 40,052 |  | 633
Workers |  | 23,427 |  | 805 |  | 25,882 |  | 809 |  | 27,545 |  | 559
|  | 74,961 |  | 1,809 |  | 79,783 |  | 1,863 |  | 82,791 |  | 1,355

The average number of employees was calculated as the average between the number of employees at the beginning and 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 status.

Stock-based compensation
In 2009, Eni suspended the incentive plan based on the stock option assignment to managers of Eni and its subsidiaries as defined in Article 2359 of the Italian Civil Code.

Following the expiring of the options relating to the assignment 2008 of the Stock Option Plan 2006-2008, at December 31, 2014, there are no stock option plans still outstanding.

The scheme evolution is provided below:

|  | 2012 |  | 2013 |  | 2014

|  | Number of shares |  | Average strike price (euro) |  | Market price (a) (euro) |  | Number of shares |  | Average strike price (euro) |  | Market price (a) (euro) |  | Number of shares |  | Average strike price (euro) |  | Market price (a) (euro)

Rights outstanding as of January 1 |  | 11,873,205 |  |  | 23.101 |  | 15.941 |  | 8,259,520 |  |  | 23.545 |  | 18.457 |  | 2,980,725 |  |  | 22.540 |  | 17.533
Rights exercised in the period |  | (93,000 | ) |  | 16.576 |  | 16.873 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rights cancelled in the period |  | (3,520,685 | ) |  | 22.233 |  | 16.637 |  | (5,278,795 | ) |  | 24.112 |  | 16.278 |  | (2,980,725 | ) |  | 22.540 |  | 19.766
Rights outstanding as of December 31 |  | 8,259,520 |  |  | 23.545 |  | 18.457 |  | 2,980,725 |  |  | 22.540 |  | 17.533 |  |  |  |  |  |  |
of which exercisable as of December 31 |  | 8,243,205 |  |  | 23.544 |  | 18.457 |  | 2,969,450 |  |  | 22.540 |  | 17.533 |  |  |  |  |  |  |

(a) |  | Market price relating to new rights granted, rights exercised in the period and rights cancelled in the period corresponds to the average market value (arithmetic average of official prices recorded on Mercato Telematico Azionario in the month preceding: (i) the date of the Board of Directors resolution regarding the stock option assignment; (ii) the date on which the emission/transfer of the shares granted were recorded in the grantee’s securities account; and (iii) the date of the unilateral termination of employment for rights cancelled), weighted with the number of shares. Market price of stock at the beginning and end of the year is the price recorded at December 31.

In 2012, 2013 and 2014, no costs were recognized relating to the relevant stock option plans.

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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 amounted (including contributions and ancillary costs) to euro 40 million, euro 38 million and euro 43 million for 2012, 2013 and 2014, respectively, and consisted of the following:

(euro million) |  | 2012 |  | 2013 |  | 2014

Wages and salaries |  | 24 |  | 25 |  | 25
Post-employment benefits |  | 1 |  | 2 |  | 2
Other long-term benefits |  | 12 |  | 11 |  | 10
Indemnities upon termination of employment |  | 3 |  |  |  | 6
|  | 40 |  | 38 |  | 43

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 13.2 million, euro 11.4 million and euro 10.1 million for 2012, 2013 and 2014, respectively.

Compensation of Statutory Auditors amounted to euro 0.467 million, euro 0.474 million and euro 0.419 million in 2012, 2013 and 2014, respectively.

Compensations 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 cost to the Group, even if not subjected to personal income tax.

Other operating income (loss)
The analysis of net income (loss) on financial derivatives was as follows:

(euro million) |  | 2012 |  | 2013 |  | 2014

Net income (loss) on cash flow hedging derivatives |  | (1 | ) |  | 25 |  |  | (133 | )
Net income (loss) on other derivatives |  | (157 | ) |  | (96 | ) |  | 278 |
|  | (158 | ) |  | (71 | ) |  | 145 |

Net losses on cash flow hedging derivatives related to the ineffective portion of the hedging relationship of commodity derivatives which was recognized through profit and loss in the Gas & Power segment.

Net income (loss) on other derivatives related to: (i) gains and losses on fair value measurement and settlement of commodity derivatives entered into by the Gas & Power segment to optimize commercial margins and for proprietary trading (net income of euro 27 million in 2014, net loss of euro 17 million and euro 8 million in 2012 and 2013, respectively); (ii) gains and losses on 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 (net income of euro 220 million in 2014, net loss of euro 141 million and euro 91 million in 2012 and 2013, respectively); and (iii) fair value measurement at certain derivatives embedded in the pricing formulas of long-term gas supply contracts in the Exploration & Production segment (net income of euro 1 million, euro 3 million and euro 31 million in 2012, 2013 and 2014, respectively).

Operating costs are disclosed in note 44 – Transactions with related parties.

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Depreciation, depletion, amortization and impairments

(euro million) |  | 2012 |  | 2013 |  | 2014

Depreciation, depletion and amortization: |  |  |  |  |  |  |  |  |
- tangible assets |  | 7,443 |  |  | 7,454 |  |  | 8,187 |
- intangible assets |  | 2,207 |  |  | 1,976 |  |  | 1,789 |
|  | 9,650 |  |  | 9,430 |  |  | 9,976 |
Impairments: |  |  |  |  |  |  |  |  |
- tangible assets |  | 1,600 |  |  | 2,116 |  |  | 1,540 |
- intangible assets |  | 2,375 |  |  | 507 |  |  | 53 |
|  | 3,975 |  |  | 2,623 |  |  | 1,593 |
less: |  |  |  |  |  |  |  |  |
- reversal of impairments - tangible assets |  | (3 | ) |  | (223 | ) |  | (64 | )
- capitalized direct costs associated with self-constructed assets - tangible assets |  | (1 | ) |  | (3 | ) |  | (2 | )
- capitalized direct costs associated with self-constructed assets - intangible assets |  | (4 | ) |  | (6 | ) |  | (4 | )
|  | 13,617 |  |  | 11,821 |  |  | 11,499 |

Depreciation, depletion, amortization and impairments by industry segment are disclosed in note 43 – Information by industry segment and by geographical area.
39 Finance income (expense)

(euro million) |  | 2012 |  | 2013 |  | 2014

Finance income (expense) |  |  |  |  |  |  |  |  |
Finance income |  | 7,208 |  |  | 5,732 |  |  | 6,459 |
Finance expense |  | (8,327 | ) |  | (6,653 | ) |  | (7,710 | )
Net finance income from financial assets held for trading |  |  |  |  | 4 |  |  | 24 |
|  | (1,119 | ) |  | (917 | ) |  | (1,227 | )
Income (expense) from derivative financial instruments |  | (252 | ) |  | (92 | ) |  | 162 |
|  | (1,371 | ) |  | (1,009 | ) |  | (1,065 | )

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The breakdown by lenders or type of net finance income or expense is provided below:

(euro million) |  | 2012 |  | 2013 |  | 2014

Finance income (expense) related to net borrowings |  |  |  |  |  |  |  |  |
Interest and other finance expense on ordinary bonds |  | (729 | ) |  | (742 | ) |  | (759 | )
Interest due to banks and other financial institutions |  | (257 | ) |  | (181 | ) |  | (163 | )
Interest and other income from financial receivables and securities held for non-operating purposes |  | 24 |  |  | 49 |  |  | 28 |
Interest from banks |  | 28 |  |  | 43 |  |  | 26 |
Net finance income from financial assets held for trading |  |  |  |  | 4 |  |  | 24 |
|  | (934 | ) |  | (827 | ) |  | (844 | )
Exchange differences |  |  |  |  |  |  |  |  |
Positive exchange differences |  | 7,015 |  |  | 5,485 |  |  | 6,177 |
Negative exchange differences |  | (6,884 | ) |  | (5,448 | ) |  | (6,427 | )
|  | 131 |  |  | 37 |  |  | (250 | )
Other finance income (expense) |  |  |  |  |  |  |  |  |
Capitalized finance expense |  | 150 |  |  | 170 |  |  | 163 |
Interest and other income on financing receivables and securities held for operating purposes |  | 54 |  |  | 61 |  |  | 74 |
Finance expense due to the passage of time (accretion discount) (a) |  | (308 | ) |  | (240 | ) |  | (293 | )
Other finance income (expense) |  | (212 | ) |  | (118 | ) |  | (77 | )
|  | (316 | ) |  | (127 | ) |  | (133 | )
|  | (1,119 | ) |  | (917 | ) |  | (1,227 | )

(a) |  | The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities.

Derivative financial instruments consisted of the following:

(euro million) |  | 2012 |  | 2013 |  | 2014

Options |  | (26) |  | (41 | ) |  | 68
Derivatives on exchange rate |  | (138) |  | (91 | ) |  | 48
Derivatives on interest rate |  | (88) |  | 40 |  |  | 46
|  | (252) |  | (92 | ) |  | 162

Net profit from derivatives of euro 162 million (a net loss of euro 252 million and euro 92 million in 2012 and 2013, respectively) were 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 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. Income on options of euro 68 million (loss of euro 26 million and euro 41 million in 2012 and 2013, respectively) related to the measurement at fair value of the options embedded in the bonds convertible into ordinary shares of Galp Energia SGPS SA for euro 45 million (loss for euro 26 million in 2012 and income for euro 14 million in 2013) and Snam SpA for euro 23 million (net loss for euro 55 million in 2013) following the reduction of the liability recognized in the previous year that was due because the options are reaching their deadline and the market price of the shares is making the options out-of-the-money.

More information is provided in note 44 – Transactions with related parties.

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40 Income (expense) from investments
Share of profit (loss) of equity-accounted investments

(euro million) |  | 2012 |  | 2013 |  | 2014

Share of profit from equity-accounted investments |  | 451 |  |  | 313 |  |  | 215 |
Share of loss from equity-accounted investments |  | (250 | ) |  | (105 | ) |  | (86 | )
Decreases (increases) in the provision for losses on investments |  | (15 | ) |  | 14 |  |  | (8 | )
|  | 186 |  |  | 222 |  |  | 121 |

More information is provided in note 19 – Investments.

Share of profit (loss) of equity accounted investments by industry segment is disclosed in note 43 – Information by industry segment and by geographical area.

Other gain (loss) from investments

(euro million) |  | 2012 |  | 2013 |  | 2014

Dividends |  | 431 |  | 400 |  | 385 |
Net gains on disposals |  | 349 |  | 3,598 |  | 163 |
Other net income (expense) |  | 1,823 |  | 1,865 |  | (179 | )
|  | 2,603 |  | 5,863 |  | 369 |

In 2014, dividend income for euro 385 million related to the Nigeria LNG Ltd (euro 247 million), Snam SpA (euro 43 million) and Galp Energia SGPS SA (euro 22 million). In 2013, dividend income for euro 400 million primarily related to the Nigeria LNG Ltd (euro 224 million), Snam SpA (euro 72 million) and Galp Energia SGPS SA (euro 43 million). In 2012, dividend income for euro 431 million primarily related to the Nigeria LNG Ltd (euro 331 million).

Net gains on disposals for 2014 amounted to euro 163 million and related: (i) for euro 96 million to the sale of a 8.15% of the share capital of Galp Energia SGPS SA, of which euro 77 million related to the reversal of the reserve for fair value measurement; (ii) for euro 54 million to the sale of a 20% (entire stake owned) of the share capital of South Stream Transport BV to Gazprom; and (iii) for euro 9 million to the sale of a 50% (entire stake own) of the share capital of EnBW Eni Verwaltungsgesellschaft mbH to EnBW Energie Baden-Württemberg AG. Net gains on disposals for 2013 amounted to euro 3,598 million and related: (i) for euro 3,359 million to the sale of a 28.57% interest in the share capital of Eni East Africa SpA to China National Petroleum Corp (CNPC). Eni East Africa is the operator of the discovery Area 4 in Mozambique. Through its equity investment in Eni East Africa, CNPC indirectly acquired a 20% interest in Area 4, while Eni retained the 50% interest through the remaining controlling stake in Eni East Africa SpA; (ii) for euro 98 million to the sale of a 8.19% of the share capital of Galp Energia SGPS SA, of which euro 67 million related to the reversal of the reserve for fair value measurement; (iii) for euro 75 million to the sale of a 11.69% of the share capital of Snam SpA, of which euro 8 million related to the reversal of the reserve for fair value measurement; and (iv) for euro 63 million to the sale of a 49% (entire stake own) of the share capital of Super Octanos CA. Net gains on disposals for 2012 amounted to euro 349 million and related for euro 311 million to Galp Energia SGPS SA as Eni divested 5% of the share capital of the investee to Amorim Energia BV and a further 4% through an accelerated book-building procedure to institutional investors. More information is provided in note 19 – Investments.

In 2014, other net expense of euro 179 million included the re-measurement at market fair value at the balance sheet date of 66.3 million of Galp Energia SGPS SA (loss for euro 231 million at the price of euro 8.43 per share) and of 288.7 million shares of Snam SpA (income for euro 10 million at the price of euro 4.1 per share underlying two convertible bonds). The valuation of these bonds was based on the fair value option provided by IAS 39. In 2013, other net income of euro 1,865 million included: (i) the revaluation of the 60% stake in Artic Russia BV (entire stake owned). At the balance sheet date, Eni’s interest in Artic Russia was classified as an asset held for sale and measured at fair value due to the loss of joint control over the investee following the satisfaction, before year end, of all conditions precedent to the Sale and Purchase Agreement signed with Gazprom in November 2013. The re-measurement at fair value recorded to profit amounted to euro 1,682 million. The consideration for the disposal

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was cashed in on January 2014; and (ii) the re-measurement at market fair value of 288.7 million shares of Snam SpA and of 66.3 million of Galp Energia SGPS SA underlying two convertible bonds issued on January 18, 2013 and on November 30, 2012, respectively, for which was applied the fair value option (income for euro 158 million and euro 10 million, respectively). In 2012, other net income of euro 1,823 million included: (i) an extraordinary income of euro 835 million recognized in connection with a capital increase made by Galp’s subsidiary Petrogal whereby a new shareholder subscribed its share by contributing a cash amount fairly in excess of the net book value of the interest acquired; (ii) a revaluation gain of euro 865 million of the interest in Galp Energia SGPS SA (28.34%) measured at fair value at the price current at the date when Eni ceased to retain a significant influence over the investee and a gain on the re-measurement at market fair value at the balance sheet date of euro 65 million of part of residual interest in Galp Energia SGPS SA (8%) which was underlying a convertible bond based on the fair value option provided by IAS 39; and (iii) the re-measurement at market fair value at the balance sheet date of 288.7 million shares of Snam SpA underlying a convertible bond issued on January 18, 2013 for which was applied the fair value option (income for euro 6 million). More information is provided in note 19 – Investments.

41 Income taxes

(euro million) |  | 2012 |  | 2013 |  | 2014

Current taxes: |  |  |  |  |  |  |  |  |
- Italian subsidiaries |  | 751 |  |  | 806 |  |  | (541 | )
- subsidiaries of the Exploration & Production segment - outside Italy |  | 10,214 |  |  | 7,602 |  |  | 6,512 |
- other subsidiaries - outside Italy |  | 464 |  |  | 312 |  |  | 313 |
|  | 11,429 |  |  | 8,720 |  |  | 6,284 |
Net deferred taxes: |  |  |  |  |  |  |  |  |
- Italian subsidiaries |  | 373 |  |  | (198 | ) |  | 314 |
- subsidiaries of the Exploration & Production segment - outside Italy |  | 129 |  |  | 756 |  |  | 128 |
- other subsidiaries - outside Italy |  | (252 | ) |  | (273 | ) |  | (234 | )
|  | 250 |  |  | 285 |  |  | 208 |
|  | 11,679 |  |  | 9,005 |  |  | 6,492 |

Tax gain on income taxes currently payable by Italian subsidiaries of euro 541 million were in respect of the Italian corporate taxation (tax gain for IRES of euro 735 million and tax loss for IRAP of euro 37 million) and foreign taxes on the share of profit earned outside Italy (tax loss of euro 157 million). The tax gain for IRES of euro 735 million includes a tax gain of euro 824 million due to the settlement of a tax dispute with the Italian Fiscal Authorities regarding how to determine a tax surcharge of 4% due by the parent company Eni SpA as provided by Law No. 7/2009 (the so-called Libyan tax) since 2009.

The effective tax rate was 88.4% (70.2% and 64.5% in 2012 and 2013, respectively) compared with a statutory tax rate of 33.4% (44.0% and 43.2% in 2012 and 2013, respectively). This was calculated by applying the Italian statutory tax rate on corporate profit of 27.5% (38.0%21 in 2012 and 2013, respectively) and a 3.9% (same rate in 2012 and 2013) corporate tax rate applicable to the net value of production as provided for by Italian laws.

(21) |  | Includes a 5.5% supplemental tax rate on taxable profit of energy companies in Italy effective from January 1, 2008 and further increases of 1% effective from January 1, 2009, pursuant to the Law Decree No. 112/2008 (converted into Law No. 133/2008) and 4% effective from January 1, 2011, pursuant the Law Decree No. 138/2011 (converted into Law No. 148/2011) which enlarged the scope of application to include renewable energy companies and gas transport and distribution companies. These supplemental tax rates are not applicable to Eni SpA in 2014. The Robin Tax was assessed to be no more recoverable as, on February 2015, the Italian Constitutional Court stated the illegitimacy of this tax prospectively, denying any reimbursement right.

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The difference between the statutory and effective tax rate was due to the following factors:

(%) |  | 2012 |  | 2013 |  | 2014

Statutory tax rate |  | 44.0 |  | 43.2 |  |  | 33.4 |
Items increasing (decreasing) statutory tax rate: |  |  |  |  |  |  |  |
- higher tax rate related to subsidiaries outside Italy |  | 16.8 |  | 16.0 |  |  | 50.7 |
- impact pursuant to the write-off of deferred tax assets and recalculation of tax rates |  | 7.6 |  | 8.9 |  |  | 13.7 |
- impact pursuant to the application of the Italian Windfall Corporate tax as per Law No. 7/2009 |  | 1.5 |  | 1.3 |  |  |  |
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law No. 7/2009 |  |  |  |  |  |  | (11.2 | )
- permanent differences and other adjustments |  | 0.3 |  | (4.9 | ) |  | 1.8 |
|  | 26.2 |  | 21.3 |  |  | 55.0 |
|  | 70.2 |  | 64.5 |  |  | 88.4 |

In 2014, the increased tax rate at foreign subsidiaries primarily related to 49.2 percentage points in the Exploration & Production segment (17.8 and 14.9 percentage points in 2012 and 2013, respectively).

A write down of deferred tax assets impacted the Group tax rate by 13.7 percentage points related to the write-off of deferred tax assets of Italian subsidiaries which were assessed to be no more recoverable due to the projections of lower future taxable profit (euro 500 million equal to 6.8 percentage points) 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, on February 2015, the Italian Court stated the illegitimacy of this tax (euro 476 million, equal to 6.5 percentage points). Such sentence stated the illegitimacy of a tax rule prospectively, denying any reimbursement right.

In 2014, the increase due to permanent differences and other adjustments of 1.8 percentage points comprised the effect of 0.7 percentage points due to the taxation of intragroup dividends. In 2013, the decrease due to permanent differences and other adjustments of 4.9 percentage points comprised an effect of 6.6 percentage points due to non-taxable gains on sale relating to the transactions of the 28.57% at Eni East Africa SpA and an effect of 0.9 percentage points due to non-taxable gains on sale and revaluation relating to the transactions at Galp Energia SGPS SA and Snam SpA. Such decrease was partially offset by an effect of 1.0 percentage points due to a non-deductible impairment of the goodwill allocated to the European gas market CGU and an effect of 0.8 percentage points due to the tax regime provided for intercompany dividends. In 2012, the increase due to permanent differences and other adjustments of 0.3 percentage points comprised an effect of 3.3 percentage points due to a non-deductible impairment of the goodwill allocated to the European gas market CGU and a negative effect of 4.5 percentage points due to non-taxable gains on the sale and revaluation relating to the transactions at Galp Energia SGPS SA.

42 Earnings per share
Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.

The average number of ordinary shares used for the calculation of the basic earnings per share outstanding at December 31, 2012, 2013 and 2014 was 3,622,764,007, 3,622,797,043 and 3,610,387,582, respectively.

Diluted earnings per share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of shares fully diluted including shares outstanding in the year, excluding treasury shares, including the number of potential shares outstanding in connection with stock-based compensation plans.

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As of December 31, 2012, 2013 and 2014, there were no shares that could be potentially issued and, therefore, the weighted average number of shares used in the calculation of the basic earnings coincides to the weighted average number of shares used in the calculation of diluted earnings.

|  | 2012 |  | 2013 |  | 2014

Average number of shares used for the calculation of the basic and diluted earnings per share |  |  |  | 3,622,764,007 |  | 3,622,797,043 |  | 3,610,387,582
Eni’s net profit |  | (euro million) |  | 7,790 |  | 5,160 |  | 1,291
Basic and diluted earning per share |  | (euro per share) |  | 2.15 |  | 1.42 |  | 0.36
Eni’s net profit - Continuing operations |  | (euro million) |  | 4,200 |  | 5,160 |  | 1,291
Basic and diluted earning per share |  | (euro per share) |  | 1.16 |  | 1.42 |  | 0.36
Eni’s net profit - Discontinued operations |  | (euro million) |  | 3,590 |  |  |  |
Basic and diluted earning per share |  | (euro per share) |  | 0.99 |  |  |  |

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43 Information by industry segment and by geographical area
Information by industry segment

|  | Other activities (d) |  | Discontinued operation s (d) |  |

(euro million) |  | `Exploration & Production` |  | `Gas & Power``` `(d)` |  | `Refining & Marketing` |  | `Versalis` |  | `Engineering & Construction` |  | `Corporate and financial companies` |  | `Snam` |  | `Others` |  | `Intragroup profits` |  | `Total` |  | `Snam` |  | `Intragroup eliminations` |  | `Continuing operations`

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from operations (a) |  | 35,874 |  |  | 36,198 |  |  | 62,531 |  |  | 6,418 |  |  | 12,799 |  |  | 1,369 |  |  | 2,646 |  |  | 119 |  |  | (75 | ) |  |  |  |  |  |  |  |  |  |
Less: intersegment sales |  | (20,322 | ) |  | (2,038 | ) |  | (2,962 | ) |  | (411 | ) |  | (1,109 | ) |  | (1,242 | ) |  | (1,274 | ) |  | (40 | ) |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales to customers |  | 15,552 |  |  | 34,160 |  |  | 59,569 |  |  | 6,007 |  |  | 11,690 |  |  | 127 |  |  | 1,372 |  |  | 79 |  |  | (75 | ) |  | 128,481 |  |  | (1,372 | ) |  |  |  | 127,109
Operating profit |  | 18,470 |  |  | (3,125 | ) |  | (1,264 | ) |  | (681 | ) |  | 1,453 |  |  | (341 | ) |  | 1,679 |  |  | (300 | ) |  | 208 |  |  | 16,099 |  |  | (1,679 | ) |  | 788 |  | 15,208
Provisions for contingencies |  | 40 |  |  | 457 |  |  | 93 |  |  | 22 |  |  | 36 |  |  | 140 |  |  | 72 |  |  | 68 |  |  |  |  |  | 928 |  |  | (72 | ) |  |  |  | 856
Depreciation, amortization and impairments |  | 8,532 |  |  | 2,923 |  |  | 1,209 |  |  | 202 |  |  | 708 |  |  | 65 |  |  | 284 |  |  | 3 |  |  | (25 | ) |  | 13,901 |  |  | (284 | ) |  |  |  | 13,617
Share of profit (loss) of equity-accounted investments |  | 39 |  |  | 81 |  |  | 20 |  |  | 2 |  |  | 46 |  |  | (1 | ) |  | 38 |  |  | (1 | ) |  |  |  |  | 224 |  |  | (38 | ) |  |  |  | 186
Identifiable assets (b) |  | 59,225 |  |  | 20,696 |  |  | 15,266 |  |  | 3,151 |  |  | 14,402 |  |  | 966 |  |  |  |  |  | 474 |  |  | (776 | ) |  | 113,404 |  |  |  |  |  |  |  |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 26,788 |  |  |  |  |  |  |  |
Equity-accounted investments |  | 2,159 |  |  | 951 |  |  | 72 |  |  | 50 |  |  | 179 |  |  | 6 |  |  |  |  |  | 36 |  |  |  |  |  | 3,453 |  |  |  |  |  |  |  |
Identifiable liabilities (c) |  | 16,147 |  |  | 10,802 |  |  | 6,361 |  |  | 750 |  |  | 5,229 |  |  | 1,187 |  |  |  |  |  | 2,954 |  |  | 21 |  |  | 43,451 |  |  |  |  |  |  |  |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 34,324 |  |  |  |  |  |  |  |
Capital expenditures |  | 10,307 |  |  | 213 |  |  | 898 |  |  | 172 |  |  | 1,011 |  |  | 152 |  |  | 756 |  |  | 14 |  |  | 38 |  |  | 13,561 |  |  |  |  |  |  |  |
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from operations (a) |  | 31,264 |  |  | 32,212 |  |  | 57,238 |  |  | 5,859 |  |  | 11,598 |  |  | 1,453 |  |  |  |  |  | 80 |  |  | 18 |  |  |  |  |  |  |  |  |  |  |
Less: intersegment sales |  | (18,218 | ) |  | (1,225 | ) |  | (2,897 | ) |  | (289 | ) |  | (1,018 | ) |  | (1,339 | ) |  |  |  |  | (39 | ) |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales to customers |  | 13,046 |  |  | 30,987 |  |  | 54,341 |  |  | 5,570 |  |  | 10,580 |  |  | 114 |  |  |  |  |  | 41 |  |  | 18 |  |  | 114,697 |  |  |  |  |  |  |  |
Operating profit |  | 14,868 |  |  | (2,967 | ) |  | (1,492 | ) |  | (725 | ) |  | (98 | ) |  | (399 | ) |  |  |  |  | (337 | ) |  | 38 |  |  | 8,888 |  |  |  |  |  |  |  |
Provisions for contingencies |  | 61 |  |  | 314 |  |  | 100 |  |  | 65 |  |  | 76 |  |  | 178 |  |  |  |  |  | 77 |  |  | (21 | ) |  | 850 |  |  |  |  |  |  |  |
Depreciation, amortization and impairments |  | 7,829 |  |  | 2,098 |  |  | 978 |  |  | 139 |  |  | 721 |  |  | 61 |  |  |  |  |  | 20 |  |  | (25 | ) |  | 11,821 |  |  |  |  |  |  |  |
Share of profit (loss) of equity-accounted investments |  | 129 |  |  | 71 |  |  | 5 |  |  |  |  |  | 2 |  |  | 7 |  |  |  |  |  | 8 |  |  |  |  |  | 222 |  |  |  |  |  |  |  |
Identifiable assets (b) |  | 59,784 |  |  | 18,205 |  |  | 15,013 |  |  | 3,169 |  |  | 14,208 |  |  | 968 |  |  |  |  |  | 255 |  |  | (793 | ) |  | 110,809 |  |  |  |  |  |  |  |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 27,532 |  |  |  |  |  |  |  |
Equity-accounted investments |  | 1,730 |  |  | 999 |  |  | 74 |  |  | 148 |  |  | 166 |  |  |  |  |  |  |  |  | 36 |  |  |  |  |  | 3,153 |  |  |  |  |  |  |  |
Identifiable liabilities (c) |  | 15,608 |  |  | 10,182 |  |  | 6,079 |  |  | 844 |  |  | 5,517 |  |  | 1,606 |  |  |  |  |  | 2,740 |  |  | (86 | ) |  | 42,490 |  |  |  |  |  |  |  |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 34,802 |  |  |  |  |  |  |  |
Capital expenditures |  | 10,475 |  |  | 229 |  |  | 672 |  |  | 314 |  |  | 902 |  |  | 190 |  |  |  |  |  | 21 |  |  | (3 | ) |  | 12,800 |  |  |  |  |  |  |  |
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from operations (a) |  | 28,488 |  |  | 28,250 |  |  | 56,153 |  |  | 5,284 |  |  | 12,873 |  |  | 1,378 |  |  |  |  |  | 78 |  |  | 54 |  |  |  |  |  |  |  |  |  |  |
Less: intersegment sales |  | (16,618 | ) |  | (1,103 | ) |  | (2,196 | ) |  | (253 | ) |  | (1,244 | ) |  | (1,250 | ) |  |  |  |  | (47 | ) |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales to customers |  | 11,870 |  |  | 27,147 |  |  | 53,957 |  |  | 5,031 |  |  | 11,629 |  |  | 128 |  |  |  |  |  | 31 |  |  | 54 |  |  | 109,847 |  |  |  |  |  |  |  |
Operating profit |  | 10,766 |  |  | 186 |  |  | (2,229 | ) |  | (704 | ) |  | 18 |  |  | (246 | ) |  |  |  |  | (272 | ) |  | 398 |  |  | 7,917 |  |  |  |  |  |  |  |
Provisions for contingencies |  | 29 |  |  | (26 | ) |  | 124 |  |  | 28 |  |  | 154 |  |  | 138 |  |  |  |  |  | 50 |  |  | (3 | ) |  | 494 |  |  |  |  |  |  |  |
Depreciation, amortization and impairments |  | 9,163 |  |  | 359 |  |  | 567 |  |  | 195 |  |  | 1,157 |  |  | 69 |  |  |  |  |  | 15 |  |  | (26 | ) |  | 11,499 |  |  |  |  |  |  |  |
Share of profit (loss) of equity-accounted investments |  | 52 |  |  | 42 |  |  | 8 |  |  | (4 | ) |  | 21 |  |  |  |  |  |  |  |  | 2 |  |  |  |  |  | 121 |  |  |  |  |  |  |  |
Identifiable assets (b) |  | 68,113 |  |  | 16,603 |  |  | 12,993 |  |  | 3,059 |  |  | 14,210 |  |  | 1,042 |  |  |  |  |  | 258 |  |  | (486 | ) |  | 115,792 |  |  |  |  |  |  |  |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 30,415 |  |  |  |  |  |  |  |
Equity-accounted investments |  | 1,959 |  |  | 772 |  |  | 73 |  |  | 155 |  |  | 120 |  |  |  |  |  |  |  |  | 36 |  |  |  |  |  | 3,115 |  |  |  |  |  |  |  |
Identifiable liabilities (c) |  | 19,152 |  |  | 10,267 |  |  | 5,269 |  |  | 698 |  |  | 6,171 |  |  | 1,243 |  |  |  |  |  | 2,660 |  |  | (165 | ) |  | 45,295 |  |  |  |  |  |  |  |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 38,703 |  |  |  |  |  |  |  |
Capital expenditures |  | 10,524 |  |  | 172 |  |  | 537 |  |  | 282 |  |  | 694 |  |  | 83 |  |  |  |  |  | 30 |  |  | (82 | ) |  | 12,240 |  |  |  |  |  |  |  |

(a) |  | Before elimination of intersegment sales.
(b) |  | Includes assets directly associated with the generation of operating profit.
(c) |  | Includes liabilities directly associated with the generation of operating profit.
(d) |  | The results of Snam has been reclassified from the "Gas & Power" segment to the "Other activities" segment and presented in the discontinued operations.

The new provisions of IAS 19, IFRS 10 and IFRS 11 were applied retrospectively by adjusting the opening balance sheet as of January 1, 2012 and the 2012 profit and loss account.

Environmental provisions incurred by Eni SpA due to intercompany guarantees on behalf of Syndial have been reported within the segment reporting unit "Other activities".

Intersegment revenues are conducted on an arm’s length basis.

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Financial information by geographical area
Identifiable assets and investments by geographical area of origin

(euro million) |  |  |  | Italy |  | Other European Union |  | Rest of Europe |  | Americas |  | Asia |  | Africa |  | Other areas |  | Total

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Identifiable assets (a) |  | 31,424 |  | 15,288 |  | 11,084 |  | 7,207 |  | 14,828 |  | 31,699 |  | 1,874 |  | 113,404
Capital expenditures in tangible and intangible assets |  | 2,926 |  | 1,263 |  | 1,626 |  | 1,184 |  | 1,663 |  | 4,725 |  | 174 |  | 13,561
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Identifiable assets (a) |  | 28,619 |  | 14,513 |  | 7,992 |  | 8,683 |  | 17,921 |  | 31,300 |  | 1,781 |  | 110,809
Capital expenditures in tangible and intangible assets |  | 2,044 |  | 1,089 |  | 1,553 |  | 1,506 |  | 1,799 |  | 4,556 |  | 253 |  | 12,800
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Identifiable assets (a) |  | 26,516 |  | 15,086 |  | 8,703 |  | 8,456 |  | 20,424 |  | 34,868 |  | 1,739 |  | 115,792
Capital expenditures in tangible and intangible assets |  | 1,785 |  | 853 |  | 1,407 |  | 1,196 |  | 1,974 |  | 4,864 |  | 161 |  | 12,240

(a) |  | Includes assets directly associated with the generation of operating profit.

Sales from operations by geographic area of destination

(euro million) |  | 2012 |  | 2013 |  | 2014

Italy |  | 33,860 |  | 31,949 |  | 29,621
Other European Union |  | 35,909 |  | 31,629 |  | 29,933
Rest of Europe |  | 9,645 |  | 11,462 |  | 12,434
Americas |  | 15,244 |  | 7,752 |  | 8,944
Asia |  | 16,394 |  | 18,608 |  | 16,257
Africa |  | 14,710 |  | 12,073 |  | 11,640
Other areas |  | 1,347 |  | 1,224 |  | 1,018
|  | 127,109 |  | 114,697 |  | 109,847

44 Transactions with related parties In the ordinary course of its business Eni enters into transactions regarding:

(a) |  | exchanges of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries;
(b) |  | exchanges of goods and provision of services with entities controlled by the Italian Government;
(c) |  | relations with Vodafone Omnitel BV related to Eni SpA through a member of the Board of Directors pursuant to Consob Regulation dated March 12, 2010 concerning transactions with related parties and the internal procedure of Eni "Transactions involving interests of Directors and Statutory Auditors and transactions with related parties". These transactions, regulated at market conditions, mainly involve costs for mobile communication services for euro 16 million and business collaboration agreements relating to the loyalty program you&eni; and
(d) |  | contributions to entities with a non-company form 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.

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Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities with the aim to develop solidarity, culture and research initiatives, on arm’s length basis.

Trade and other transactions with related parties

(euro million) |  | Dec. 31, 2012 |  | 2012

| Costs |  | Revenues |  |

Name |  | Receivables and other assets |  | Payables and other liabilities |  | Guarantees |  | Goods |  | Services |  | Other |  | Goods |  | Services |  | Other |  | Other operating (expense) income

Continuing operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ACAM Clienti SpA |  | 19 |  | 1 |  | 2 |  |  |  |  |  |  |  | 65 |  | 1 |  |  |  |  |
Agiba Petroleum Co |  | 3 |  | 67 |  |  |  |  |  | 96 |  |  |  |  |  |  |  |  |  |  |
Azienda Energia e Servizi Torino SpA |  |  |  |  |  |  |  |  |  | 86 |  |  |  |  |  |  |  |  |  |  |
Bronberger & Kessler und |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gilg & Schweiger GmbH & Co KG |  | 9 |  |  |  |  |  |  |  |  |  |  |  | 84 |  |  |  |  |  |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Due |  | 51 |  | 51 |  |  |  |  |  | 51 |  |  |  |  |  | 85 |  |  |  |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Uno |  | 66 |  | 19 |  | 6,122 |  |  |  | 5 |  |  |  |  |  | 16 |  |  |  |  |
EnBW Eni Verwaltungsgesellschaft mbH |  | 60 |  |  |  |  |  |  |  |  |  |  |  | 287 |  |  |  |  |  |  |
Gaz de Bordeaux SAS |  |  |  |  |  |  |  |  |  |  |  |  |  | 56 |  |  |  |  |  |  |
InAgip doo |  | 54 |  | 10 |  |  |  |  |  | 24 |  |  |  | 53 |  | 1 |  |  |  |  |
Karachaganak Petroleum Operating BV |  | 28 |  | 56 |  |  |  | 1,331 |  | 244 |  | 14 |  | 5 |  | 8 |  |  |  |  |
KWANDA - Suporte Logistico Lda |  | 54 |  | 1 |  |  |  |  |  | 2 |  |  |  |  |  | 7 |  |  |  |  |
Mellitah Oil & Gas BV |  | 7 |  | 47 |  |  |  |  |  | 166 |  |  |  | 5 |  | 12 |  |  |  |  |
Petrobel Belayim Petroleum Co |  | 31 |  | 328 |  |  |  |  |  | 585 |  |  |  |  |  | 79 |  |  |  |  |
Toscana Energia SpA |  |  |  |  |  |  |  |  |  | 86 |  |  |  |  |  |  |  | 1 |  |  |
Unión Fenosa Gas SA |  | 2 |  | 3 |  | 57 |  |  |  |  |  | 6 |  | 120 |  |  |  | 1 |  |  |
Other (*) |  | 239 |  | 94 |  | 73 |  | 45 |  | 420 |  | 11 |  | 229 |  | 121 |  | 8 |  |  |
|  | 623 |  | 677 |  | 6,254 |  | 1,376 |  | 1,765 |  | 31 |  | 904 |  | 330 |  | 10 |  |  |
Unconsolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agip Kazakhstan North Caspian Operating Co NV |  | 236 |  | 172 |  |  |  |  |  | 605 |  | 2 |  |  |  | 1,064 |  | 5 |  |  |
Eni BTC Ltd |  |  |  |  |  | 154 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) |  | 54 |  | 3 |  | 4 |  |  |  |  |  |  |  |  |  | 7 |  | 7 |  |  |
Other (*) |  | 14 |  | 59 |  | 2 |  | 7 |  | 50 |  | 4 |  | 17 |  | 3 |  | 7 |  |  |
|  | 304 |  | 234 |  | 160 |  | 7 |  | 655 |  | 6 |  | 17 |  | 1,074 |  | 19 |  |  |
|  | 927 |  | 911 |  | 6,414 |  | 1,383 |  | 2,420 |  | 37 |  | 921 |  | 1,404 |  | 29 |  |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Enel Group |  | 16 |  | 8 |  |  |  | 4 |  | 554 |  |  |  | 55 |  | 90 |  | 1 |  | (7 | )
Finmeccanica Group |  | 22 |  | 47 |  |  |  | 13 |  | 68 |  |  |  | 17 |  |  |  |  |  |  |
Snam Group |  | 182 |  | 482 |  | 46 |  | 13 |  | 558 |  | 2 |  | 102 |  | 26 |  | 1 |  |  |
GSE - Gestore Servizi Energetici |  | 86 |  | 66 |  |  |  | 627 |  |  |  | 58 |  | 777 |  | 18 |  | 12 |  |  |
Terna Group |  | 45 |  | 61 |  |  |  | 156 |  | 126 |  | 12 |  | 87 |  | 67 |  | 14 |  | 17 |
Other (*) |  | 42 |  | 29 |  |  |  |  |  | 59 |  | 3 |  | 57 |  | 1 |  |  |  |  |
|  | 393 |  | 693 |  | 46 |  | 813 |  | 1,365 |  | 75 |  | 1,095 |  | 202 |  | 28 |  | 10 |
Pension funds and foundations |  |  |  | 1 |  |  |  |  |  |  |  | 21 |  |  |  |  |  |  |  |  |
|  | 1,320 |  | 1,605 |  | 6,460 |  | 2,196 |  | 3,785 |  | 133 |  | 2,016 |  | 1,606 |  | 57 |  | 10 |
Discontinued operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Azienda Energia e Servizi Torino SpA |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  | 1 |  |  |
Toscana Energia SpA |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |  |
Other (*) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3 |  | 1 |  |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Enel Group |  |  |  |  |  |  |  |  |  | 87 |  |  |  |  |  | 295 |  |  |  |  |
Other (*) |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  | 3 |  | 1 |  |  |
|  |  |  |  |  |  |  |  |  | 87 |  | 1 |  |  |  | 298 |  | 1 |  |  |
|  |  |  |  |  |  |  |  |  | 87 |  | 1 |  |  |  | 301 |  | 2 |  |  |
|  | 1,320 |  | 1,605 |  | 6,460 |  | 2,196 |  | 3,872 |  | 134 |  | 2,016 |  | 1,907 |  | 59 |  | 10 |

(*) |  | Each individual amount included herein was lower than euro 50 million.

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(euro million) |  | Dec. 31, 2013 |  | 2013

| Costs |  | Revenues |  |

Name |  | Receivables and other assets |  | Payables and other liabilities |  | Guarantees |  | Goods |  | Services |  | Other |  | Goods |  | Services |  | Other |  | Other operating (expense) income

Continuing operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agiba Petroleum Co |  | 1 |  | 69 |  |  |  |  |  | 132 |  |  |  |  |  |  |  |  |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Due |  | 78 |  | 165 |  |  |  |  |  | 127 |  |  |  |  |  | 168 |  |  |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Uno |  | 42 |  | 16 |  | 6,122 |  |  |  | 2 |  |  |  |  |  | 44 |  |  |  |
EnBW Eni Verwaltungsgesellschaft mbH |  | 33 |  |  |  |  |  |  |  |  |  |  |  | 165 |  | 1 |  |  |  |
InAgip doo |  | 57 |  | 22 |  |  |  |  |  | 63 |  |  |  |  |  | 34 |  |  |  |
Karachaganak Petroleum Operating BV |  | 26 |  | 220 |  |  |  | 1,218 |  | 275 |  | 4 |  |  |  | 19 |  |  |  |
KWANDA - Suporte Logistico Lda |  | 55 |  | 5 |  |  |  |  |  | 2 |  | 1 |  |  |  | 6 |  |  |  |
Mellitah Oil & Gas BV |  | 7 |  | 61 |  |  |  | 16 |  | 215 |  |  |  |  |  | 3 |  |  |  |
Petrobel Belayim Petroleum Co |  | 32 |  | 360 |  |  |  |  |  | 570 |  |  |  |  |  | 47 |  |  |  |
Petromar Lda |  | 71 |  | 7 |  | 29 |  |  |  | 6 |  | 1 |  |  |  | 69 |  |  |  |
PetroSucre SA |  | 57 |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |
Unión Fenosa Gas Comercializadora SA |  | 23 |  | 1 |  |  |  |  |  | 1 |  |  |  | 254 |  |  |  |  |  |
Unión Fenosa Gas SA |  | 2 |  | 1 |  | 57 |  |  |  |  |  | 32 |  | 17 |  | 2 |  | 1 |  |
Other (*) |  | 123 |  | 182 |  | 18 |  | 79 |  | 314 |  | 7 |  | 150 |  | 80 |  | 9 |  |
|  | 607 |  | 1,109 |  | 6,226 |  | 1,313 |  | 1,707 |  | 45 |  | 586 |  | 474 |  | 10 |  |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agip Kazakhstan North Caspian Operating Co NV |  | 115 |  | 153 |  |  |  |  |  | 506 |  | 16 |  |  |  | 541 |  | 4 |  |
Eni BTC Ltd |  |  |  |  |  | 147 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) |  | 62 |  | 1 |  | 10 |  |  |  |  |  |  |  |  |  | 2 |  |  |  |
Other (*) |  | 14 |  | 56 |  | 2 |  | 6 |  | 45 |  | 4 |  | 13 |  | 8 |  | 5 |  |
|  | 191 |  | 210 |  | 159 |  | 6 |  | 551 |  | 20 |  | 13 |  | 551 |  | 9 |  |
|  | 798 |  | 1,319 |  | 6,385 |  | 1,319 |  | 2,258 |  | 65 |  | 599 |  | 1,025 |  | 19 |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Enel Group |  | 134 |  | 29 |  |  |  | 2 |  | 848 |  |  |  | 78 |  | 109 |  | 2 |  | 49
Snam Group |  | 337 |  | 564 |  | 13 |  | 38 |  | 2,038 |  | 4 |  | 792 |  | 87 |  | 1 |  |
Terna Group |  | 43 |  | 58 |  |  |  | 124 |  | 149 |  | 13 |  | 118 |  | 38 |  | 2 |  | 19
GSE - Gestore Servizi Energetici |  | 86 |  | 135 |  |  |  | 811 |  |  |  | 96 |  | 265 |  | 21 |  | 9 |  |
Other (*) |  | 47 |  | 70 |  |  |  | 7 |  | 107 |  | 4 |  | 48 |  | 4 |  |  |  |
|  | 647 |  | 856 |  | 13 |  | 982 |  | 3,142 |  | 117 |  | 1,301 |  | 259 |  | 14 |  | 68
Pension funds and foundations |  |  |  | 2 |  |  |  |  |  | 4 |  | 51 |  |  |  |  |  |  |  |
|  | 1,445 |  | 2,177 |  | 6,398 |  | 2,301 |  | 5,404 |  | 233 |  | 1,900 |  | 1,284 |  | 33 |  | 68

(*) |  | Each individual amount included herein was lower than euro 50 million.

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(euro million) |  | Dec. 31, 2014 |  | 2014

| Costs |  | Revenues |  |

Name |  | Receivables and other assets |  | Payables and other liabilities |  | Guarantees |  | Goods |  | Services |  | Other |  | Goods |  | Services |  | Other |  | Other operating (expense) income

Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agiba Petroleum Co |  | 2 |  | 60 |  |  |  |  |  | 169 |  |  |  |  |  |  |  |  |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Due |  | 120 |  | 152 |  |  |  |  |  | 159 |  |  |  |  |  | 216 |  |  |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Uno |  | 23 |  | 12 |  | 6,122 |  |  |  | 3 |  |  |  |  |  | 14 |  |  |  |
EnBW Eni Verwaltungsgesellschaft mbH |  |  |  |  |  |  |  |  |  |  |  |  |  | 134 |  | 2 |  |  |  |
InAgip doo |  | 52 |  | 11 |  |  |  |  |  | 44 |  |  |  | 1 |  | 7 |  |  |  |
Karachaganak Petroleum Operating BV |  | 43 |  | 233 |  |  |  | 1,246 |  | 320 |  | 22 |  |  |  | 20 |  |  |  |
KWANDA - Suporte Logistico Lda |  | 68 |  | 15 |  |  |  |  |  | 10 |  |  |  |  |  | 9 |  |  |  |
Mellitah Oil & Gas BV |  | 98 |  | 58 |  |  |  | 10 |  | 235 |  |  |  |  |  | 7 |  |  |  |
Petrobel Belayim Petroleum Co |  | 32 |  | 375 |  |  |  |  |  | 603 |  |  |  |  |  | 85 |  |  |  |
Petromar Lda |  | 93 |  | 4 |  | 21 |  |  |  | 1 |  | 1 |  |  |  | 61 |  |  |  |
South Stream Transport BV |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 495 |  | 1 |  |
Unión Fenosa Gas Comercializadora SA |  | 15 |  | 1 |  |  |  |  |  |  |  |  |  | 157 |  |  |  |  |  |
Unión Fenosa Gas SA |  |  |  |  |  | 57 |  |  |  | 1 |  | 1 |  |  |  |  |  |  |  |
Other (*) |  | 122 |  | 67 |  |  |  | 17 |  | 182 |  | 18 |  | 95 |  | 92 |  | 15 |  |
|  | 668 |  | 988 |  | 6,200 |  | 1,273 |  | 1,727 |  | 42 |  | 387 |  | 1,008 |  | 16 |  |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agip Kazakhstan North Caspian Operating Co NV |  |  |  |  |  |  |  |  |  | 342 |  | 7 |  |  |  | 187 |  | 2 |  |
Eni BTC Ltd |  |  |  |  |  | 167 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) |  | 61 |  | 1 |  | 10 |  |  |  |  |  |  |  |  |  | 3 |  |  |  |
Other (*) |  | 13 |  | 52 |  | 1 |  |  |  | 13 |  |  |  | 4 |  | 2 |  | 4 |  |
|  | 74 |  | 53 |  | 178 |  |  |  | 355 |  | 7 |  | 4 |  | 192 |  | 6 |  |
|  | 742 |  | 1,041 |  | 6,378 |  | 1,273 |  | 2,082 |  | 49 |  | 391 |  | 1,200 |  | 22 |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Enel Group |  | 156 |  | 122 |  |  |  |  |  | 933 |  |  |  | 181 |  | 133 |  | 1 |  | 183
Snam Group |  | 147 |  | 585 |  | 7 |  | 155 |  | 1,867 |  | 5 |  | 235 |  | 72 |  |  |  | 13
Terna Group |  | 33 |  | 65 |  |  |  | 89 |  | 154 |  | 7 |  | 120 |  | 35 |  | 44 |  | 12
GSE - Gestore Servizi Energetici |  | 88 |  | 124 |  |  |  | 580 |  | 2 |  | 60 |  | 172 |  | 14 |  |  |  |
Other (*) |  | 44 |  | 93 |  |  |  | 8 |  | 111 |  | 3 |  | 45 |  | 6 |  | 2 |  |
|  | 468 |  | 989 |  | 7 |  | 832 |  | 3,067 |  | 75 |  | 753 |  | 260 |  | 47 |  | 208
Pension funds and foundations |  |  |  | 2 |  |  |  |  |  | 4 |  | 61 |  |  |  |  |  |  |  |
|  | 1,210 |  | 2,032 |  | 6,385 |  | 2,105 |  | 5,153 |  | 185 |  | 1,144 |  | 1,460 |  | 69 |  | 208

(*) |  | Each individual amount included herein was lower than euro 50 million.

Most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

• |  | provisions of specialized services in upstream activities and Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Agip Kazakhstan North Caspian Operating Co NV, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co and, only with Karachaganak Petroleum Operating BV, purchase of oil products and with Agip Kazakhstan North Caspian Operating Co NV, provisions of services by the Engineering & Construction segment; services charged to Eni’s associates are invoiced on the basis of incurred costs;
• |  | transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Bologna with CEPAV (Consorzio Eni per l’Alta Velocità) Uno and related guarantees;
• |  | transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Verona with CEPAV (Consorzio Eni per l’Alta Velocità) Due;
• |  | sale of gas outside Italy to EnBW Eni Verwaltungsgesellschaft mbH and Unión Fenosa Gas Comercializadora SA. Transactions with EnBW Eni Verwaltungsgesellschaft mbH are reported until the date of the sale occurred on August 5, 2014;
• |  | transactions with InAgip doo related to the redetermination of the interest in an offshore field located in the Adriatic Sea;
• |  | planning, construction and technical assistance to support by KWANDA - Suporte Logistico Lda and Petromar Lda and, only for Petromar Lda, guarantees issued in relation to contractual commitments related to the execution of project planning and realization;
• |  | engineering and technical assistance to South Stream Transport BV in relation to the construction of the first line of the submarine gas pipeline South Stream;
• |  | 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;

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• |  | guarantees issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd; and
• |  | services for the 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 fuel oil, 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 on the basis of tariffs set by the 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, as they would be conducted on an arm’s length basis with Snam Group;
• |  | sale and purchase of electricity, the acquisition of domestic electricity transmission service and the fair value of derivative financial instruments included in the prices of electricity related to sale/purchase transactions with Terna Group; and
• |  | sale and purchase of electricity with GSE - Gestore Servizi Energetici.

Transactions with pension funds and foundation concerned:

• |  | provisions to pension funds for euro 61 million; and
• |  | contributions to Eni Enrico Mattei Foundation for euro 4 million.

Financing transactions with related parties

(euro million) |  | Dec. 31, 2012 |  | 2012

Name |  | Receivables |  | Payables |  | Guarantees |  | Charges |  | Gains |  | Income from equity instruments

Continuing operations |  |  |  |  |  |  |  |  |  |  |  |
Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |
CARDÓN IV SA |  | 80 |  |  |  |  |  |  |  | 3 |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Due |  |  |  |  |  | 84 |  |  |  |  |  |
Société Centrale Electrique du Congo SA |  | 92 |  |  |  | 5 |  |  |  |  |  |
Other (*) |  | 405 |  | 105 |  | 7 |  | 1 |  | 18 |  |
|  | 577 |  | 105 |  | 96 |  | 1 |  | 21 |  |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |  |  |  |  |  |
Other (*) |  | 58 |  | 49 |  | 1 |  | 1 |  |  |  |
|  | 58 |  | 49 |  | 1 |  | 1 |  |  |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group |  | 883 |  |  |  |  |  |  |  | 6 |  |
Snam Group |  | 141 |  |  |  |  |  |  |  | 1 |  |
|  | 1,024 |  |  |  |  |  |  |  | 7 |  |
|  | 1,659 |  | 154 |  | 97 |  | 2 |  | 28 |  |
Discontinued operations |  |  |  |  |  |  |  |  |  |  |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group |  |  |  |  |  |  |  |  |  |  |  | 2,019
|  |  |  |  |  |  |  |  |  |  |  | 2,019
|  | 1,659 |  | 154 |  | 97 |  | 2 |  | 28 |  | 2,019

(*) |  | Each individual amount included herein was lower than euro 50 million.

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(euro million) |  | Dec. 31, 2013 |  | 2013

Name |  | Receivables |  | Payables |  | Guarantees |  | Charges |  | Gains |  | Income from equity instruments

Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |
CARDÓN IV SA |  | 236 |  |  |  |  |  |  |  | 10 |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Due |  |  |  |  |  | 150 |  |  |  |  |  |
Matrìca SpA |  | 100 |  |  |  |  |  |  |  | 4 |  |
Shatskmorneftegaz Sarl |  | 51 |  |  |  |  |  | 13 |  |  |  |
Société Centrale Electrique du Congo SA |  | 74 |  |  |  | 5 |  |  |  |  |  |
Unión Fenosa Gas SA |  |  |  | 120 |  |  |  |  |  |  |  |
Other (*) |  | 281 |  | 86 |  | 15 |  | 72 |  | 23 |  |
|  | 742 |  | 206 |  | 170 |  | 85 |  | 37 |  |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |  |  |  |  |  |
Other (*) |  | 59 |  | 57 |  | 1 |  |  |  | 1 |  |
|  | 59 |  | 57 |  | 1 |  |  |  | 1 |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |
Other (*) |  |  |  | 1 |  |  |  |  |  | 3 |  |
|  |  |  | 1 |  |  |  |  |  | 3 |  |
|  | 801 |  | 264 |  | 171 |  | 85 |  | 41 |  |

(*) |  | Each individual amount included herein was lower than euro 50 million.

(euro million) |  | Dec. 31, 2014 |  | 2014

Name |  | Receivables |  | Payables |  | Guarantees |  | Charges |  | Gains |  | Income from equity instruments

Joint ventures and associates |  |  |  |  |  |  |  |  |  |  |  |
CARDÓN IV SA |  | 621 |  |  |  |  |  |  |  | 29 |  |
CEPAV (Consorzio Eni per l'Alta Velocità) Due |  |  |  |  |  | 150 |  |  |  | 6 |  |
Matrìca SpA |  | 200 |  |  |  |  |  |  |  | 5 |  |
Société Centrale Electrique du Congo SA |  | 84 |  |  |  | 2 |  |  |  |  |  |
Unión Fenosa Gas SA |  |  |  | 90 |  |  |  |  |  |  |  |
Other (*) |  | 84 |  | 13 |  | 19 |  | 55 |  | 4 |  |
|  | 989 |  | 103 |  | 171 |  | 55 |  | 44 |  |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |  |  |  |  |  |
Other (*) |  | 68 |  | 73 |  | 2 |  |  |  | 1 |  |
|  | 68 |  | 73 |  | 2 |  |  |  | 1 |  |
Entities controlled by the Government |  |  |  |  |  |  |  |  |  |  |  |
Other (*) |  |  |  | 5 |  |  |  |  |  | 1 |  |
|  |  |  | 5 |  |  |  |  |  | 1 |  |
|  | 1,057 |  | 181 |  | 173 |  | 55 |  | 46 |  |

(*) |  | Each individual amount included herein was lower than euro 50 million.

Most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

• |  | a cash deposit at Eni’s financial companies on behalf of Unión Fenosa Gas SA;
• |  | financing loans granted to CARDÓN IV SA for the exploration and development activities of a gas field and to Société Centrale Electrique du Congo SA for the construction of an electric plant in Congo;
• |  | a bank debt guarantee issued on behalf of CEPAV (Consorzio Eni per l’Alta Velocità) Due;
• |  | financing loans granted to Matrìca SpA in relation to the "Green Chemistry" project at the Porto Torres plant.

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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:

|  | Dec. 31, 2012 |  | Dec. 31, 2013 |  | Dec. 31, 2014

(euro million) |  | Total |  | Related parties |  | Impact (%) |  | Total |  | Related parties |  | Impact (%) |  | Total |  | Related parties |  | Impact (%)

Trade and other receivables |  | 28,618 |  | 2,594 |  | 9.06 |  | 28,890 |  | 1,869 |  | 6.47 |  | 28,601 |  | 1,973 |  | 6.90
Other current assets |  | 1,617 |  | 8 |  | 0.49 |  | 1,325 |  | 15 |  | 1.13 |  | 4,385 |  | 43 |  | 0.98
Other non-current financial assets |  | 913 |  | 334 |  | 36.58 |  | 858 |  | 320 |  | 37.30 |  | 1,022 |  | 239 |  | 23.39
Other non-current assets |  | 4,398 |  | 43 |  | 0.98 |  | 3,676 |  | 42 |  | 1.14 |  | 2,773 |  | 12 |  | 0.43
Current financial liabilities |  | 2,032 |  | 154 |  | 7.58 |  | 2,553 |  | 264 |  | 10.34 |  | 2,716 |  | 181 |  | 6.66
Trade and other payables |  | 23,666 |  | 1,583 |  | 6.69 |  | 23,701 |  | 2,160 |  | 9.11 |  | 23,703 |  | 1,954 |  | 8.24
Other liabilities |  | 1,418 |  | 6 |  | 0.42 |  | 1,437 |  | 17 |  | 1.18 |  | 4,489 |  | 58 |  | 1.29
Other non-current liabilities |  | 2,598 |  | 16 |  | 0.62 |  | 2,259 |  |  |  |  |  | 2,285 |  | 20 |  | 0.88

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

|  | 2012 |  | 2013 |  | 2014

(euro million) |  | Total |  | Related parties |  | Impact (%) |  | Total |  | Related parties |  | Impact (%) |  | Total |  | Related parties |  | Impact (%)

Continuing operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from operations |  | 127,109 |  |  | 3,622 |  | 2.85 |  | 114,697 |  |  | 3,184 |  | 2.78 |  | 109,847 |  | 2,604 |  | 2.37
Other income and revenues |  | 1,548 |  |  | 57 |  | 3.68 |  | 1,387 |  |  | 33 |  | 2.38 |  | 1,101 |  | 69 |  | 6.27
Purchases, services and other |  | 95,034 |  |  | 6,093 |  | 6.41 |  | 90,003 |  |  | 7,897 |  | 8.77 |  | 86,340 |  | 7,382 |  | 8.55
Payroll and related costs |  | 4,640 |  |  | 21 |  | 0.45 |  | 5,301 |  |  | 41 |  | 0.77 |  | 5,337 |  | 61 |  | 1.14
Other operating income (expense) |  | (158 | ) |  | 10 |  | .. |  | (71 | ) |  | 68 |  | .. |  | 145 |  | 208 |  | ..
Financial income |  | 7,208 |  |  | 28 |  | 0.39 |  | 5,732 |  |  | 41 |  | 0.72 |  | 6,459 |  | 46 |  | 0.71
Financial expense |  | 8,327 |  |  | 2 |  | 0.02 |  | 6,653 |  |  | 85 |  | 1.28 |  | 7,710 |  | 55 |  | 0.71
Discontinued operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net sales from operations |  | 1,886 |  |  | 303 |  | 16.07 |  |  |  |  |  |  |  |  |  |  |  |  |
Operating expenses |  | 995 |  |  | 88 |  | 8.84 |  |  |  |  |  |  |  |  |  |  |  |  |
Income (expense) from investments |  | 3,508 |  |  | 2,019 |  | 57.55 |  |  |  |  |  |  |  |  |  |  |  |  |

Transactions with related parties were part of the ordinary course of Eni’s business and were mainly conducted on an arm’s length basis.

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Main cash flows with related parties are provided below:

(euro million) |  | 2012 |  | 2013 |  | 2014

Revenues and other income |  | 3,679 |  |  | 3,217 |  |  | 2,673 |
Costs and other expenses |  | (4,864 | ) |  | (6,731 | ) |  | (6,262 | )
Other operating income (loss) |  | 10 |  |  | 68 |  |  | 208 |
Net change in trade and other receivables and liabilities |  | (183 | ) |  | 495 |  |  | 132 |
Net interests |  | 26 |  |  | 40 |  |  | 46 |
Net cash provided from operating activities - Continuing operations |  | (1,332 | ) |  | (2,911 | ) |  | (3,203 | )
Net cash provided from operating activities - Discontinued operations |  | 215 |  |  |  |  |  |  |
Net cash provided from operating activities |  | (1,117 | ) |  | (2,911 | ) |  | (3,203 | )
Capital expenditures in tangible and intangible assets |  | (1,250 | ) |  | (1,207 | ) |  | (1,181 | )
Disposal of investments |  | 3,517 |  |  |  |  |  |  |
Net change in accounts payable and receivable in relation to investments |  | 261 |  |  | (13 | ) |  | (114 | )
Change in financial receivables |  | (1,043 | ) |  | 830 |  |  | (163 | )
Net cash used in investing activities |  | 1,485 |  |  | (390 | ) |  | (1,458 | )
Change in financial liabilities |  | (93 | ) |  | 119 |  |  | (99 | )
Net cash used in financing activities |  | (93 | ) |  | 119 |  |  | (99 | )
Total financial flows to related parties |  | 275 |  |  | (3,182 | ) |  | (4,760 | )

The impact of cash flows with related parties consisted of the following:

|  | 2012 |  | 2013 |  | 2014

(euro million) |  | Total |  | Related parties |  | Impact (%) |  | Total |  | Related parties |  | Impact (%) |  | Total |  | Related parties |  | Impact (%)

Cash provided from operating activities |  | 12,567 |  |  | (1,117 | ) |  | .. |  | 11,026 |  |  | (2,911 | ) |  | .. |  | 15,110 |  |  | (3,203) |  | ..
Cash used in investing activities |  | (8,377 | ) |  | 1,485 |  |  | .. |  | (10,981 | ) |  | (390 | ) |  | 3.55 |  | (8,943 | ) |  | (1,458) |  | 16.30
Cash used in financing activities |  | 2,071 |  |  | (93 | ) |  | .. |  | (2,510 | ) |  | 119 |  |  | .. |  | (5,062 | ) |  | (99) |  | 1.96

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45 Other information about investments

Information on Eni’s investments as of December 31, 2014
The following section provides the information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2014. Unless otherwise indicated, the share capital is represented by the ordinary shares directly held by the Group, while the ownership interest corresponds to the voting rights.

Parent company

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Eni SpA (#) |  | Rome |  | Italy |  | EUR |  | 4,005,358,876 |  | Cassa Depositi e Prestiti SpA Ministero dell’Economia e delle Finanze Eni SpA Others |  | 25.76 4.34 0.91 68.99 |  |  |  |

Subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration & Production |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

Eni Angola SpA |  | San Donato Milanese (MI) |  | Angola |  | EUR |  | 20,200,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Mediterranea Idrocarburi SpA |  | Gela (CL) |  | Italy |  | EUR |  | 5,200,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Mozambico SpA |  | San Donato Milanese (MI) |  | Mozambique |  | EUR |  | 200,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Timor Leste SpA |  | San Donato Milanese (MI) |  | Timor Leste |  | EUR |  | 6,841,517 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni West Africa SpA |  | San Donato Milanese (MI) |  | Angola |  | EUR |  | 10,000,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Zubair SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 120,000 |  | Eni SpA Third parties |  | 99.99 (..) |  | 100.00 |  | F.C.
Floaters SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 200,120,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Ieoc SpA |  | San Donato Milanese (MI) |  | Egypt |  | EUR |  | 18,331,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Società Adriatica Idrocarburi SpA |  | San Giovanni Teatino (CH) |  | Italy |  | EUR |  | 14,738,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Società Ionica Gas SpA |  | San Giovanni Teatino (CH) |  | Italy |  | EUR |  | 11,452,500 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Società Petrolifera Italiana SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 24,103,200 |  | Eni SpA Third parties |  | 99.96 0.04 |  | 99.96 |  | F.C.
Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA |  | Venezia Marghera (VE) |  | Italy |  | EUR |  | 2,064,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agip Caspian Sea BV |  | Amsterdam (Netherlands) |  | Kazakhstan |  | EUR |  | 20,005 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Agip Energy and Natural Resources (Nigeria) Ltd |  | Abuja (Nigeria) |  | Nigeria |  | NGN |  | 5,000,000 |  | Eni International BV Eni Oil Holdings BV |  | 95.00 5.00 |  | 100.00 |  | F.C.
Agip Karachaganak BV |  | Amsterdam (Netherlands) |  | Kazakhstan |  | EUR |  | 20,005 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Agip Oil Ecuador BV |  | Amsterdam (Netherlands) |  | Ecuador |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Agip Oleoducto de Crudos Pesados BV |  | Amsterdam (Netherlands) |  | Ecuador |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Burren (Cyprus) Holdings Ltd |  | Nicosia (Cyprus) |  | Cyprus |  | EUR |  | 1,710 |  | Burren En. (Berm) Ltd |  | 100.00 |  |  |  | Co.

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

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Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Burren Energy (Bermuda) Ltd |  | Hamilton (Bermuda) |  | United Kingdom |  | USD |  | 62,342,955 |  | Burren Energy Plc |  | 100.00 |  | 100.00 |  | F.C.
Burren Energy Congo Ltd |  | Tortola (British Virgin Islands) |  | Republic of the Congo |  | USD |  | 50,000 |  | Burren En. (Berm) Ltd |  | 100.00 |  | 100.00 |  | F.C.
Burren Energy (Egypt) Ltd |  | London (United Kingdom) |  | Egypt |  | GBP |  | 2 |  | Burren Energy Plc |  | 100.00 |  |  |  | Eq.
Burren Energy India Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 2 |  | Burren Energy Plc |  | 100.00 |  | 100.00 |  | F.C.
Burren Energy Ltd |  | Nicosia (Cyprus) |  | Cyprus |  | EUR |  | 1,710 |  | Burren En. (Berm) Ltd |  | 100.00 |  | 100.00 |  | F.C.
Burren Energy Plc |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 28,819,023 |  | Eni UK Holding Plc Eni UK Ltd |  | 99.99 (..) |  | 100.00 |  | F.C.
Burren Energy (Services) Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 2 |  | Burren Energy Plc |  | 100.00 |  | 100.00 |  | F.C.
Burren Energy Ship Management Ltd |  | Nicosia (Cyprus) |  | Cyprus |  | EUR |  | 1,710 |  | Burren (Cyp) Hold. Ltd |  | 100.00 |  |  |  |
Burren Energy Shipping and Transportation Ltd |  | Nicosia (Cyprus) |  | Cyprus |  | EUR |  | 3,420 |  | Burren (Cyp) Hold. Ltd Burren En. (Berm) Ltd |  | 50.00 50.00 |  |  |  | Co.
Burren Shakti Ltd |  | Hamilton (Bermuda) |  | United Kingdom |  | USD |  | 65,300,000 |  | Burren En. India Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Abu Dhabi BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni AEP Ltd |  | London (United Kingdom) |  | Pakistan |  | GBP |  | 73,471,000 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Algeria Exploration BV |  | Amsterdam (Netherlands) |  | Algeria |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Algeria Ltd Sàrl |  | Luxembourg (Luxembourg) |  | Algeria |  | USD |  | 20,000 |  | Eni Oil Holdings BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Algeria Production BV |  | Amsterdam (Netherlands) |  | Algeria |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Ambalat Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni America Ltd |  | Dover, Delaware (USA) |  | USA |  | USD |  | 72,000 |  | Eni UHL Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Angola Exploration BV |  | Amsterdam (Netherlands) |  | Angola |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Angola Production BV |  | Amsterdam (Netherlands) |  | Angola |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Argentina Exploración y Explotación SA |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 24,136,336 |  | Eni International BV Eni Oil Holdings BV |  | 95.00 5.00 |  |  |  | Eq.
Eni Arguni I Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Australia BV |  | Amsterdam (Netherlands) |  | Australia |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Australia Ltd |  | London (United Kingdom) |  | Australia |  | GBP |  | 20,000,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni BB Petroleum Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 1,000 |  | Eni Petroleum Co Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni BTC Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 34,000,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni Bukat Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Bulungan BV |  | Amsterdam (Netherlands) |  | Indonesia |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Canada Holding Ltd |  | Calgary (Canada) |  | Canada |  | USD |  | 1,453,200,001 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni CBM Ltd |  | London (United Kingdom) |  | Indonesia |  | USD |  | 2,210,728 |  | Eni Lasmo Plc |  | 100.00 |  | 100.00 |  | F.C.
Eni China BV |  | Amsterdam (Netherlands) |  | China |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Congo SA |  | Pointe-Noire (Republic of the Congo) |  | Republic of the Congo |  | USD |  | 17,000,000 |  | Eni E&P Holding BV Eni Int. NA NV Sàrl Eni International BV |  | 99.99 (..) (..) |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Eni Croatia BV |  | Amsterdam (Netherlands) |  | Croatia |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Cyprus Ltd |  | Nicosia (Cyprus) |  | Cyprus |  | EUR |  | 2,002 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Dación BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 90,000 |  | Eni Oil Holdings BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Denmark BV |  | Amsterdam (Netherlands) |  | Greenland |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda (former Eni Oil do Brasil SA) |  | Rio de Janeiro (Brazil) |  | Brazil |  | BRL |  | 1,579,800,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.99 (..) |  |  |  | Eq.
Eni East Sepinggan Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Elgin/Franklin Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 100 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Energy Russia BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Engineering E&P Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 40,000,001 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Exploration & Production Holding BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 29,832,777.12 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Gabon SA |  | Libreville (Gabon) |  | Gabon |  | XAF |  | 7,400,000,000 |  | Eni International BV Third parties |  | 99.96 0.04 |  | 99.96 |  | F.C.
Eni Ganal Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 2 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Gas & Power LNG Australia BV |  | Amsterdam (Netherlands) |  | Australia |  | EUR |  | 10,000,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Ghana Exploration and Production Ltd |  | Accra (Ghana) |  | Ghana |  | GHS |  | 21,412,500 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Hewett Ltd |  | Aberdeen (United Kingdom) |  | United Kingdom |  | GBP |  | 3,036,000 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Hydrocarbons Venezuela Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 11,000 |  | Eni Lasmo Plc |  | 100.00 |  |  |  | Eq.
Eni India Ltd |  | London (United Kingdom) |  | India |  | GBP |  | 44,000,000 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Indonesia Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 100 |  | Eni ULX Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Indonesia Ots 1 Ltd |  | George Town (Cayman Islands) |  | Indonesia |  | USD |  | 1.01 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni International NA NV Sàrl |  | Luxembourg (Luxembourg) |  | United Kingdom |  | USD |  | 25,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Investments Plc |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 750,050,000 |  | Eni SpA Eni UK Ltd |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni Iran BV |  | Amsterdam (Netherlands) |  | Iran |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Iraq BV |  | Amsterdam (Netherlands) |  | Iraq |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Ireland BV |  | Amsterdam (Netherlands) |  | Ireland |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Isatay BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni Ivory Coast Ltd (former Eni BBI Ltd) |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 1 |  | Eni UK Ltd |  | 100.00 |  |  |  | Eq.
Eni JPDA 03-13 Ltd |  | London (United Kingdom) |  | Australia |  | GBP |  | 250,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni JPDA 06-105 Pty Ltd |  | Perth (Australia) |  | Australia |  | AUD |  | 80,830,576 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni JPDA 11-106 BV |  | Amsterdam (Netherlands) |  | Australia |  | EUR |  | 50,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Kenya BV |  | Amsterdam (Netherlands) |  | Kenya |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Krueng Mane Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 2 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Lasmo Plc |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 337,638,724.25 |  | Eni Investments Plc Eni UK Ltd |  | 99.99 (..) |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-117

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Eni Liberia BV |  | Amsterdam (Netherlands) |  | Liberia |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Liverpool Bay Operating Co Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 5,001,000 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni LNS Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 80,400,000 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Mali BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni Marketing Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 1,000 |  | Eni Petroleum Co Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni Middle East BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Middle East Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 5,000,002 |  | Eni ULT Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni MOG Ltd (in liquidation) |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 220,711,147.50 |  | Eni Lasmo Plc Eni LNS Ltd |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni Mozambique Engineering Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 1 |  | Eni UK Ltd |  | 100.00 |  |  |  | Eq.
Eni Mozambique LNG Holding BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Muara Bakau BV |  | Amsterdam (Netherlands) |  | Indonesia |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Myanmar BV |  | Amsterdam (Netherlands) |  | Myanmar |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Norge AS |  | Forus (Norway) |  | Norway |  | NOK |  | 278,000,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni North Africa BV |  | Amsterdam (Netherlands) |  | Libya |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni North Ganal Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Oil & Gas Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 100,800 |  | Eni America Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Oil Algeria Ltd |  | London (United Kingdom) |  | Algeria |  | GBP |  | 1,000 |  | Eni Lasmo Plc |  | 100.00 |  | 100.00 |  | F.C.
Eni Oil Holdings BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 450,000 |  | Eni ULX Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Pakistan Ltd |  | London (United Kingdom) |  | Pakistan |  | GBP |  | 90,087 |  | Eni ULX Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Pakistan (M) Ltd Sàrl |  | Luxembourg (Luxembourg) |  | Pakistan |  | USD |  | 20,000 |  | Eni Oil Holdings BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Papalang Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 2 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Petroleum Co Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 156,600,000 |  | Eni SpA Eni International BV |  | 63.86 36.14 |  | 100.00 |  | F.C.
Eni Petroleum US Llc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 1,000 |  | Eni BB Petroleum Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni PNG Ltd (in liquidation) |  | Port Moresby (Papua New Guinea) |  | Papua New Guinea |  | PGK |  | 15,400,274 |  | Eni International BV |  | 100.00 |  |  |  | Co.
Eni Polska s. z. o. (in liquidation) |  | Warsaw (Poland) |  | Poland |  | PLN |  | 4,100,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Popodi Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 2 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Portugal BV |  | Amsterdam (Netherlands) |  | Portugal |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni Rapak Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 2 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni RD Congo SA |  | Kinshasa (Democratic Republic of the Congo) |  | Democratic Republic of the Congo |  | CDF |  | 10,000,000,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni South Africa BV |  | Amsterdam (Netherlands) |  | Republic of South Africa |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni South China Sea Ltd Sàrl |  | Luxembourg (Luxembourg) |  | China |  | USD |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni South Salawati Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni TNS Ltd |  | Aberdeen (United Kingdom) |  | United Kingdom |  | GBP |  | 1,000 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Togo BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-118

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Eni Trinidad and Tobago Ltd |  | Port of Spain (Trinidad & Tobago) |  | Trinidad & Tobago |  | TTD |  | 1,181,880 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Tunisia BV |  | Amsterdam (Netherlands) |  | Tunisia |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Turkmenistan Ltd (former Burren Resources Petroleum Ltd) |  | Hamilton (Bermuda) |  | Turkmenistan |  | USD |  | 20,000 |  | Burren Energy (Bermuda) Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni UHL Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 1 |  | Eni ULT Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni UKCS Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 100 |  | Eni UK Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni UK Holding Plc |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 424,050,000 |  | Eni Lasmo Plc Eni UK Ltd |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni UK Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 250,000,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Ukraine Deep Waters BV |  | Amsterdam (Netherlands) |  | Ukraine |  | EUR |  | 20,000 |  | Eni Ukraine Hold. BV |  | 100.00 |  |  |  | Eq.
Eni Ukraine Holdings BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Ukraine Llc |  | Kiev (Ukraine) |  | Ukraine |  | UAH |  | 42,004,757.64 |  | Eni Ukraine Hold. BV Eni International BV |  | 99.99 0.01 |  | 100.00 |  | F.C.
Eni Ukraine Shallow Waters BV |  | Amsterdam (Netherlands) |  | Ukraine |  | EUR |  | 20,000 |  | Eni Ukraine Hold. BV |  | 100.00 |  |  |  | Eq.
Eni ULT Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 93,215,492.25 |  | Eni Lasmo Plc |  | 100.00 |  | 100.00 |  | F.C.
Eni ULX Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 200,010,000 |  | Eni ULT Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni USA Gas Marketing Llc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 10,000 |  | Eni Marketing Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni USA Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 1,000 |  | Eni Oil & Gas Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni US Operating Co Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 1,000 |  | Eni Petroleum Co Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni Venezuela BV |  | Amsterdam (Netherlands) |  | Venezuela |  | EUR |  | 20,000 |  | Eni Venezuela E&P Holding SA |  | 100.00 |  | 100.00 |  | F.C.
Eni Venezuela E&P Holding SA |  | Bruxelles (Belgium) |  | Belgium |  | USD |  | 963,800,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.97 0.03 |  | 100.00 |  | F.C.
Eni Ventures Plc (in liquidation) |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 278,050,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.99 (..) |  |  |  | Co.
Eni Vietnam BV |  | Amsterdam (Netherlands) |  | Vietnam |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Western Asia BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni West Timor Ltd |  | London (United Kingdom) |  | Indonesia |  | GBP |  | 1 |  | Eni Indonesia Ltd |  | 100.00 |  | 100.00 |  | F.C.
Eni Yemen Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 1,000 |  | Burren Energy Plc |  | 100.00 |  |  |  | Eq.
Eurl Eni Algérie |  | Algeri (Algeria) |  | Algeria |  | DZD |  | 1,000,000 |  | Eni Algeria Ltd Sàrl |  | 100.00 |  |  |  | Eq.
First Calgary Petroleums LP |  | Wilmington (USA) |  | Algeria |  | USD |  | 1 |  | Eni Canada Hold. Ltd FCP Partner Co ULC |  | 99.90 0.10 |  | 100.00 |  | F.C.
First Calgary Petroleums Partner Co ULC |  | Calgary (Canada) |  | Canada |  | CAD |  | 10 |  | Eni Canada Hold. Ltd |  | 100.00 |  | 100.00 |  | F.C.
Hindustan Oil Exploration Co Ltd (**) |  | Vadodara (India) |  | India |  | INR |  | 1,304,932,890 |  | Burren Shakti Ltd Eni UK Holding Plc Burren En. India Ltd Third parties |  | 27.16 20.01 0.01 52.82 |  | 47.18 |  | F.C.
HOEC Bardahl India Ltd |  | Vadodara (India) |  | India |  | INR |  | 5,000,200 |  | Hindus. Oil E. Co Ltd |  | 100.00 |  |  |  | Eq.
Ieoc Exploration BV |  | Amsterdam (Netherlands) |  | Egypt |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Ieoc Production BV |  | Amsterdam (Netherlands) |  | Egypt |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Lasmo Sanga Sanga Ltd |  | Hamilton (Bermuda) |  | Indonesia |  | USD |  | 12,000 |  | Eni Lasmo Plc |  | 100.00 |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(**) |  | The company is de facto controlled due to a wide dispersion of the other shareholdings.

F-119

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Liverpool Bay Ltd |  | London (United Kingdom) |  | United Kingdom |  | USD |  | 29,075,343 |  | Eni ULX Ltd |  | 100.00 |  | 100.00 |  | F.C.
Nigerian Agip CPFA Ltd |  | Lagos (Nigeria) |  | Nigeria |  | NGN |  | 1,262,500 |  | NAOC Ltd Agip En Nat Res.Ltd Nigerian Agip E. Ltd |  | 98.02 0.99 0.99 |  |  |  | Co.
Nigerian Agip Exploration Ltd |  | Abuja (Nigeria) |  | Nigeria |  | NGN |  | 5,000,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.99 0.01 |  | 100.00 |  | F.C.
Nigerian Agip Oil Co Ltd |  | Abuja (Nigeria) |  | Nigeria |  | NGN |  | 1,800,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.89 0.11 |  | 100.00 |  | F.C.
OOO ‘Eni Energhia’ |  | Moscow (Russia) |  | Russia |  | RUB |  | 2,000,000 |  | Eni Energy Russia BV Eni Oil Holdings BV |  | 99.90 0.10 |  | 100.00 |  | F.C.
Tecnomare Egypt Ltd |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 50,000 |  | Tecnomare SpA Soc. Ionica Gas SpA |  | 99.00 1.00 |  |  |  | Eq.
Zetah Congo Ltd |  | Nassau (Bahamas) |  | Republic of the Congo |  | USD |  | 300 |  | Eni Congo SA Burren En. Congo Ltd |  | 66.67 33.33 |  |  |  | Co.
Zetah Kouilou Ltd |  | Nassau (Bahamas) |  | Republic of the Congo |  | USD |  | 2,000 |  | Eni Congo SA Burren En. Congo Ltd Third parties |  | 54.50 37.00 8.50 |  |  |  | Co.
Gas & Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ACAM Clienti SpA |  | La Spezia |  | Italy |  | EUR |  | 120,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Gas Transport Services Srl |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 120,000 |  | Eni SpA |  | 100.00 |  |  |  | Co.
Eni Medio Oriente SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 6,655,992 |  | Eni SpA |  | 100.00 |  |  |  | Eq.
EniPower Mantova SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 144,000,000 |  | EniPower SpA Third parties |  | 86.50 13.50 |  | 86.50 |  | F.C.
EniPower SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 944,947,849 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Est Più SpA |  | Gorizia |  | Italy |  | EUR |  | 7,100,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
LNG Shipping SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 240,900,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Servizi Fondo Bombole Metano SpA |  | Rome |  | Italy |  | EUR |  | 13,580,000.20 |  | Eni SpA |  | 100.00 |  |  |  | Co.
Trans Tunisian Pipeline Co SpA |  | San Donato Milanese (MI) |  | Tunisia |  | EUR |  | 1,098,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana |  | Ljubljana (Slovenia) |  | Slovenia |  | EUR |  | 12,956,935 |  | Eni SpA Third parties |  | 51.00 49.00 |  | 51.00 |  | F.C.
Distrigas LNG Shipping SA |  | Bruxelles (Belgium) |  | Belgium |  | EUR |  | 788,579.55 |  | LNG Shipping SpA Eni Gas & Power NV |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni G&P France BV |  | Amsterdam (Netherlands) |  | France |  | EUR |  | 20,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni G&P Trading BV |  | Amsterdam (Netherlands) |  | Turkey |  | EUR |  | 70,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Gas & Power France SA |  | Levallois Perret (France) |  | France |  | EUR |  | 29,937,600 |  | Eni G&P France BV Third parties |  | 99.85 0.15 |  | 99.85 |  | F.C.
Eni Gas & Power NV |  | Bruxelles (Belgium) |  | Belgium |  | EUR |  | 413,248,823.14 |  | Eni SpA Eni International BV |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni Gas Transport Services SA (in liquidation) |  | Lugano (Switzerland) |  | Switzerland |  | CHF |  | 100,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Power Generation NV |  | Bruxelles (Belgium) |  | Belgium |  | EUR |  | 5,161,500 |  | Eni SpA Eni Gas & Power NV |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni Wind Belgium NV |  | Bruxelles (Belgium) |  | Belgium |  | EUR |  | 333,000 |  | Eni Gas & Power NV Eni International BV |  | 99.70 0.30 |  | 100.00 |  | F.C.
Société de Service du Gazoduc Transtunisien SA - Sergaz SA |  | Tunisi (Tunisia) |  | Tunisia |  | TND |  | 99,000 |  | Eni International BV Third parties |  | 66.67 33.33 |  | 66.67 |  | F.C.
Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA |  | Tunisi (Tunisia) |  | Tunisia |  | TND |  | 200,000 |  | Eni International BV Eni Gas & Power NV Eni SpA Trans Tunis. P. Co SpA |  | 99.85 0.05 0.05 0.05 |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Tigáz Gepa Kft |  | Hajdúszoboszló (Hungary) |  | Hungary |  | HUF |  | 52,780,000 |  | Tigáz Zrt |  | 100.00 |  |  |  | Eq.
Tigáz-Dso Földgázelosztó kft |  | Hajdúszoboszló (Hungary) |  | Hungary |  | HUF |  | 62,066,000 |  | Tigáz Zrt |  | 100.00 |  | 98.04 |  | F.C.
Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság |  | Hajdúszoboszló (Hungary) |  | Hungary |  | HUF |  | 17,000,000,000 |  | Eni SpA Tigáz Zrt Third parties |  | 97.88 0.16 1.96 | (a) | 98.04 |  | F.C.
Refining & Marketing |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consorzio AgipGas Sabina (in liquidation) |  | Cittaducale (RI) |  | Italy |  | EUR |  | 5,160 |  | Eni Rete o&no SpA |  | 100.00 |  |  |  | Co.
Consorzio Condeco Santapalomba (in liquidation) |  | Rome |  | Italy |  | EUR |  | 125,507 |  | Eni SpA Third parties |  | 92.66 7.34 |  |  |  | Eq.
Consorzio Movimentazioni Petrolifere nel Porto di Livorno |  | Stagno (LI) |  | Italy |  | EUR |  | 1,000 |  | Ecofuel SpA Costiero Gas L. SpA Third parties |  | 49.90 11.00 39.10 |  |  |  | Co.
Ecofuel SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 52,000,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Fuel Centrosud SpA |  | Rome |  | Italy |  | EUR |  | 21,000,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Fuel Nord SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 9,670,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Rete oil&nonoil SpA |  | Rome |  | Italy |  | EUR |  | 27,480,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Trading & Shipping SpA |  | Rome |  | Italy |  | EUR |  | 60,036,650 |  | Eni SpA Eni Gas & Power NV |  | 94.73 5.27 |  | 100.00 |  | F.C.
Raffineria di Gela SpA |  | Gela (CL) |  | Italy |  | EUR |  | 15,000,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agip Lubricantes SA (in liquidation) |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 1,500,000 |  | Eni International BV Eni Oil Holdings BV |  | 97.00 3.00 |  |  |  | Eq.
Eni Austria GmbH |  | Vienna (Austria) |  | Austria |  | EUR |  | 78,500,000 |  | Eni International BV Eni Deutsch. GmbH |  | 75.00 25.00 |  | 100.00 |  | F.C.
Eni Benelux BV |  | Rotterdam (Netherlands) |  | Netherlands |  | EUR |  | 1,934,040 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Ceská Republika Sro |  | Prague (Czech Republic) |  | Czech Republic |  | CZK |  | 359,000,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.99 0.01 |  | 100.00 |  | F.C.
Eni Deutschland GmbH |  | Munich (Germany) |  | Germany |  | EUR |  | 90,000,000 |  | Eni International BV Eni Oil Holdings BV |  | 89.00 11.00 |  | 100.00 |  | F.C.
Eni Ecuador SA |  | Quito (Ecuador) |  | Ecuador |  | USD |  | 103,142.08 |  | Eni International BV Esain SA |  | 99.93 0.07 |  | 100.00 |  | F.C.
Eni France Sàrl |  | Lyon (France) |  | France |  | EUR |  | 56,800,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Hungaria Zrt |  | Budaörs (Hungary) |  | Hungary |  | HUF |  | 15,441,600,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Iberia SLU |  | Alcobendas (Spain) |  | Spain |  | EUR |  | 17,299,100 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Lubricants Trading (Shanghai) Co Ltd |  | Shanghai (China) |  | China |  | EUR |  | 5,000,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
Eni Marketing Austria GmbH |  | Vienna (Austria) |  | Austria |  | EUR |  | 19,621,665.23 |  | Eni Mineralölh. GmbH Eni International BV |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni Mineralölhandel GmbH |  | Vienna (Austria) |  | Austria |  | EUR |  | 34,156,232.06 |  | Eni Austria GmbH |  | 100.00 |  | 100.00 |  | F.C.
Eni Romania Srl |  | Bucharest (Romania) |  | Romania |  | RON |  | 23,876,310 |  | Eni International BV Eni Oil Holdings BV |  | 99.00 1.00 |  | 100.00 |  | F.C.
Eni Schmiertechnik GmbH |  | Wurzburg (Germany) |  | Germany |  | EUR |  | 2,000,000 |  | Eni Deutsch. GmbH |  | 100.00 |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(a) |  | Controlling interest: | Eni SpA | 98.04 |
|  |  | Third parties | 1.96 |

F-121

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Eni Slovenija doo |  | Ljubljana (Slovenia) |  | Slovenia |  | EUR |  | 3,795,528.29 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Eni Slovensko Spol Sro |  | Bratislava (Slovakia) |  | Slovakia |  | EUR |  | 36,845,251 |  | Eni International BV Eni Oil Holdings BV |  | 99.99 0.01 |  | 100.00 |  | F.C.
Eni Suisse SA |  | Lausanne (Switzerland) |  | Switzerland |  | CHF |  | 102,500,000 |  | Eni International BV Third parties |  | 99.99 (..) |  | 100.00 |  | F.C.
Eni Trading & Shipping Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 36,000,000 |  | Ets SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni USA R&M Co Inc |  | Wilmington (USA) |  | USA |  | USD |  | 11,000,000 |  | Eni International BV |  | 100.00 |  | 100.00 |  | F.C.
Esacontrol SA |  | Quito (Ecuador) |  | Ecuador |  | USD |  | 60,000 |  | Eni Ecuador SA Third parties |  | 87.00 13.00 |  |  |  | Eq.
Esain SA |  | Quito (Ecuador) |  | Ecuador |  | USD |  | 30,000 |  | Eni Ecuador SA Tecnoesa SA |  | 99.99 (..) |  | 100.00 |  | F.C.
Oléoduc du Rhône SA |  | Valais (Switzerland) |  | Switzerland |  | CHF |  | 7,000,000 |  | Eni International BV |  | 100.00 |  |  |  | Eq.
OOO ‘‘Eni-Nefto’’ |  | Moscow (Russia) |  | Russia |  | RUB |  | 1,010,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.01 0.99 |  |  |  | Eq.
Tecnoesa SA |  | Quito (Ecuador) |  | Ecuador |  | USD |  | 36,000 |  | Eni Ecuador SA Esain SA |  | 99.99 (..) |  |  |  | Eq.
Versalis |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Versalis SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 1,553,400,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Consorzio Industriale Gas Naturale |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 124,000 |  | Versalis SpA Raff. di Gela SpA Eni SpA Syndial SpA Raff. Milazzo ScpA |  | 53.55 18.74 15.37 0.76 11.58 |  |  |  | Eq.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dunastyr Polisztirolgyártó Zártkoruen Mukodo Részvénytársaság |  | Budapest (Hungary) |  | Hungary |  | HUF |  | 8,092,160,000 |  | Versalis SpA Versalis Deutsch. GmbH Versalis International SA |  | 96.34 1.83 1.83 |  | 100.00 |  | F.C.
Eni Chemicals Trading (Shanghai) Co Ltd |  | Shanghai (China) |  | China |  | USD |  | 5,000,000 |  | Versalis SpA |  | 100.00 |  | 100.00 |  | F.C.
Polimeri Europa Elastomeres France SA (in liquidation) |  | Champagnier (France) |  | France |  | EUR |  | 13,011,904 |  | Versalis SpA |  | 100.00 |  |  |  | Eq.
Versalis Deutschland GmbH (former Polimeri Europa GmbH) |  | Eschborn (Germany) |  | Germany |  | EUR |  | 100,000 |  | Versalis SpA |  | 100.00 |  | 100.00 |  | F.C.
Versalis France SAS (former Polimeri Europa France SAS) |  | Mardyck (France) |  | France |  | EUR |  | 126,115,582.90 |  | Versalis SpA |  | 100.00 |  | 100.00 |  | F.C.
Versalis International SA |  | Bruxelles (Belgium) |  | Belgium |  | EUR |  | 15,449,173.88 |  | Versalis SpA Versalis Deutsch. GmbH Dunastyr Zrt Versalis France |  | 59.00 23.71 14.43 2.86 |  | 100.00 |  | F.C.
Versalis Kimya Ticaret Limited Sirketi |  | Istanbul (Turkey) |  | Turkey |  | TRY |  | 20,000 |  | Versalis International SA |  | 100.00 |  |  |  | Eq.
Versalis Pacific (India) Private Ltd |  | Mumbai (India) |  | India |  | INR |  | 100,000 |  | Versalis Pacific Trading Third parties |  | 99.99 0.01 |  |  |  | Eq.
Versalis Pacific Trading (Shanghai) Co Ltd |  | Shanghai (China) |  | China |  | CNY |  | 1,000,000 |  | Eni Chem. Trad. Co Ltd |  | 100.00 |  | 100.00 |  | F.C.
Versalis UK Ltd (former Polimeri Europa UK Ltd) |  | Hythe (United Kingdom) |  | United Kingdom |  | GBP |  | 4,004,041 |  | Versalis SpA |  | 100.00 |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Engineering & Construction |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Saipem SpA (#) |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 441,410,900 |  | Eni SpA Saipem SpA Third parties |  | 42.91 0.44 56.65 | (a) | 43.11 |  | F.C.
Denuke Scarl |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 10,000 |  | Saipem SpA Third parties |  | 55.00 45.00 |  | 23.71 |  | F.C.
Servizi Energia Italia SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 291,000 |  | Saipem SpA |  | 100.00 |  | 43.11 |  | F.C.
Smacemex Scarl |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 10,000 |  | Saipem SpA Third parties |  | 60.00 40.00 |  | 25.87 |  | F.C.
SnamprogettiChiyoda SAS di Saipem SpA |  | San Donato Milanese (MI) |  | Algeria |  | EUR |  | 10,000 |  | Saipem SpA Third parties |  | 99.90 0.10 |  | 43.07 |  | F.C.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Andromeda Consultoria Tecnica e Representações Ltda |  | Rio de Janeiro (Brazil) |  | Brazil |  | BRL |  | 5,494,210 |  | Saipem SpA Snamprog. Netherl. BV |  | 99.00 1.00 |  | 43.11 |  | F.C.
Boscongo SA |  | Pointe-Noire (Republic of the Congo) |  | Republic of the Congo |  | XAF |  | 1,597,805,000 |  | Saipem SA |  | 100.00 |  | 43.11 |  | F.C.
Construction Saipem Canada Inc |  | Montréal (Canada) |  | Canada |  | CAD |  | 1,000 |  | Saipem Canada Inc |  | 100.00 |  | 43.11 |  | F.C.
ER SAI Caspian Contractor Llc |  | Almaty (Kazakhstan) |  | Kazakhstan |  | KZT |  | 1,105,930,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  | 21.56 |  | F.C.
ERS - Equipment Rental & Services BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 90,760 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Global Petroprojects Services AG |  | Zurich (Switzerland) |  | Switzerland |  | CHF |  | 5,000,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Moss Maritime AS |  | Lysaker (Norway) |  | Norway |  | NOK |  | 40,000,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Moss Maritime Inc |  | Houston (USA) |  | USA |  | USD |  | 145,000 |  | Moss Maritime AS |  | 100.00 |  | 43.11 |  | F.C.
North Caspian Service Co Llp |  | Almaty (Kazakhstan) |  | Kazakhstan |  | KZT |  | 1,910,000,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Petrex SA |  | Iquitos (Peru) |  | Peru |  | PEN |  | 762,729,045 |  | Saipem Intern. BV Snamprog. Netherl. BV |  | 99.99 (..) |  | 43.11 |  | F.C.
Professional Training Center Llc |  | Karakiyan (Kazakhstan) |  | Kazakhstan |  | KZT |  | 1,000,000 |  | ER SAI Caspian Llc |  | 100.00 |  | 21.56 |  | F.C.
PT Saipem Indonesia |  | Jakarta Selatan (Indonesia) |  | Indonesia |  | USD |  | 152,778,100 |  | Saipem Intern. BV Saipem Asia Sdn Bhd |  | 68.55 31.45 |  | 43.11 |  | F.C.
SAGIO Companhia Angolana de Gestão de Instalação Offshore Ltda |  | Luanda (Angola) |  | Angola |  | AOA |  | 1,600,000 |  | Saipem Intern. BV Third parties |  | 60.00 40.00 |  |  |  | Eq.
Saigut SA de CV |  | Delegacion Cuauhtemoc (Mexico) |  | Mexico |  | MXN |  | 90,050,000 |  | Saimexicana SA Saipem Serv. M. SA CV |  | 99.99 (..) |  | 43.11 |  | F.C.
Saimep Limitada |  | Maputo (Mozambico) |  | Mozambique |  | MZN |  | 70,000,000 |  | Saipem SA Saipem Intern. BV |  | 99.98 0.02 |  | 43.11 |  | F.C.
Saimexicana SA de CV |  | Delegacion Cuauhtemoc (Mexico) |  | Mexico |  | MXN |  | 1,528,188,000 |  | Saipem SA Sofresid SA |  | 99.99 (..) |  | 43.11 |  | F.C.
Saipem America Inc |  | Wilmington (USA) |  | USA |  | USD |  | 50,000,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Argentina de Perforaciones, Montajes Y Proyectos Sociedad Anónima, Minera, Industrial, Comercial y Financiera (in liquidation) |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 1,805,300 |  | Saipem Intern. BV Third parties |  | 99.90 0.10 |  |  |  | Eq.
Saipem Asia Sdn Bhd |  | Kuala Lumpur (Malaysia) |  | Malaysia |  | MYR |  | 8,116,500 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.

(*) |  | Consolidation or valuation method: 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.

(a) |  | Controlling interest: | Eni SpA | 43.11 |
|  |  | Third parties | 56.89 |

F-123

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Saipem Australia Pty Ltd |  | West Perth (Australia) |  | Australia |  | AUD |  | 10,661,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem (Beijing) Technical Services Co Ltd |  | Beijing (China) |  | China |  | USD |  | 1,750,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Canada Inc |  | Montréal (Canada) |  | Canada |  | CAD |  | 100,100 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Contracting Algérie SpA |  | Algeri (Algeria) |  | Algeria |  | DZD |  | 1,556,435,000 |  | Sofresid SA Saipem SA |  | 99.99 (..) |  | 43.11 |  | F.C.
Saipem Contracting Netherlands BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Contracting (Nigeria) Ltd |  | Lagos (Nigeria) |  | Nigeria |  | NGN |  | 827,000,000 |  | Saipem Intern. BV Third parties |  | 97.94 2.06 |  | 42.23 |  | F.C.
Saipem do Brasil Serviçõs de Petroleo Ltda |  | Rio de Janeiro (Brazil) |  | Brazil |  | BRL |  | 854,796,299 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Drilling Co Private Ltd |  | Mumbai (India) |  | India |  | INR |  | 50,273,400 |  | Saipem SA Saipem Intern. BV |  | 50.27 49.73 |  | 43.11 |  | F.C.
Saipem Drilling Norway AS |  | Sola (Norway) |  | Norway |  | NOK |  | 100,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem East Africa Ltd |  | Kampala (Uganda) |  | Uganda |  | UGX |  | 50,000,000 |  | Saipem Intern. BV Third parties |  | 51.00 49.00 |  |  |  | Eq.
Saipem India Projects Private Ltd (former Saipem India Projects Ltd) |  | Chennai (India) |  | India |  | INR |  | 407,000,000 |  | Saipem SA |  | 100.00 |  | 43.11 |  | F.C.
Saipem Ingenieria y Construcciones SLU |  | Madrid (Spain) |  | Spain |  | EUR |  | 80,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem International BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 172,444,000 |  | Saipem SpA |  | 100.00 |  | 43.11 |  | F.C.
Saipem Libya Llc - SA.LI.CO. Llc |  | Tripoli (Libya) |  | Libya |  | LYD |  | 10,000,000 |  | Saipem Intern. BV Snamprog. Netherl. BV |  | 60.00 40.00 |  | 43.11 |  | F.C.
Saipem Ltd |  | Kingston Upon Thames - Surrey (United Kingdom) |  | United Kingdom |  | EUR |  | 7,500,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Luxembourg SA |  | Luxembourg (Luxembourg) |  | Luxembourg |  | EUR |  | 31,002 |  | Saipem Maritime Sàrl Saipem Portugal Lda |  | 99.99 (..) |  | 43.11 |  | F.C.
Saipem (Malaysia) Sdn Bhd |  | Kuala Lumpur (Malaysia) |  | Malaysia |  | MYR |  | 1,033,500 |  | Saipem Intern. BV Third parties |  | 41.94 58.06 | (a) | 17.84 |  | F.C.
Saipem Maritime Asset Management Luxembourg Sàrl |  | Luxembourg (Luxembourg) |  | Luxembourg |  | USD |  | 378,000 |  | Saipem SpA |  | 100.00 |  | 43.11 |  | F.C.
Saipem Misr for Petroleum Services SAE |  | Port Said (Egypt) |  | Egypt |  | EUR |  | 2,000,000 |  | Saipem Intern. BV ERS BV Saipem Portugal Lda |  | 99.92 0.04 0.04 |  | 43.11 |  | F.C.
Saipem (Nigeria) Ltd |  | Lagos (Nigeria) |  | Nigeria |  | NGN |  | 259,200,000 |  | Saipem Intern. BV Third parties |  | 89.41 10.59 |  | 38.55 |  | F.C.
Saipem Norge AS |  | Sola (Norway) |  | Norway |  | NOK |  | 100,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Offshore Norway AS |  | Sola (Norway) |  | Norway |  | NOK |  | 120,000 |  | Saipem SpA |  | 100.00 |  | 43.11 |  | F.C.
Saipem (Portugal) Comércio Marítimo, Sociedade Unipessoal Lda |  | Caniçal (Portugal) |  | Portugal |  | EUR |  | 299,278,738.24 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem SA |  | Montigny-le-Bretonneux (France) |  | France |  | EUR |  | 26,488,694.96 |  | Saipem SpA |  | 100.00 |  | 43.11 |  | F.C.
Saipem Services México SA de CV |  | Delegacion Cuauhtemoc (Mexico) |  | Mexico |  | MXN |  | 50,000 |  | Saimexicana SA Saipem America Inc |  | 99.99 (..) |  | 43.11 |  | F.C.
Saipem Singapore Pte Ltd |  | Singapore (Singapore) |  | Singapore |  | SGD |  | 28,890,000 |  | Saipem SA |  | 100.00 |  | 43.11 |  | F.C.
Saipem UK Ltd (in liquidation) |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 9,705 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Saipem Ukraine Llc |  | Kiev (Ukraine) |  | Ukraine |  | EUR |  | 106,060.61 |  | Saipem Intern. BV Saipem Luxemb. SA |  | 99.00 1.00 |  | 43.11 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(a) |  | Controlling interest: | Saipem International BV | 41.38 |
|  |  | Third parties | 58.62 |

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Sajer Iraq Co for Petroleum Services Trading General Contracting & Transport Llc |  | Baghdad (Iraq) |  | Iraq |  | IQD |  | 300,000,000 |  | Saipem Intern. BV Third parties |  | 60.00 40.00 |  | 25.87 |  | F.C.
Saudi Arabian Saipem Ltd |  | Al Khobar (Saudi Arabia) |  | Saudi Arabia |  | SAR |  | 5,000,000 |  | Saipem Intern. BV Third parties |  | 60.00 40.00 |  | 25.87 |  | F.C.
Sigurd Rück AG |  | Zurich (Switzerland) |  | Switzerland |  | CHF |  | 25,000,000 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Snamprogetti Engineering & Contracting Co Ltd |  | Al Khobar (Saudi Arabia) |  | Saudi Arabia |  | SAR |  | 10,000,000 |  | Snamprog. Netherl. BV Third parties |  | 70.00 30.00 |  | 30.18 |  | F.C.
Snamprogetti Engineering BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 18,151.20 |  | Saipem Maritime Sàrl |  | 100.00 |  | 43.11 |  | F.C.
Snamprogetti Ltd (in liquidation) |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 9,900 |  | Snamprog. Netherl. BV |  | 100.00 |  | 43.11 |  | F.C.
Snamprogetti Lummus Gas Ltd |  | Sliema (Malta) |  | Malta |  | EUR |  | 50,000 |  | Snamprog. Netherl. BV Third parties |  | 99.00 1.00 |  | 42.68 |  | F.C.
Snamprogetti Netherlands BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 92,117,340 |  | Saipem SpA |  | 100.00 |  | 43.11 |  | F.C.
Snamprogetti Romania Srl |  | Bucharest (Romania) |  | Romania |  | RON |  | 5,034,100 |  | Snamprog. Netherl. BV Saipem Intern. BV |  | 99.00 1.00 |  | 43.11 |  | F.C.
Snamprogetti Saudi Arabia Co Ltd Llc |  | Al Khobar (Saudi Arabia) |  | Saudi Arabia |  | SAR |  | 10,000,000 |  | Saipem Intern. BV Snamprog. Netherl. BV |  | 95.00 5.00 |  | 43.11 |  | F.C.
Sofresid Engineering SA |  | Montigny-le-Bretonneux (France) |  | France |  | EUR |  | 1,267,142.80 |  | Sofresid SA Third parties |  | 99.99 0.01 |  | 43.11 |  | F.C.
Sofresid SA |  | Montigny-le-Bretonneux (France) |  | France |  | EUR |  | 8,253,840 |  | Saipem SA Third parties |  | 99.99 (..) |  | 43.11 |  | F.C.
Sonsub International Pty Ltd |  | Sydney (Australia) |  | Australia |  | AUD |  | 13,157,570 |  | Saipem Intern. BV |  | 100.00 |  | 43.11 |  | F.C.
Other activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Syndial SpA - Attività Diversificate |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 409,936,364.07 |  | Eni SpA Third parties |  | 99.99 (..) |  | 100.00 |  | F.C.
Anic Partecipazioni SpA (in liquidation) |  | Gela (CL) |  | Italy |  | EUR |  | 23,519,847.16 |  | Syndial SpA Third parties |  | 99.96 0.04 |  |  |  | Eq.
Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) |  | Gela (CL) |  | Italy |  | EUR |  | 1,300,000 |  | Syndial SpA Third parties |  | 52.00 48.00 |  |  |  | Eq.
Ing. Luigi Conti Vecchi SpA |  | Assemini (CA) |  | Italy |  | EUR |  | 130,000 |  | Syndial SpA |  | 100.00 |  | 100.00 |  | F.C.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oleodotto del Reno SA |  | Coira (Switzerland) |  | Switzerland |  | CHF |  | 1,550,000 |  | Syndial SpA |  | 100.00 |  |  |  | Eq.

Corporate and financial companies |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agenzia Giornalistica Italia SpA |  | Rome |  | Italy |  | EUR |  | 4,000,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni Adfin SpA |  | Rome |  | Italy |  | EUR |  | 85,537,498.80 |  | Eni SpA Third parties |  | 99.63 0.37 |  | 99.63 |  | F.C.
Eni Corporate University SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 3,360,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
EniServizi SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 13,427,419.08 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Serfactoring SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 5,160,000 |  | Eni Adfin SpA Third parties |  | 49.00 51.00 |  | 48.82 |  | F.C.
Servizi Aerei SpA |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 79,817,238 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Banque Eni SA |  | Bruxelles (Belgium) |  | Belgium |  | EUR |  | 50,000,000 |  | Eni International BV Eni Oil Holdings BV |  | 99.90 0.10 |  | 100.00 |  | F.C.
Eni Finance International SA |  | Bruxelles (Belgium) |  | Belgium |  | USD |  | 3,475,036,000 |  | Eni International BV Eni SpA |  | 66.39 33.61 |  | 100.00 |  | F.C.
Eni Finance USA Inc |  | Dover, Delaware (USA) |  | USA |  | USD |  | 15,000,000 |  | Eni Petroleum Co Inc |  | 100.00 |  | 100.00 |  | F.C.
Eni Insurance Ltd |  | Dublin (Ireland) |  | Ireland |  | EUR |  | 100,000,000 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni International BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 641,683,425 |  | Eni SpA |  | 100.00 |  | 100.00 |  | F.C.
Eni International Resources Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 50,000 |  | Eni SpA Eni UK Ltd |  | 99.99 (..) |  | 100.00 |  | F.C.

Joint arrangements and associates
Exploration & Production
In Italy

Eni East Africa SpA (†) |  | San Donato Milanese (MI) |  | Mozambique |  | EUR |  | 20,000,000 |  | Eni SpA Third parties |  | 71.43 28.57 |  | 71.43 |  | J.O.
Società Oleodotti Meridionali - SOM SpA (†) |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 3,085,000 |  | Eni SpA Third parties |  | 70.00 30.00 |  | 70.00 |  | J.O.
Venezia Tecnologie SpA (†) |  | Porto Marghera (VE) |  | Italy |  | EUR |  | 150,000 |  | Eni SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Agiba Petroleum Co (†) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Al-Fayrouz Petroleum Co (†) (in liquidation) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Exploration BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Angola LNG Ltd |  | Hamilton (Bermuda) |  | Angola |  | USD |  | 10,822,085,779 |  | Eni Angola Prod. BV Third parties |  | 13.60 86.40 |  |  |  | Eq.
Ashrafi Island Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 25.00 75.00 |  |  |  | Co.
Barentsmorneftegaz Sàrl (†) |  | Luxembourg (Luxembourg) |  | Russia |  | USD |  | 20,000 |  | Eni Energy Russia BV Third parties |  | 33.33 66.67 |  |  |  | Eq.
Cabo Delgado Development Limitada (†) |  | Maputo (Mozambique) |  | Mozambique |  | USD |  | 40,000 |  | Eni Mozambique LNG Third parties |  | 50.00 50.00 |  |  |  | Co.
CARDÓN IV SA (†) |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 17,210,000 |  | Eni Venezuela BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Compañia Agua Plana SA |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 100 |  | Eni Venezuela BV Third parties |  | 26.00 74.00 |  |  |  | Co.
East Delta Gas Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 37.50 62.50 |  |  |  | Co.
East Kanayis Petroleum Co (†) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 50.00 50.00 |  |  |  | Co.
East Obaiyed Petroleum Co (†) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc SpA Third parties |  | 50.00 50.00 |  |  |  | Co.
El Temsah Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 25.00 75.00 |  |  |  | Co.
EniRepSa Gas Ltd (†) (in liquidation) |  | Al-Khobar (Saudi Arabia) |  | Saudi Arabia |  | SAR |  | 11,250,000 |  | Eni Middle East BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Enstar Petroleum Ltd |  | Calgary (Canada) |  | Canada |  | CAD |  | 0.10 |  | Unimar Llc |  | 100.00 |  |  |  |
Fedynskmorneftegaz Sàrl (†) |  | Luxembourg (Luxembourg) |  | Russia |  | USD |  | 20,000 |  | Eni Energy Russia BV Third parties |  | 33.33 66.67 |  |  |  | Eq.
InAgip doo (†) |  | Zagreb (Croatia) |  | Croatia |  | HRK |  | 54,000 |  | Eni Croatia BV Third parties |  | 50.00 50.00 |  |  |  | Co.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†) |  | Jointly controlled entity.

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Karachaganak Petroleum Operating BV |  | Amsterdam (Netherlands) |  | Kazakhstan |  | EUR |  | 20,000 |  | Agip Karachaganak BV Third parties |  | 29.25 70.75 |  |  |  | Co.
Karachaganak Project Development Ltd (KPD) |  | Reading, Berkshire (United Kingdom) |  | United Kingdom |  | GBP |  | 100 |  | Agip Karachaganak BV Third parties |  | 38.00 62.00 |  |  |  | Eq.
Khaleej Petroleum Co Wll |  | Safat (Kuwait) |  | Kuwait |  | KWD |  | 250,000 |  | Eni Middle E. Ltd Third parties |  | 49.00 51.00 |  |  |  | Eq.
Liberty National Development Co Llc |  | Wilmington (USA) |  | USA |  | USD |  | 0 (a) |  | Eni Oil & Gas Inc Third parties |  | 32.50 67.50 |  |  |  | Eq.
Llc Astroinvest-Energy |  | Zinkiv (Ukraine) |  | Ukraine |  | UAH |  | 457,860,000 |  | Zagoryanska P BV |  | 100.00 |  |  |  |
Llc Industrial Company Gazvydobuvannya |  | Poltava (Ukraine) |  | Ukraine |  | UAH |  | 315,000,000 |  | Pokrovskoe P BV |  | 100.00 |  |  |  |
Llc ‘Westgasinvest’ (†) |  | Lviv (Ukraine) |  | Ukraine |  | UAH |  | 2,000,000 |  | Eni Ukraine Hold.BV Third parties |  | 50.01 49.99 |  |  |  | Eq.
Mediterranean Gas Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 25.00 75.00 |  |  |  | Co.
Mellitah Oil & Gas BV (†) |  | Amsterdam (Netherlands) |  | Libya |  | EUR |  | 20,000 |  | Eni North Africa BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Nile Delta Oil Co Nidoco |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 37.50 62.50 |  |  |  | Co.
North Bardawil Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Exploration BV Third parties |  | 30.00 70.00 |  |  |  | Co.
Petrobel Belayim Petroleum Co (†) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 50.00 50.00 |  |  |  | Co.
PetroBicentenario SA (†) |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 64,000,000 |  | Eni Lasmo Plc Third parties |  | 40.00 60.00 |  |  |  | Eq.
PetroJunín SA (†) |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 2,150,100,000 |  | Eni Lasmo Plc Third parties |  | 40.00 60.00 |  |  |  | Eq.
PetroSucre SA |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 220,300,000 |  | Eni Venezuela BV Third parties |  | 26.00 74.00 |  |  |  | Eq.
Pharaonic Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 25.00 75.00 |  |  |  | Co.
Pokrovskoe Petroleum BV (†) |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 25,715 |  | Eni Ukraine Hold. BV Third parties |  | 30.00 70.00 |  |  |  | Eq.
Port Said Petroleum Co (†) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Raml Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 22.50 77.50 |  |  |  | Co.
Ras Qattara Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 37.50 62.50 |  |  |  | Co.
Rovuma Basin LNG Land Limitada (†) |  | Maputo (Mozambique) |  | Mozambique |  | MZN |  | 140,000 |  | Eni East Africa SpA Third parties |  | 33.33 66.67 |  |  |  | Co.
Shatskmorneftegaz Sàrl (†) |  | Luxembourg (Luxembourg) |  | Russia |  | USD |  | 20,000 |  | Eni Energy Russia BV Third parties |  | 33.33 66.67 |  |  |  | Eq.
Société Centrale Electrique du Congo SA |  | Pointe-Noire (Republic of the Congo) |  | Republic of the Congo |  | XAF |  | 44,732,000,000 |  | Eni Congo SA Third parties |  | 20.00 80.00 |  |  |  | Eq.
Société Italo Tunisienne d’Exploitation Pétrolière SA (†) |  | Tunisi (Tunisia) |  | Tunisia |  | TND |  | 5,000,000 |  | Eni Tunisia BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Sodeps - Société de Développement et d’Exploitation du Permis du Sud SA (†) |  | Tunisi (Tunisia) |  | Tunisia |  | TND |  | 100,000 |  | Eni Tunisia BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Tapco Petrol Boru Hatti Sanayi ve Ticaret AS (†) |  | Istanbul (Turkey) |  | Turkey |  | TRY |  | 7,500,000 |  | Eni International BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Tecninco Engineering Contractors Llp (†) |  | Aksai (Kazakhstan) |  | Kazakhstan |  | KZT |  | 29,478,445 |  | Tecnomare SpA Third parties |  | 49.00 51.00 |  |  |  | Eq.
Thekah Petroleum Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Exploration BV Third parties |  | 25.00 75.00 |  |  |  | Co.
Unimar Llc (†) |  | Houston (USA) |  | USA |  | USD |  | 0 (a) |  | Eni America Ltd Third parties |  | 50.00 50.00 |  |  |  | Eq.
United Gas Derivatives Co |  | Cairo (Egypt) |  | Egypt |  | USD |  | 285,000,000 |  | Eni International BV Third parties |  | 33.33 66.67 |  |  |  | Eq.
VIC CBM Ltd (†) |  | London (United Kingdom) |  | Indonesia |  | USD |  | 1,315,912 |  | Eni Lasmo Plc Third parties |  | 50.00 50.00 |  |  |  | Eq.

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

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Virginia Indonesia Co CBM Ltd (†) |  | London (United Kingdom) |  | Indonesia |  | USD |  | 631,640 |  | Eni Lasmo Plc Third parties |  | 50.00 50.00 |  |  |  | Eq.
Virginia Indonesia Co Llc |  | Wilmington (USA) |  | Indonesia |  | USD |  | 10 |  | Unimar Llc |  | 100.00 |  |  |  |
Virginia International Co Llc |  | Wilmington (USA) |  | Indonesia |  | USD |  | 10 |  | Unimar Llc |  | 100.00 |  |  |  |
West Ashrafi Petroleum Co (†) |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Exploration BV Third parties |  | 50.00 50.00 |  |  |  | Co.
Zagoryanska Petroleum BV (†) |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 18,000 |  | Eni Ukraine Hold.BV Third parties |  | 60.00 40.00 |  |  |  | Eq.
Zetah Noumbi Ltd |  | Nassau (Bahamas) |  | Republic of the Congo |  | USD |  | 100 |  | Burren En. Congo Ltd Third parties |  | 37.00 63.00 |  |  |  | Co.
Gas & Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mariconsult SpA (†) |  | Milan |  | Italy |  | EUR |  | 120,000 |  | Eni SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Società EniPower Ferrara Srl (†) |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 170,000,000 |  | EniPower SpA Third parties |  | 51.00 49.00 |  | 51.00 |  | J.O.
Termica Milazzo Srl |  | Milan |  | Italy |  | EUR |  | 23,241,000 |  | EniPower SpA Third parties |  | 40.00 60.00 |  |  |  | Eq.
Transmed SpA (†) |  | Milan |  | Italy |  | EUR |  | 240,000 |  | Eni SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Blue Stream Pipeline Co BV (†) |  | Amsterdam (Netherlands) |  | Russia |  | EUR |  | 20,000 |  | Eni International BV Third parties |  | 50.00 50.00 |  | 50.00 |  | J.O.
Distribuidora de Gas Cuyana SA (†) |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 202,351,288 |  | Eni SpA Inv. Gas Cuyana SA Third parties |  | 6.84 51.00 42.16 |  |  |  | Co.
Distribuidora de Gas del Centro SA (†) |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 160,457,190 |  | Eni SpA Inv. Gas Centro SA Third parties |  | 31.35 51.00 17.65 |  |  |  | Co.
Egyptian International Gas Technology Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 100,000,000 |  | Eni International BV Third parties |  | 40.00 60.00 |  |  |  | Co.
Eteria Parohis Aeriou Thessalias AE (†) |  | Larissa (Greece) |  | Greece |  | EUR |  | 78,459,200 |  | Eni SpA Third parties |  | 49.00 51.00 |  |  |  | Eq.
Eteria Parohis Aeriou Thessalonikis AE (†) |  | Ampelokipi-Menemeni (Greece) |  | Greece |  | EUR |  | 202,850,000 |  | Eni SpA Third parties |  | 49.00 51.00 |  |  |  | Eq.
Gas Directo SA |  | Madrid (Spain) |  | Spain |  | EUR |  | 6,716,400 |  | U. Fenosa Gas SA Third parties |  | 60.00 40.00 |  |  |  |
Gasifica SA |  | Madrid (Spain) |  | Spain |  | EUR |  | 2,000,200 |  | U. Fenosa Gas SA Third parties |  | 90.00 10.00 |  |  |  |
GreenStream BV (†) |  | Amsterdam (Netherlands) |  | Libya |  | EUR |  | 200,000,000 |  | Eni North Africa BV Third parties |  | 50.00 50.00 |  | 50.00 |  | J.O.
Infraestructuras de Gas SA |  | Madrid (Spain) |  | Spain |  | EUR |  | 340,000 |  | U. Fenosa Gas SA Third parties |  | 85.00 15.00 |  |  |  |
Inversora de Gas Cuyana SA (†) |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 60,012,000 |  | Eni SpA Third parties |  | 76.00 24.00 |  |  |  | Co.
Inversora de Gas del Centro SA (†) |  | Buenos Aires (Argentina) |  | Argentina |  | ARS |  | 68,012,000 |  | Eni SpA Third parties |  | 25.00 75.00 |  |  |  | Co.
Nueva Electricidad del Gas SA |  | Seville (Spain) |  | Spain |  | EUR |  | 294,272 |  | U. Fenosa Gas SA |  | 100.00 |  |  |  |
Premium Multiservices SA |  | Tunisi (Tunisia) |  | Tunisia |  | TND |  | 200,000 |  | Sergaz SA Third parties |  | 50.00 50.00 |  |  |  | Eq.
SAMCO Sagl |  | Lugano (Switzerland) |  | Switzerland |  | CHF |  | 20,000 |  | Eni International BV Transmed. Pip. Co Ltd Third parties |  | 5.00 90.00 5.00 |  |  |  | Eq.
Spanish Egyptian Gas Co SAE |  | Damietta (Egypt) |  | Egypt |  | USD |  | 375,000,000 |  | U. Fenosa Gas SA Third parties |  | 80.00 20.00 |  |  |  |
Transmediterranean Pipeline Co Ltd (†) |  | St. Helier (Jersey) |  | Jersey |  | USD |  | 10,310,000 |  | Eni SpA Third parties |  | 50.00 50.00 |  | 50.00 |  | J.O.
Turul Gázvezeték Építõ es Vagyonkezelõ Részvénytársaság (†) |  | Tatabànya (Hungary) |  | Hungary |  | HUF |  | 404,000,000 |  | Tigáz Zrt Third parties |  | 58.42 41.58 |  |  |  | Eq.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†) |  | Jointly controlled entity.

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##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Unión Fenosa Gas Comercializadora SA |  | Madrid (Spain) |  | Spain |  | EUR |  | 2,340,240 |  | U. Fenosa Gas SA Third parties |  | 99.99 (..) |  |  |  |
Unión Fenosa Gas Infrastructures BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 90,000 |  | U. Fenosa Gas SA |  | 100.00 |  |  |  |
Unión Fenosa Gas Exploración y Produccion SA |  | Logroño (Spain) |  | Spain |  | EUR |  | 1,060,110 |  | U. Fenosa Gas SA |  | 100.00 |  |  |  |
Unión Fenosa Gas SA (†) |  | Madrid (Spain) |  | Spain |  | EUR |  | 32,772,000 |  | Eni SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.

Refining & Marketing
In Italy

Arezzo Gas SpA (†) |  | Arezzo |  | Italy |  | EUR |  | 394,000 |  | Eni Rete o&no SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
CePIM Centro Padano Interscambio Merci SpA |  | Fontevivo (PR) |  | Italy |  | EUR |  | 6,642,928.32 |  | Ecofuel SpA Third parties |  | 34.93 65.07 |  |  |  | Eq.
Consorzio Operatori GPL di Napoli |  | Napoli |  | Italy |  | EUR |  | 102,000 |  | Eni Rete o&no SpA Third parties |  | 25.00 75.00 |  |  |  | Co.
Costiero Gas Livorno SpA (†) |  | Livorno |  | Italy |  | EUR |  | 26,000,000 |  | Eni Rete o&no SpA Third parties |  | 65.00 35.00 |  | 65.00 |  | J.O.
Depositi Costieri Trieste SpA (†) |  | Trieste |  | Italy |  | EUR |  | 1,560,000 |  | Ecofuel SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Disma SpA |  | Segrate (MI) |  | Italy |  | EUR |  | 2,600,000 |  | Eni Rete o&no SpA Third parties |  | 25.00 75.00 |  |  |  | Eq.
PETRA SpA (†) |  | Ravenna |  | Italy |  | EUR |  | 723,100 |  | Ecofuel SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Petrolig Srl (†) |  | Genova |  | Italy |  | EUR |  | 104,000 |  | Ecofuel SpA Third parties |  | 70.00 30.00 |  | 70.00 |  | J.O.
Petroven Srl (†) |  | Genova |  | Italy |  | EUR |  | 156,000 |  | Ecofuel SpA Third parties |  | 68.00 32.00 |  | 68.00 |  | J.O.
Porto Petroli di Genova SpA |  | Genova |  | Italy |  | EUR |  | 2,068,000 |  | Ecofuel SpA Third parties |  | 40.50 59.50 |  |  |  | Eq.
Raffineria di Milazzo ScpA (†) |  | Milazzo (ME) |  | Italy |  | EUR |  | 171,143,000 |  | Eni SpA Third parties |  | 50.00 50.00 |  | 50.00 |  | J.O.
SeaPad SpA (†) |  | Genova |  | Italy |  | EUR |  | 12,400,000 |  | Ecofuel SpA Third parties |  | 80.00 20.00 |  |  |  | Eq.
Seram SpA |  | Fiumicino (RM) |  | Italy |  | EUR |  | 852,000 |  | Eni SpA Third parties |  | 25.00 75.00 |  |  |  | Co.
Servizi Milazzo Srl (†) |  | Milazzo (ME) |  | Italy |  | EUR |  | 100,000 |  | Raff. Milazzo ScpA |  | 100.00 |  | 50.00 |  | J.O.
Sigea Sistema Integrato Genova Arquata SpA |  | Genova |  | Italy |  | EUR |  | 3,326,900 |  | Ecofuel SpA Third parties |  | 35.00 65.00 |  |  |  | Eq.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

AET - Raffineriebeteiligungsgesellschaft mbH |  | Schwedt (Germany) |  | Germany |  | EUR |  | 27,000 |  | Eni Deutsch.GmbH Third parties |  | 33.33 66.67 |  |  |  | Eq.
Area di Servizio City Moesa SA |  | San Vittore (Switzerland) |  | Switzerland |  | CHF |  | 1,800,000 |  | City Carburoil SA Third parties |  | 58.00 42.00 |  |  |  |
Bayernoil Raffineriegesellschaft mbH (†) |  | Vohburg (Germany) |  | Germany |  | EUR |  | 10,226,000 |  | Eni Deutsch.GmbH Third parties |  | 20.00 80.00 |  | 20.00 |  | J.O.
Ceská Rafinérská AS |  | Litvinov (Czech Republic) |  | Czech Republic |  | CZK |  | 9,348,240,000 |  | Eni International BV Third parties |  | 32.44 67.56 |  |  |  | Co.
City Carburoil SA (†) |  | Rivera (Switzerland) |  | Switzerland |  | CHF |  | 6,000,000 |  | Eni Suisse SA Third parties |  | 49.91 50.09 |  |  |  | Eq.
ENEOS Italsing Pte Ltd |  | Singapore (Singapore) |  | Singapore |  | SGD |  | 12,000,000 |  | Eni International BV Third parties |  | 22.50 77.50 |  |  |  | Eq.

(*) |  | Consolidation or valuation method: 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-129

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

FSH Flughafen Schwechat Hydranten-Gesellschaft OG |  | Vien (Austria) |  | Austria |  | EUR |  | 8,694,844.47 |  | Eni Mineralölh. GmbH Eni Marketing A. GmbH Eni Austria GmbH Third parties |  | 14.29 14.29 14.28 57.14 |  |  |  | Co.
Fuelling Aviation Services GIE |  | Tremblay en France (France) |  | France |  | EUR |  | 1 |  | Eni France Sàrl Third parties |  | 25.00 75.00 |  |  |  | Co.
Mediterranée Bitumes SA |  | Tunisi (Tunisia) |  | Tunisia |  | TND |  | 1,000,000 |  | Eni International BV Third parties |  | 34.00 66.00 |  |  |  | Eq.
Prague Fuelling Services Sro (†) |  | Prague (Czech Republic) |  | Czech Republic |  | CZK |  | 39,984,000 |  | Eni Ceská R. Sro Third parties |  | 50.00 50.00 |  |  |  | Eq.
Rosa GmbH |  | Zirndorf (Germany) |  | Germany |  | EUR |  | 2,100,000 |  | Eni Deutsch. GmbH Third parties |  | 24.80 75.20 |  |  |  | Co.
Routex BV |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 67,500 |  | Eni International BV Third parties |  | 20.00 80.00 |  |  |  | Eq.
Saraco SA |  | Meyrin (Switzerland) |  | Switzerland |  | CHF |  | 420,000 |  | Eni Suisse SA Third parties |  | 20.00 80.00 |  |  |  | Co.
Supermetanol CA (†) |  | Jose Puerto La Cruz (Venezuela) |  | Venezuela |  | VEF |  | 12,086,744.85 |  | Ecofuel SpA Supermetanol CA Third parties |  | 34.51 30.07 35.42 | (a) | 50.00 |  | J.O.
TBG Tanklager Betriebsgesellschaft GmbH (†) |  | Salzburg (Austria) |  | Austria |  | EUR |  | 43,603.70 |  | Eni Marketing A. GmbH Third parties |  | 50.00 50.00 |  |  |  | Eq.
Weat Electronic Datenservice GmbH |  | Düsseldorf (Germany) |  | Germany |  | EUR |  | 409,034 |  | Eni Deutsch. GmbH Third parties |  | 20.00 80.00 |  |  |  | Eq.
Versalis |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Brindisi Servizi Generali Scarl |  | Brindisi |  | Italy |  | EUR |  | 1,549,060 |  | Versalis SpA Syndial SpA EniPower SpA Third parties |  | 49.00 20.20 8.90 21.90 |  |  |  | Eq.
IFM Ferrara ScpA |  | Ferrara |  | Italy |  | EUR |  | 5,270,466 |  | Versalis SpA Syndial SpA S.E.F. Srl Third parties |  | 19.74 11.58 10.70 57.98 |  |  |  | Eq.
Matrìca SpA (†) |  | Porto Torres (SS) |  | Italy |  | EUR |  | 37,500,000 |  | Versalis SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Newco Tech SpA (†) |  | Novara |  | Italy |  | EUR |  | 300,000 |  | Versalis SpA Genomatica Inc |  | 83.03 16.97 |  |  |  | Eq.
Novamont SpA |  | Novara |  | Italy |  | EUR |  | 13,333,500 |  | Versalis SpA Third parties |  | 25.00 75.00 |  |  |  | Eq.
Priolo Servizi ScpA |  | Melilli (SR) |  | Italy |  | EUR |  | 25,600,000 |  | Versalis SpA Syndial SpA Third parties |  | 33.16 4.38 62.46 |  |  |  | Eq.
Ravenna Servizi Industriali ScpA |  | Ravenna |  | Italy |  | EUR |  | 5,597,400 |  | Versalis SpA EniPower SpA Ecofuel SpA Third parties |  | 42.13 30.37 1.85 25.65 |  |  |  | Eq.
Servizi Porto Marghera Scarl |  | Porto Marghera (VE) |  | Italy |  | EUR |  | 8,751,500 |  | Versalis SpA Syndial SpA Third parties |  | 48.13 38.14 13.73 |  |  |  | Eq.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Lotte Versalis Elastomers Co Ltd (†) |  | Yeosu (South Korea) |  | South Korea |  | KRW |  | 87,200,010,000 |  | Versalis SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†) |  | Jointly controlled entity.

(a) |  | Controlling interest: | Ecofuel SpA | 50.00 |
|  |  | Third parties | 50.00 |

F-130

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Engineering & Construction |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ASG Scarl |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 50,864 |  | Saipem SpA Third parties |  | 55.41 44.59 |  |  |  | Eq.
Baltica Scarl (†) |  | Rome |  | Italy |  | EUR |  | 10,000 |  | Saipem SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
CEPAV (Consorzio Eni per l’Alta Velocità) Due |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 51,645.69 |  | Saipem SpA Third parties |  | 52.00 48.00 |  |  |  | Eq.
CEPAV (Consorzio Eni per l’Alta Velocità) Uno |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 51,645.69 |  | Saipem SpA Third parties |  | 50.36 49.64 |  |  |  | Eq.
Consorzio F.S.B. (†) |  | Marghera (VE) |  | Italy |  | EUR |  | 15,000 |  | Saipem SpA Third parties |  | 28.00 72.00 |  |  |  | Co.
Consorzio Sapro (†) |  | San Giovanni Teatino (CH) |  | Italy |  | EUR |  | 10,329.14 |  | Saipem SpA Third parties |  | 51.00 49.00 |  |  |  | Co.
Modena Scarl (in liquidation) |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 400,000 |  | Saipem SpA Third parties |  | 59.33 40.67 |  |  |  | Eq.
PLNG 9 Snc di Chiyoda Corporation e Servizi Energia Italia SpA (†) (in liquidation) |  | San Donato Milanese (MI) |  | Malaysia |  | EUR |  | 1,000 |  | SEI SpA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Rodano Consortile Scarl |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 250,000 |  | Saipem SpA Third parties |  | 53.57 46.43 |  |  |  | Eq.
Rosetti Marino SpA |  | Ravenna |  | Italy |  | EUR |  | 4,000,000 |  | Saipem SA Third parties |  | 20.00 80.00 |  |  |  | Eq.
Ship Recycling Scarl (†) |  | Genova |  | Italy |  | EUR |  | 10,000 |  | Saipem SpA Third parties |  | 51.00 49.00 |  | 21.99 |  | J.O.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
02 PEARL Snc (†) |  | Montigny-le-Bretonneux (France) |  | France |  | EUR |  | 1,000 |  | Saipem SA Third parties |  | 50.00 50.00 |  | 21.56 |  | J.O.
Barber Moss Ship Management AS (†) |  | Lysaker (Norway) |  | Norway |  | NOK |  | 1,000,000 |  | Moss Maritime AS Third parties |  | 50.00 50.00 |  |  |  | Eq.
CCS Netherlands BV (†) (former CSC Netherlands BV) |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 300,000 |  | Saipem Intern. BV Third parties |  | 33.33 66.67 |  |  |  | Eq.
Charville - Consultores e Serviços Lda (†) |  | Funchal (Portugal) |  | Portugal |  | EUR |  | 5,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
CMS&A Wll (†) |  | Doha (Qatar) |  | Qatar |  | QAR |  | 500,000 |  | Snamprog. Netherl. BV Third parties |  | 20.00 80.00 |  |  |  | Eq.
CSC Japan Godo Kaisha |  | Yokohama (Japan) |  | Japan |  | JPY |  | 3,000,000 |  | CCS Netherlands BV |  | 100.00 |  |  |  |
CSFLNG Netherlands BV (†) |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 600,000 |  | Saipem SA Third parties |  | 50.00 50.00 |  |  |  | Eq.
Fertilizantes Nitrogenados de Oriente CEC |  | Caracas (Venezuela) |  | Venezuela |  | VEB |  | 9,667,827,216 |  | Snamprog. Netherl. BV Fertiliz. N. Orien. SA Third parties |  | 20.00 (..) 79.99 |  |  |  | Co.
Fertilizantes Nitrogenados de Oriente SA |  | Caracas (Venezuela) |  | Venezuela |  | VEB |  | 286,549 |  | Snamprog. Netherl. BV Third parties |  | 20.00 80.00 |  |  |  | Co.
FPSO Mystras (Nigeria) Ltd |  | Victoria Island (Nigeria) |  | Nigeria |  | NGN |  | 15,000,000 |  | FPSO Mystras Lda |  | 100.00 |  |  |  |
FPSO Mystras - Produção de Petròleo Lda (†) |  | Funchal (Portugal) |  | Portugal |  | EUR |  | 50,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Hazira Cryogenic Engineering & Construction Management Private Ltd (†) |  | Mumbai (India) |  | India |  | INR |  | 500,000 |  | Saipem SA Third parties |  | 55.00 45.00 |  |  |  | Eq.
KWANDA - Suporte Logistico Lda |  | Luanda (Angola) |  | Angola |  | AOA |  | 25,510,204 |  | Saipem SA Third parties |  | 49.00 51.00 | (a) |  |  | Eq.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†) |  | Jointly controlled entity.

(a) |  | Controlling interest: | Saipem SA | 40.00 |
|  |  | Third parties | 60.00 |

F-131

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

LNG - Serviços e Gestao de Projectos Lda |  | Funchal (Portugal) |  | Portugal |  | EUR |  | 5,000 |  | Snamprog. Netherl. BV Third parties |  | 25.00 75.00 |  |  |  | Eq.
Mangrove Gas Netherlands BV (†) |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 2,000,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Petromar Lda (†) |  | Luanda (Angola) |  | Angola |  | USD |  | 357,142.85 |  | Saipem SA Third parties |  | 70.00 30.00 |  |  |  | Eq.
Sabella SAS |  | Quimper (France) |  | France |  | EUR |  | 5,263,495 |  | Sofresid Engine. SA Third parties |  | 22.04 77.96 |  |  |  | Eq.
Saidel Ltd (†) |  | Victoria Island, Lagos (Nigeria) |  | Nigeria |  | NGN |  | 236,650,000 |  | Saipem Intern. BV Third parties |  | 49.00 51.00 |  |  |  | Eq.
Saipar Drilling Co BV (†) |  | Amsterdam (Netherlands) |  | Netherlands |  | EUR |  | 20,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Saipem Taqa Al Rushaid Fabricators Co Ltd |  | Dammam (Saudi Arabia) |  | Saudi Arabia |  | SAR |  | 40,000,000 |  | Saipem Intern. BV Third parties |  | 40.00 60.00 |  |  |  | Eq.
Saipon Snc (†) |  | Montigny-le-Bretonneux (France) |  | France |  | EUR |  | 20,000 |  | Saipem SA Third parties |  | 60.00 40.00 |  | 25.87 |  | J.O.
Sairus Llc (†) |  | Krasnodar (Russia) |  | Russia |  | RUB |  | 83,603,800 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Société pour la Réalisation du Port de Tanger Méditerranée (†) |  | Anjra (Morocco) |  | Morocco |  | EUR |  | 33,000 |  | Saipem SA Third parties |  | 33.33 66.67 |  |  |  | Eq.
Southern Gas Constructors Ltd (†) |  | Lagos (Nigeria) |  | Nigeria |  | NGN |  | 10,000,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
SPF - TKP Omifpro Snc (†) |  | Paris (France) |  | France |  | EUR |  | 50,000 |  | Saipem SA Third parties |  | 50.00 50.00 |  | 21.56 |  | J.O.
Sud-Soyo Urban Development Lda (†) |  | Soyo (Angola) |  | Angola |  | AOA |  | 20,000,000 |  | Saipem SA Third parties |  | 49.00 51.00 |  |  |  | Eq.
Tchad Cameroon Maintenance BV (†) |  | Rotterdam (Netherlands) |  | Cameroon |  | EUR |  | 18,000 |  | Saipem SA Third parties |  | 40.00 60.00 |  |  |  | Eq.
T.C.P.I. Angola Tecnoprojecto Internacional SA |  | Luanda (Angola) |  | Angola |  | AOA |  | 9,000,000 |  | Petromar Lda Third parties |  | 35.00 65.00 |  |  |  |
Tecnoprojecto Internacional Projectos e Realizações Industriais SA |  | Porto Salvo Concelho De Oeiras (Portugal) |  | Portugal |  | EUR |  | 700,000 |  | Saipem SA Third parties |  | 42.50 57.50 |  |  |  | Eq.
TMBYS SAS (†) |  | Guyancourt (France) |  | Morocco |  | EUR |  | 30,000 |  | Saipem SA Third parties |  | 33.33 66.67 |  |  |  | Eq.
TSGI Muhendislik Insaat Ltd Sirketi (†) |  | Istanbul (Turkey) |  | Turkey |  | TRY |  | 600,000 |  | Saipem Ing y C. SLU Third parties |  | 30.00 70.00 |  |  |  | Eq.
TSKJ - Serviços de Engenharia Lda |  | Funchal (Portugal) |  | Portugal |  | EUR |  | 5,000 |  | Snamprog. Netherl. BV Third parties |  | 25.00 75.00 |  |  |  | Eq.
Xodus Subsea Ltd (†) |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 1,000,000 |  | Saipem Intern. BV Third parties |  | 50.00 50.00 |  |  |  | Eq.
Other activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cengio Sviluppo ScpA (in liquidation) |  | Genova |  | Italy |  | EUR |  | 120,255.03 |  | Syndial SpA Third parties |  | 40.00 60.00 |  |  |  | Eq.
Filatura Tessile Nazionale Italiana - FILTENI SpA (in liquidation) |  | Ferrandina (MT) |  | Italy |  | EUR |  | 4,644,000 |  | Syndial SpA Third parties |  | 59.56 40.44 | (a) |  |  | Co.
Ottana Sviluppo ScpA (in liquidation) |  | Nuoro |  | Italy |  | EUR |  | 516,000 |  | Syndial SpA Third parties |  | 30.00 70.00 |  |  |  | Eq.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†) |  | Jointly controlled entity.

(a) |  | Controlling interest: | Syndial SpA | 48.00 |
|  |  | Third parties | 52.00 |

F-132

##### Table of Contents

Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Other significant investments |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration & Production |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

Consorzio Universitario in Ingegneria per la Qualità e l’Innovazione |  | Pisa |  | Italy |  | EUR |  | 135,000 |  | Eni SpA Third parties |  | 16.67 83.33 |  |  |  | Co.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Administradora del Golfo de Paria Este SA |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 100 |  | Eni Venezuela BV Third parties |  | 19.50 80.50 |  |  |  | Co.
Brass LNG Ltd |  | Lagos (Nigeria) |  | Nigeria |  | USD |  | 1,000,000 |  | Eni Int. NA NV Sàrl Third parties |  | 20.48 79.52 |  |  |  | Co.
Darwin LNG Pty Ltd |  | West Perth (Australia) |  | Australia |  | AUD |  | 1,111,019,258 |  | Eni G&P LNG Aus BV Third parties |  | 10.99 89.01 |  |  |  | Co.
New Liberty Residential Co Llc |  | West Trenton (USA) |  | USA |  | USD |  | 0 (a) |  | Eni Oil & Gas Inc Third parties |  | 17.50 82.50 |  |  |  | Co.
Nigeria LNG Ltd |  | Port Harcourt (Nigeria) |  | Nigeria |  | USD |  | 1,138,207,000 |  | Eni Int. NA NV Sàrl Third parties |  | 10.40 89.60 |  |  |  | Co.
Norsea Pipeline Ltd |  | Woking Surrey (United Kingdom) |  | United Kingdom |  | GBP |  | 7,614,062 |  | Eni SpA Third parties |  | 10.32 89.68 |  |  |  | Co.
North Caspian Operating Co BV |  | The Hague (Netherlands) |  | Netherlands |  | EUR |  | 128,520 |  | Agip Caspian Sea BV Third parties |  | 16.81 83.19 |  |  |  | Co.
North Caspian Transportation Manager Co BV |  | Amsterdam (Netherlands) |  | Kazakhstan |  | EUR |  | 100,010 |  | Agip Caspian Sea BV Third parties |  | 16.81 83.19 |  |  |  | Co.
OPCO - Sociedade Operacional Angola LNG SA |  | Luanda (Angola) |  | Angola |  | AOA |  | 7,400,000 |  | Eni Angola Prod.BV Third parties |  | 13.60 86.40 |  |  |  | Co.
Petrolera Güiria SA |  | Caracas (Venezuela) |  | Venezuela |  | VEF |  | 1,000,000 |  | Eni Venezuela BV Third parties |  | 19.50 80.50 |  |  |  | Co.
Point Fortin LNG Exports Ltd |  | Port of Spain (Trinidad & Tobago) |  | Trinidad & Tobago |  | USD |  | 10,000 |  | Eni T&T Ltd Third parties |  | 17.31 82.69 |  |  |  | Co.
SOMG - Sociedade de Operações e Manutenção de Gasodutos SA |  | Luanda (Angola) |  | Angola |  | AOA |  | 7,400,000 |  | Eni Angola Prod. BV Third parties |  | 13.60 86.40 |  |  |  | Co.
Torsina Oil Co |  | Cairo (Egypt) |  | Egypt |  | EGP |  | 20,000 |  | Ieoc Production BV Third parties |  | 12.50 87.50 |  |  |  | Co.
Gas & Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Angola LNG Supply Services Llc |  | Wilmington (USA) |  | USA |  | USD |  | 19,278,782 |  | Eni USA Gas M. Llc Third parties |  | 13.60 86.40 |  |  |  | Co.
Norsea Gas GmbH |  | Emden (Germany) |  | Germany |  | EUR |  | 1,533,875.64 |  | Eni International BV Third parties |  | 13.04 86.96 |  |  |  | Co.
Refining & Marketing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consorzio Obbligatorio degli Oli Usati |  | Rome |  | Italy |  | EUR |  | 36,149 |  | Eni SpA Third parties |  | 14.41 85.59 |  |  |  | Co.
Società Italiana Oleodotti di Gaeta SpA (1) |  | Rome |  | Italy |  | ITL |  | 360,000,000 |  | Eni SpA Third parties |  | 72.48 27.52 |  |  |  | Co.

(*) |  | Consolidation or valuation method: F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†) |  | Jointly controlled entity.
(a) |  | Shares without nominal value.
(1) |  | Company under extraordinary administration procedure pursuant to Law No. 95 of April 3, 1979.

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Company name |  | Registered office |  | Country of operation |  | Currency |  | Share Capital |  | Shareholders |  | % Ownership |  | % Equity ratio |  | (*)

Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
BFS Berlin Fuelling Services GbR |  | Hamburg (Germany) |  | Germany |  | EUR |  | 150,511 |  | Eni Deutsch. GmbH Third parties |  | 12.50 87.50 |  |  |  | Co.
Compania de Economia Mixta ‘Austrogas’ |  | Cuenca (Ecuador) |  | Ecuador |  | USD |  | 3,028,749 |  | Eni Ecuador SA Third parties |  | 13.31 86.69 |  |  |  | Co.
Dépot Pétrolier de Fos SA |  | Fos-sur-Mer (France) |  | France |  | EUR |  | 3,954,196.40 |  | Eni France Sàrl Third parties |  | 16.81 83.19 |  |  |  | Co.
Dépôt Pétrolier de la Côte d’Azur SAS |  | Nanterre (France) |  | France |  | EUR |  | 207,500 |  | Eni France Sàrl Third parties |  | 18.00 82.00 |  |  |  | Co.
Joint Inspection Group Ltd |  | London (United Kingdom) |  | United Kingdom |  | GBP |  | 0 (a) |  | Eni SpA Third parties |  | 12.50 87.50 |  |  |  | Co.
S.I.P.G. Société Immobilier Pétrolier de Gestion Snc |  | Tremblay en France (France) |  | France |  | EUR |  | 40,000 |  | Eni France Sàrl Third parties |  | 12.50 87.50 |  |  |  | Co.
Sistema Integrado de Gestion de Aceites Usados |  | Madrid (Spain) |  | Spain |  | EUR |  | 181,427 |  | Eni Iberia SLU Third parties |  | 14.96 85.04 |  |  |  | Co.
Tanklager - Gesellschaft Tegel (TGT) GbR |  | Hamburg (Germany) |  | Germany |  | EUR |  | 23 |  | Eni Deutsch. GmbH Third parties |  | 12.50 87.50 |  |  |  | Co.
TAR - Tankanlage Ruemlang AG |  | Ruemlang (Switzerland) |  | Switzerland |  | CHF |  | 3,259,500 |  | Eni Suisse SA Third parties |  | 16.27 83.73 |  |  |  | Co.
Tema Lube Oil Co Ltd |  | Accra (Ghana) |  | Ghana |  | GHS |  | 258,309 |  | Eni International BV Third parties |  | 12.00 88.00 |  |  |  | Co.
Corporate and financial companies |  |  |  |  |  |  |  |  |  |  |  |  |  |
In Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consorzio per l’Innovazione nella Gestione delle Imprese e della Pubblica Amministrazione |  | Milan |  | Italy |  | EUR |  | 150,000 |  | Eni Corporate U. SpA Third parties |  | 10.67 89.33 |  |  |  | Co.
Emittenti Titoli SpA |  | Milan |  | Italy |  | EUR |  | 4,264,000 |  | Eni SpA Emittenti Titoli SpA Third parties |  | 10.00 0.78 89.22 |  |  |  | Co.
Snam SpA (#) |  | San Donato Milanese (MI) |  | Italy |  | EUR |  | 3,696,851,994 |  | Eni SpA Snam SpA Third parties |  | 8.25 0.08 91.67 |  |  |  | F.V.
Outside Italy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Galp Energia SGPS SA (#) |  | Lisbon (Portugal) |  | Portugal |  | EUR |  | 829,250,635 |  | Eni SpA Third parties |  | 8.00 92.00 |  |  |  | F.V.

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

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Information on Eni’s consolidated subsidiaries with significant non-controlling interest
The following table sets forth the main line items of profit and loss, balance sheet and cash flow statement including intragroup transactions related to Saipem Group, de facto controlled by Eni due to a wide dispersion of the other shareholdings of the parent company Saipem SpA. The ownership interest of the non-controlling interest corresponds to the voting rights.

|  | 2013 |  | 2014

(euro million) |  | Saipem Group |  | Saipem Group

Non-controlling interest (%) |  | 56.89 |  |  | 56.89 |
Current assets |  | 7,763 |  |  | 8,632 |
Non-current assets |  | 9,129 |  |  | 8,996 |
Current liabilities |  | 8,769 |  |  | 9,605 |
Non-current liabilities |  | 3,349 |  |  | 3,828 |
Revenues |  | 11,598 |  |  | 12,873 |
Net profit (loss) for the year |  | (349 | ) |  | (621 | )
Total comprehensive income (loss) for the year |  | (435 | ) |  | (555 | )
Net cash provided by operating activities |  | 455 |  |  | 1,198 |
Net cash used in investing activities |  | (506 | ) |  | (699 | )
Net cash used in financing activities |  | 153 |  |  | (214 | )
Net cash flow of the year |  | 60 |  |  | 305 |
Net profit (loss) for the year attributable to non-controlling interest |  | (190 | ) |  | (345 | )
Dividends paid to non-controlling interest |  | 245 |  |  | 45 |

Total shareholders’ equity attributable to non-controlling interest amounted to euro 2,455 million, of which euro 2,398 million pertaining to the Saipem Group (euro 2,839 million at December 31, 2013, of which euro 2,748 million pertaining to the Saipem Group).

Changes in the ownership interest without loss of control
In 2014, Eni did not report any Changes in the ownership interest without loss or acquisition of control.

In 2013, Eni acquired the 45.27% of its subsidiary Tigáz Zrt for a total consideration of euro 28 million. The book value of the shareholders’ equity acquired was euro 32 million with a corresponding negative goodwill amounting to euro 4 million.

Principal joint ventures, joint operations and associates as of December 31, 2014

Company name |  | Registered office |  | Operating office |  | Business segment |  | % ownership interest |  | % voting rights

Joint venture |  |  |  |  |  |  |  |  |  |
CARDÓN IV SA |  | Caracas (Venezuela) |  | Venezuela |  | Exploration & Production |  | 50.00 |  | 50.00
Eteria Parohis AeriouThessalonikis AE |  | Ampelokipi-Menemeni (Greece) |  | Greece |  | Gas & Power |  | 49.00 |  | 49.00
Unión Fenosa Gas SA |  | Madrid (Spain) |  | Spain |  | Gas & Power |  | 50.00 |  | 50.00
Joint operation |  |  |  |  |  |  |  |  |  |
Blue Stream Pipeline Co BV |  | Amsterdam (Netherlands) |  | Russia |  | Gas & Power |  | 50.00 |  | 50.00
Eni East Africa SpA |  | San Donato Milanese (MI) (Italy) |  | Mozambique |  | Exploration & Production |  | 71.43 |  | 71.43
GreenStream BV |  | Amsterdam (Netherlands) |  | Libya |  | Gas & Power |  | 50.00 |  | 50.00
Raffineria di Milazzo ScpA |  | Milazzo (ME) (Italy) |  | Italy |  | Refining & Marketing |  | 50.00 |  | 50.00
Associates |  |  |  |  |  |  |  |  |  |
Angola LNG Ltd |  | Hamilton (Bermuda) |  | Angola |  | Exploration & Production |  | 13.60 |  | 13.60
PetroSucre SA |  | Caracas (Venezuela) |  | Venezuela |  | Exploration & Production |  | 26.00 |  | 26.00
United Gas Derivatives Co |  | Cairo (Egypt) |  | Egypt |  | Exploration & Production |  | 33.33 |  | 33.33

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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:

|  | 2013 |  | 2014

(euro million) |  | CARDÓN IV SA |  | Eteria Parohis Aeriou Thessalonikis AE |  | Unión Fenosa Gas SA |  | Other joint ventures |  | CARDÓN IV SA |  | Eteria Parohis Aeriou Thessalonikis AE |  | Unión Fenosa Gas SA |  | Other joint ventures

Current assets |  | 341 |  |  | 61 |  |  | 751 |  |  | 1,740 |  |  | 871 |  |  | 43 |  |  | 715 |  |  | 939 |
- of which cash and cash equivalent |  | 32 |  |  | 31 |  |  | 92 |  |  | 258 |  |  | 43 |  |  | 25 |  |  | 87 |  |  | 361 |
Non-current assets |  | 916 |  |  | 213 |  |  | 1,352 |  |  | 880 |  |  | 1,674 |  |  | 208 |  |  | 1,246 |  |  | 1,439 |
Total assets |  | 1,257 |  |  | 274 |  |  | 2,103 |  |  | 2,620 |  |  | 2,545 |  |  | 251 |  |  | 1,961 |  |  | 2,378 |
Current liabilities |  | 907 |  |  | 8 |  |  | 304 |  |  | 1,968 |  |  | 2,089 |  |  | 24 |  |  | 270 |  |  | 1,469 |
- current financial liabilities |  | 492 |  |  |  |  |  | 78 |  |  | 290 |  |  | 1,248 |  |  |  |  |  | 62 |  |  | 408 |
Non-current liabilities |  | 146 |  |  |  |  |  | 900 |  |  | 93 |  |  | 164 |  |  |  |  |  | 732 |  |  | 188 |
- non-current financial liabilities |  |  |  |  |  |  |  | 803 |  |  | 25 |  |  |  |  |  |  |  |  | 647 |  |  | 31 |
Total liabilities |  | 1,053 |  |  | 8 |  |  | 1,204 |  |  | 2,061 |  |  | 2,253 |  |  | 24 |  |  | 1,002 |  |  | 1,657 |
Net equity |  | 204 |  |  | 266 |  |  | 899 |  |  | 559 |  |  | 292 |  |  | 227 |  |  | 959 |  |  | 721 |
Eni’s ownership interest (%) |  | 50.00 |  |  | 49.00 |  |  | 50.00 |  |  |  |  |  | 50.00 |  |  | 49.00 |  |  | 50.00 |  |  |  |
Book value of the investment |  | 102 |  |  | 130 |  |  | 547 |  |  | 262 |  |  | 146 |  |  | 111 |  |  | 577 |  |  | 346 |
Revenues and other operating income |  |  |  |  | 130 |  |  | 1,586 |  |  | 1,899 |  |  |  |  |  | 117 |  |  | 1,619 |  |  | 1,174 |
Operating expense |  | (9 | ) |  | (88 | ) |  | (1,413 | ) |  | (1,759 | ) |  | (7 | ) |  | (80 | ) |  | (1,463 | ) |  | (918 | )
Depreciation, depletion, amortization and impairments |  | (1 | ) |  | (13 | ) |  | (55 | ) |  | (241 | ) |  | (2 | ) |  | (14 | ) |  | (50 | ) |  | (284 | )
Operating profit |  | (10 | ) |  | 29 |  |  | 118 |  |  | (101 | ) |  | (9 | ) |  | 23 |  |  | 106 |  |  | (28 | )
Finance (expense) income |  | (16 | ) |  | 1 |  |  | (28 | ) |  | 267 |  |  | 63 |  |  | 1 |  |  | (34 | ) |  | 14 |
Income (expense) from investments |  |  |  |  |  |  |  | 12 |  |  | (9 | ) |  |  |  |  |  |  |  | 26 |  |  | (20 | )
Profit before income taxes |  | (26 | ) |  | 30 |  |  | 102 |  |  | 157 |  |  | 54 |  |  | 24 |  |  | 98 |  |  | (34 | )
Income taxes |  | 68 |  |  | (7 | ) |  | (26 | ) |  | (108 | ) |  | 2 |  |  | (6 | ) |  | (14 | ) |  | (97 | )
Net profit |  | 42 |  |  | 23 |  |  | 76 |  |  | 49 |  |  | 56 |  |  | 18 |  |  | 84 |  |  | (131 | )
Other comprehensive income |  | (9 | ) |  |  |  |  | 4 |  |  | (49 | ) |  | 33 |  |  |  |  |  | 22 |  |  | 45 |
Total other comprehensive income |  | 33 |  |  | 23 |  |  | 80 |  |  |  |  |  | 89 |  |  | 18 |  |  | 106 |  |  | (86 | )
Net profit attributable to Eni |  | 21 |  |  | 11 |  |  | 38 |  |  | 31 |  |  | 28 |  |  | 9 |  |  | 42 |  |  | 26 |
Dividends received by the joint ventures |  |  |  |  | 11 |  |  |  |  |  | 36 |  |  |  |  |  | 10 |  |  | 23 |  |  | 65 |

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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:

|  | 2013 |  | 2014

(euro million) |  | Angola LNG Ltd |  | EnBW Eni Verwaltungs gesellschaft mbH |  | PetroSucre SA |  | United Gas Derivatives Co |  | Other associates |  | Angola LNG Ltd |  | PetroSucre SA |  | United Gas Derivatives Co |  | Other associates

Current assets |  | 241 |  |  | 328 |  |  | 883 |  |  | 255 |  |  | 973 |  |  | 318 |  |  | 1,503 |  |  | 361 |  |  | 1,232 |
- of which cash and cash equivalent |  | 108 |  |  | 68 |  |  | 59 |  |  | 83 |  |  | 274 |  |  | 167 |  |  | 5 |  |  | 171 |  |  | 124 |
Non-current assets |  | 8,109 |  |  | 414 |  |  | 788 |  |  | 144 |  |  | 1,629 |  |  | 9,389 |  |  | 736 |  |  | 137 |  |  | 635 |
Total assets |  | 8,350 |  |  | 742 |  |  | 1,671 |  |  | 399 |  |  | 2,602 |  |  | 9,707 |  |  | 2,239 |  |  | 498 |  |  | 1,867 |
Current liabilities |  | 234 |  |  | 263 |  |  | 935 |  |  | 92 |  |  | 983 |  |  | 484 |  |  | 1,515 |  |  | 167 |  |  | 1,118 |
- current financial liabilities |  |  |  |  | 254 |  |  |  |  |  |  |  |  | 125 |  |  |  |  |  |  |  |  |  |  |  | 86 |
Non-current liabilities |  | 269 |  |  | 137 |  |  | 71 |  |  | 20 |  |  | 318 |  |  | 210 |  |  | 67 |  |  | 24 |  |  | 202 |
- non-current financial liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  | 21 |  |  |  |  |  |  |  |  |  |  |  | 46 |
Total liabilities |  | 503 |  |  | 400 |  |  | 1,006 |  |  | 112 |  |  | 1,301 |  |  | 694 |  |  | 1,582 |  |  | 191 |  |  | 1,320 |
Net equity |  | 7,847 |  |  | 342 |  |  | 665 |  |  | 287 |  |  | 1,301 |  |  | 9,013 |  |  | 657 |  |  | 307 |  |  | 547 |
Eni’s ownership interest (%) |  | 13.60 |  |  | 50.00 |  |  | 26.00 |  |  | 33.33 |  |  |  |  |  | 13.60 |  |  | 26.00 |  |  | 33.33 |  |  |  |
Book value of the investment |  | 1,067 |  |  | 179 |  |  | 173 |  |  | 96 |  |  | 373 |  |  | 1,226 |  |  | 171 |  |  | 102 |  |  | 208 |
Revenues and other operating income |  | 194 |  |  | 1,678 |  |  | 911 |  |  | 312 |  |  | 1,272 |  |  |  |  |  | 824 |  |  | 229 |  |  | 1,391 |
Operating expense |  | (413 | ) |  | (1,619 | ) |  | (621 | ) |  | (54 | ) |  | (1,191 | ) |  | (237 | ) |  | (554 | ) |  | (64 | ) |  | (1,333 | )
Depreciation, depletion, amortization and impairments |  |  |  |  | (24 | ) |  | (148 | ) |  | (32 | ) |  | (79 | ) |  |  |  |  | (214 | ) |  | (23 | ) |  | (63 | )
Operating profit |  | (219 | ) |  | 35 |  |  | 142 |  |  | 226 |  |  | 2 |  |  | (237 | ) |  | 56 |  |  | 142 |  |  | (5 | )
Finance (expense) income |  | (16 | ) |  |  |  |  | 46 |  |  |  |  |  | 7 |  |  | (14 | ) |  | (6 | ) |  | 3 |  |  | (2 | )
Income (expense) from investments |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  |  |  |  | 7 |
Profit before income taxes |  | (235 | ) |  | 35 |  |  | 188 |  |  | 226 |  |  | 10 |  |  | (251 | ) |  | 50 |  |  | 145 |  |  |  |
Income taxes |  | (76 | ) |  | (7 | ) |  | (20 | ) |  | (58 | ) |  | (12 | ) |  |  |  |  | (27 | ) |  | (50 | ) |  | (14 | )
Net profit |  | (311 | ) |  | 28 |  |  | 168 |  |  | 168 |  |  | (2 | ) |  | (251 | ) |  | 23 |  |  | 95 |  |  | (14 | )
Other comprehensive income |  | (352 | ) |  |  |  |  | (32 | ) |  | (13 | ) |  | (10 | ) |  | 1,075 |  |  | 82 |  |  | 37 |  |  | 3 |
Total other comprehensive income |  | (663 | ) |  | 28 |  |  | 136 |  |  | 155 |  |  | (12 | ) |  | 824 |  |  | 105 |  |  | 132 |  |  | (11 | )
Net profit attributable to Eni |  | (42 | ) |  | 14 |  |  | 44 |  |  | 56 |  |  | 25 |  |  | (34 | ) |  | 6 |  |  | 32 |  |  | (6 | )
Dividends received by associates |  |  |  |  |  |  |  | 105 |  |  | 60 |  |  | 30 |  |  |  |  |  | 29 |  |  | 36 |  |  | 13 |

46 Significant non-recurring events and operations
In 2012, in 2013 and 2014, Eni did not report any non-recurring events and operations.

47 Positions or transactions deriving from atypical and/or unusual operations
In 2012, 2013 and 2014 no transactions deriving from atypical and/or unusual operations were reported.

48 Subsequent events

No significant events were reported after December 31, 2014.

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Supplemental oil and gas information (unaudited)

The following information pursuant to "International Financial Reporting Standards" (IFRS) is presented in accordance with FASB Extractive Activities - Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs
Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following:

(euro million) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved mineral interests |  | 13,465 |  |  | 12,497 |  |  | 18,237 |  |  | 21,854 |  |  | 2,351 |  |  | 6,604 |  |  | 10,652 |  |  | 1,662 |  |  | 87,322 |
Unproved mineral interests |  | 31 |  |  | 385 |  |  | 428 |  |  | 2,835 |  |  | 37 |  |  | 1,441 |  |  | 1,419 |  |  | 190 |  |  | 6,766 |
Support equipment and facilities |  | 269 |  |  | 37 |  |  | 1,370 |  |  | 992 |  |  | 78 |  |  | 90 |  |  | 57 |  |  | 12 |  |  | 2,905 |
Incomplete wells and other |  | 799 |  |  | 2,803 |  |  | 1,105 |  |  | 1,851 |  |  | 6,069 |  |  | 634 |  |  | 669 |  |  | 24 |  |  | 13,954 |
Gross capitalized costs |  | 14,564 |  |  | 15,722 |  |  | 21,140 |  |  | 27,532 |  |  | 8,535 |  |  | 8,769 |  |  | 12,797 |  |  | 1,888 |  |  | 110,947 |
Accumulated depreciation, depletion and amortization |  | (10,241 | ) |  | (8,581 | ) |  | (11,370 | ) |  | (15,562 | ) |  | (1,000 | ) |  | (6,269 | ) |  | (8,406 | ) |  | (723 | ) |  | (62,152 | )
Net capitalized costs consolidated subsidiaries (a) (b) |  | 4,323 |  |  | 7,141 |  |  | 9,770 |  |  | 11,970 |  |  | 7,535 |  |  | 2,500 |  |  | 4,391 |  |  | 1,165 |  |  | 48,795 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved mineral interests |  |  |  |  | 2 |  |  | 77 |  |  | 34 |  |  |  |  |  | 438 |  |  | 429 |  |  |  |  |  | 980 |
Unproved mineral interests |  |  |  |  | 52 |  |  |  |  |  |  |  |  |  |  |  | 74 |  |  |  |  |  |  |  |  | 126 |
Support equipment and facilities |  |  |  |  |  |  |  | 7 |  |  |  |  |  |  |  |  | 1 |  |  | 3 |  |  |  |  |  | 11 |
Incomplete wells and other |  |  |  |  | 20 |  |  | 4 |  |  | 1,059 |  |  |  |  |  |  |  |  | 378 |  |  |  |  |  | 1,461 |
Gross capitalized costs |  |  |  |  | 74 |  |  | 88 |  |  | 1,093 |  |  |  |  |  | 513 |  |  | 810 |  |  |  |  |  | 2,578 |
Accumulated depreciation, depletion and amortization |  |  |  |  | (56 | ) |  | (67 | ) |  |  |  |  |  |  |  | (405 | ) |  | (145 | ) |  |  |  |  | (673 | )
Net capitalized costs equity-accounted entities (a) (b) |  |  |  |  | 18 |  |  | 21 |  |  | 1,093 |  |  |  |  |  | 108 |  |  | 665 |  |  |  |  |  | 1,905 |
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved mineral interests |  | 14,862 |  |  | 13,754 |  |  | 21,549 |  |  | 27,697 |  |  | 2,917 |  |  | 8,827 |  |  | 13,050 |  |  | 1,825 |  |  | 104,481 |
Unproved mineral interests |  | 31 |  |  | 399 |  |  | 493 |  |  | 3,263 |  |  | 43 |  |  | 1,590 |  |  | 1,588 |  |  | 214 |  |  | 7,621 |
Support equipment and facilities |  | 346 |  |  | 42 |  |  | 1,569 |  |  | 1,164 |  |  | 94 |  |  | 35 |  |  | 66 |  |  | 13 |  |  | 3,329 |
Incomplete wells and other |  | 816 |  |  | 3,527 |  |  | 1,411 |  |  | 2,988 |  |  | 7,140 |  |  | 690 |  |  | 819 |  |  | 120 |  |  | 17,511 |
Gross capitalized costs |  | 16,055 |  |  | 17,722 |  |  | 25,022 |  |  | 35,112 |  |  | 10,194 |  |  | 11,142 |  |  | 15,523 |  |  | 2,172 |  |  | 132,942 |
Accumulated depreciation, depletion and amortization |  | (11,154 | ) |  | (9,519 | ) |  | (14,335 | ) |  | (20,039 | ) |  | (1,241 | ) |  | (8,042 | ) |  | (10,605 | ) |  | (1,009 | ) |  | (75,944 | )
Net capitalized costs consolidated subsidiaries (a) (b) |  | 4,901 |  |  | 8,203 |  |  | 10,687 |  |  | 15,073 |  |  | 8,953 |  |  | 3,100 |  |  | 4,918 |  |  | 1,163 |  |  | 56,998 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved mineral interests |  |  |  |  | 2 |  |  | 77 |  |  | 24 |  |  |  |  |  | 539 |  |  | 549 |  |  |  |  |  | 1,191 |
Unproved mineral interests |  |  |  |  | 31 |  |  |  |  |  |  |  |  |  |  |  | 84 |  |  |  |  |  |  |  |  | 115 |
Support equipment and facilities |  |  |  |  |  |  |  | 7 |  |  |  |  |  |  |  |  | 1 |  |  | 4 |  |  |  |  |  | 12 |
Incomplete wells and other |  |  |  |  | 12 |  |  | 5 |  |  | 1,241 |  |  |  |  |  |  |  |  | 776 |  |  |  |  |  | 2,034 |
Gross capitalized costs |  |  |  |  | 45 |  |  | 89 |  |  | 1,265 |  |  |  |  |  | 624 |  |  | 1,329 |  |  |  |  |  | 3,352 |
Accumulated depreciation, depletion and amortization |  |  |  |  | (39 | ) |  | (69 | ) |  |  |  |  |  |  |  | (522 | ) |  | (230 | ) |  |  |  |  | (860 | )
Net capitalized costs equity-accounted entities (a) (b) |  |  |  |  | 6 |  |  | 20 |  |  | 1,265 |  |  |  |  |  | 102 |  |  | 1,099 |  |  |  |  |  | 2,492 |

(a) |  | The amounts include net capitalized financial charges totaling euro 715 million in 2013 and euro 868 million in 2014 for the consolidated subsidiaries and euro 12 million in 2013 and euro 46 million in 2014 for equity-accounted entities.
(b) |  | The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The "Successful Effort Method" application according to Eni accounting policy would have led to an increase in net capitalized costs, mainly in relation to exploration costs, of euro 4,378 million in 2013 and euro 4,786 million in 2014 for the consolidated subsidiaries and euro 86 million in 2013 and euro 123 million in 2014 for equity-accounted entities.

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Costs incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(euro million) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  | 14 |  | 27 |  |  |  |  |  | 2 |  |  |  | 43
Unproved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration |  | 32 |  | 151 |  | 153 |  | 1,142 |  | 3 |  | 193 |  | 80 |  | 96 |  | 1,850
Development (a) |  | 1,045 |  | 2,485 |  | 1,441 |  | 2,246 |  | 762 |  | 702 |  | 1,071 |  | 16 |  | 9,768
Total costs incurred consolidated subsidiaries |  | 1,077 |  | 2,636 |  | 1,608 |  | 3,415 |  | 765 |  | 895 |  | 1,153 |  | 112 |  | 11,661
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unproved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration |  |  |  | 13 |  | 2 |  | 11 |  |  |  | 4 |  |  |  |  |  | 30
Development (b) |  |  |  | 19 |  | 7 |  | 117 |  |  |  | 188 |  | 154 |  |  |  | 485
Total costs incurred equity-accounted entities |  |  |  | 32 |  | 9 |  | 128 |  |  |  | 192 |  | 154 |  |  |  | 515
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  | 64 |  |  |  |  |  |  |  |  |  |  |  | 64
Unproved property acquisitions |  |  |  |  |  | 45 |  |  |  |  |  |  |  |  |  |  |  | 45
Exploration |  | 32 |  | 357 |  | 95 |  | 757 |  | 1 |  | 233 |  | 110 |  | 84 |  | 1,669
Development (a) |  | 697 |  | 1,855 |  | 765 |  | 2,617 |  | 600 |  | 719 |  | 1,141 |  | 57 |  | 8,451
Total costs incurred consolidated subsidiaries |  | 729 |  | 2,212 |  | 969 |  | 3,374 |  | 601 |  | 952 |  | 1,251 |  | 141 |  | 10,229
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unproved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration |  |  |  | 5 |  | 3 |  |  |  |  |  | 81 |  | 1 |  |  |  | 90
Development (b) |  |  |  | 1 |  | 5 |  | 39 |  |  |  | 353 |  | 318 |  |  |  | 716
Total costs incurred equity-accounted entities |  |  |  | 6 |  | 8 |  | 39 |  |  |  | 434 |  | 319 |  |  |  | 806
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unproved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration |  | 29 |  | 188 |  | 227 |  | 635 |  |  |  | 160 |  | 139 |  | 20 |  | 1,398
Development (a) |  | 1,382 |  | 2,395 |  | 955 |  | 3,479 |  | 572 |  | 1,118 |  | 1,169 |  | 122 |  | 11,192
Total costs incurred consolidated subsidiaries |  | 1,411 |  | 2,583 |  | 1,182 |  | 4,114 |  | 572 |  | 1,278 |  | 1,308 |  | 142 |  | 12,590
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unproved property acquisitions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploration |  |  |  | 2 |  |  |  |  |  |  |  | 33 |  | 1 |  |  |  | 36
Development (b) |  |  |  | 0 |  | 1 |  | 22 |  |  |  | 38 |  | 375 |  |  |  | 436
Total costs incurred equity-accounted entities |  |  |  | 2 |  | 1 |  | 22 |  |  |  | 71 |  | 376 |  |  |  | 472

(a) |  | Includes the abandonment costs of the assets for euro 1,381 million in 2012, negative for euro 191 million in 2013 and euro 2,062 million in 2014.
(b) |  | Includes the abandonment costs of the assets for euro 63 million in 2012, for euro 10 million in 2013 and negative for euro 47 million in 2014.

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Results of operations from oil and gas producing activities
Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a party to certain production sharing agreements, 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 in satisfaction of Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.

Results of operations from oil and gas producing activities by geographical area consist of the following:

(euro million) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  | 3,712 |  |  | 3,177 |  |  | 2,338 |  |  | 6,040 |  |  | 459 |  |  | 425 |  |  | 1,614 |  |  | 425 |  |  | 18,190 |
- sales to third parties |  | 50 |  |  | 715 |  |  | 9,129 |  |  | 2,243 |  |  | 1,368 |  |  | 1,387 |  |  | 106 |  |  | 333 |  |  | 15,331 |
Total revenues |  | 3,762 |  |  | 3,892 |  |  | 11,467 |  |  | 8,283 |  |  | 1,827 |  |  | 1,812 |  |  | 1,720 |  |  | 758 |  |  | 33,521 |
Operations costs |  | (302 | ) |  | (655 | ) |  | (606 | ) |  | (913 | ) |  | (188 | ) |  | (209 | ) |  | (361 | ) |  | (134 | ) |  | (3,368 | )
Production taxes |  | (307 | ) |  |  |  |  | (390 | ) |  | (818 | ) |  |  |  |  | (43 | ) |  |  |  |  |  |  |  | (1,558 | )
Exploration expenses |  | (32 | ) |  | (154 | ) |  | (153 | ) |  | (993 | ) |  | (3 | ) |  | (230 | ) |  | (147 | ) |  | (123 | ) |  | (1,835 | )
D.D. & A. and provision for abandonment (a) |  | (777 | ) |  | (683 | ) |  | (1,137 | ) |  | (1,750 | ) |  | (120 | ) |  | (720 | ) |  | (1,256 | ) |  | (167 | ) |  | (6,610 | )
Other income (expense) |  | (201 | ) |  | (122 | ) |  | (934 | ) |  | (435 | ) |  | 206 |  |  | (149 | ) |  | 74 |  |  | (42 | ) |  | (1,603 | )
Pre-tax income from producing activities |  | 2,143 |  |  | 2,278 |  |  | 8,247 |  |  | 3,374 |  |  | 1,722 |  |  | 461 |  |  | 30 |  |  | 292 |  |  | 18,547 |
Income taxes |  | (919 | ) |  | (1,524 | ) |  | (5,194 | ) |  | (2,508 | ) |  | (736 | ) |  | (176 | ) |  | (14 | ) |  | (164 | ) |  | (11,235 | )
Results of operations from E&P activities of consolidated subsidiaries (b) |  | 1,224 |  |  | 754 |  |  | 3,053 |  |  | 866 |  |  | 986 |  |  | 285 |  |  | 16 |  |  | 128 |  |  | 7,312 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to third parties |  |  |  |  | 2 |  |  | 20 |  |  | 44 |  |  |  |  |  | 144 |  |  | 300 |  |  |  |  |  | 510 |
Total revenues |  |  |  |  | 2 |  |  | 20 |  |  | 44 |  |  |  |  |  | 144 |  |  | 300 |  |  |  |  |  | 510 |
Operations costs |  |  |  |  |  |  |  | (10 | ) |  | (5 | ) |  |  |  |  | (14 | ) |  | (20 | ) |  |  |  |  | (49 | )
Production taxes |  |  |  |  | (1 | ) |  | (3 | ) |  |  |  |  |  |  |  | (4 | ) |  | (128 | ) |  |  |  |  | (136 | )
Exploration expenses |  |  |  |  | (5 | ) |  | (2 | ) |  | (11 | ) |  |  |  |  | (4 | ) |  |  |  |  |  |  |  | (22 | )
D.D. & A. and provision for abandonment |  |  |  |  | (50 | ) |  | (2 | ) |  | (13 | ) |  |  |  |  | (41 | ) |  | (35 | ) |  |  |  |  | (141 | )
Other income (expense) |  |  |  |  | (7 | ) |  | 2 |  |  | (48 | ) |  |  |  |  | (6 | ) |  | (55 | ) |  |  |  |  | (114 | )
Pre-tax income from producing activities |  |  |  |  | (61 | ) |  | 5 |  |  | (33 | ) |  |  |  |  | 75 |  |  | 62 |  |  |  |  |  | 48 |
Income taxes |  |  |  |  |  |  |  | (3 | ) |  | 4 |  |  |  |  |  | (36 | ) |  | (38 | ) |  |  |  |  | (73 | )
Results of operations from E&P activities of equity-accounted entities (b) |  |  |  |  | (61 | ) |  | 2 |  |  | (29 | ) |  |  |  |  | 39 |  |  | 24 |  |  |  |  |  | (25 | )

(a) |  | Includes asset impairments amounting to euro 547 million in 2012.
(b) |  | The "Successful Effort Method" application according to accounting Eni policy would have led to an increase of euro 610 million in 2012 for the consolidated subsidiaries; a decrease of euro 10 million in 2012 for equity-accounted entities.

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(euro million) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  | 3,784 |  |  | 2,468 |  |  | 2,341 |  |  | 5,264 |  |  | 396 |  |  | 870 |  |  | 1,537 |  |  | 146 |  |  | 16,806 |
- sales to third parties |  |  |  |  | 704 |  |  | 7,723 |  |  | 1,855 |  |  | 1,175 |  |  | 864 |  |  | 93 |  |  | 338 |  |  | 12,752 |
Total revenues |  | 3,784 |  |  | 3,172 |  |  | 10,064 |  |  | 7,119 |  |  | 1,571 |  |  | 1,734 |  |  | 1,630 |  |  | 484 |  |  | 29,558 |
Operations costs |  | (391 | ) |  | (717 | ) |  | (649 | ) |  | (932 | ) |  | (192 | ) |  | (224 | ) |  | (342 | ) |  | (119 | ) |  | (3,566 | )
Production taxes |  | (326 | ) |  |  |  |  | (317 | ) |  | (710 | ) |  |  |  |  | (38 | ) |  |  |  |  | (25 | ) |  | (1,416 | )
Exploration expenses |  | (32 | ) |  | (288 | ) |  | (95 | ) |  | (869 | ) |  | (1 | ) |  | (205 | ) |  | (136 | ) |  | (110 | ) |  | (1,736 | )
D.D. & A. and provision for abandonment (a) |  | (907 | ) |  | (573 | ) |  | (1,192 | ) |  | (1,882 | ) |  | (111 | ) |  | (524 | ) |  | (848 | ) |  | 43 |  |  | (5,994 | )
Other income (expense) |  | (277 | ) |  | 161 |  |  | (1,009 | ) |  | (519 | ) |  | (105 | ) |  | (140 | ) |  | 20 |  |  | (11 | ) |  | (1,880 | )
Pre-tax income from producing activities |  | 1,851 |  |  | 1,755 |  |  | 6,802 |  |  | 2,207 |  |  | 1,162 |  |  | 603 |  |  | 324 |  |  | 262 |  |  | 14,966 |
Income taxes |  | (872 | ) |  | (1,006 | ) |  | (4,281 | ) |  | (1,702 | ) |  | (396 | ) |  | (178 | ) |  | (117 | ) |  | (149 | ) |  | (8,701 | )
Results of operations from E&P activities of consolidated subsidiaries (b) |  | 979 |  |  | 749 |  |  | 2,521 |  |  | 505 |  |  | 766 |  |  | 425 |  |  | 207 |  |  | 113 |  |  | 6,265 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to third parties |  |  |  |  |  |  |  | 20 |  |  | 26 |  |  |  |  |  | 199 |  |  | 243 |  |  |  |  |  | 488 |
Total revenues |  |  |  |  |  |  |  | 20 |  |  | 26 |  |  |  |  |  | 199 |  |  | 243 |  |  |  |  |  | 488 |
Operations costs |  |  |  |  |  |  |  | (11 | ) |  | (44 | ) |  |  |  |  | (18 | ) |  | (23 | ) |  |  |  |  | (96 | )
Production taxes |  |  |  |  |  |  |  | (4 | ) |  |  |  |  |  |  |  | (14 | ) |  | (113 | ) |  |  |  |  | (131 | )
Exploration expenses |  |  |  |  | (8 | ) |  | (3 | ) |  |  |  |  |  |  |  | (25 | ) |  | (1 | ) |  |  |  |  | (37 | )
D.D. & A. and provision for abandonment |  |  |  |  | (1 | ) |  | (1 | ) |  |  |  |  |  |  |  | (65 | ) |  | (40 | ) |  |  |  |  | (107 | )
Other income (expense) |  |  |  |  | (4 | ) |  | 5 |  |  | (12 | ) |  |  |  |  | (13 | ) |  | (38 | ) |  |  |  |  | (62 | )
Pre-tax income from producing activities |  |  |  |  | (13 | ) |  | 6 |  |  | (30 | ) |  |  |  |  | 64 |  |  | 28 |  |  |  |  |  | 55 |
Income taxes |  |  |  |  |  |  |  | (4 | ) |  | (10 | ) |  |  |  |  | (35 | ) |  | 30 |  |  |  |  |  | (19 | )
Results of operations from E&P activities of equity-accounted entities (b) |  |  |  |  | (13 | ) |  | 2 |  |  | (40 | ) |  |  |  |  | 29 |  |  | 58 |  |  |  |  |  | 36 |
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  | 3,028 |  |  | 2,721 |  |  | 2,010 |  |  | 4,716 |  |  | 346 |  |  | 589 |  |  | 1,691 |  |  | 67 |  |  | 15,168 |
- sales to third parties |  |  |  |  | 596 |  |  | 7,415 |  |  | 1,369 |  |  | 976 |  |  | 774 |  |  | 129 |  |  | 299 |  |  | 11,558 |
Total revenues |  | 3,028 |  |  | 3,317 |  |  | 9,425 |  |  | 6,085 |  |  | 1,322 |  |  | 1,363 |  |  | 1,820 |  |  | 366 |  |  | 26,726 |
Operations costs |  | (423 | ) |  | (687 | ) |  | (694 | ) |  | (935 | ) |  | (208 | ) |  | (223 | ) |  | (357 | ) |  | (124 | ) |  | (3,651 | )
Production taxes |  | (293 | ) |  |  |  |  | (291 | ) |  | (648 | ) |  |  |  |  | (33 | ) |  |  |  |  | (15 | ) |  | (1,280 | )
Exploration expenses |  | (29 | ) |  | (227 | ) |  | (207 | ) |  | (706 | ) |  |  |  |  | (185 | ) |  | (189 | ) |  | (46 | ) |  | (1,589 | )
D.D. & A. and provision for abandonment (a) |  | (818 | ) |  | (1,083 | ) |  | (1,288 | ) |  | (2,010 | ) |  | (91 | ) |  | (850 | ) |  | (1,181 | ) |  | (172 | ) |  | (7,493 | )
Other income (expense) |  | (184 | ) |  | (96 | ) |  | (773 | ) |  | (358 | ) |  | (251 | ) |  | (117 | ) |  | (78 | ) |  | (30 | ) |  | (1,887 | )
Pre-tax income from producing activities |  | 1,281 |  |  | 1,224 |  |  | 6,172 |  |  | 1,428 |  |  | 772 |  |  | (45 | ) |  | 15 |  |  | (21 | ) |  | 10,826 |
Income taxes |  | (351 | ) |  | (803 | ) |  | (3,928 | ) |  | (1,273 | ) |  | (291 | ) |  | (112 | ) |  | (6 | ) |  | (16 | ) |  | (6,780 | )
Results of operations from E&P activities of consolidated subsidiaries (b) |  | 930 |  |  | 421 |  |  | 2,244 |  |  | 155 |  |  | 481 |  |  | (157 | ) |  | 9 |  |  | (37 | ) |  | 4,046 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
- sales to third parties |  |  |  |  |  |  |  | 19 |  |  |  |  |  |  |  |  | 87 |  |  | 232 |  |  |  |  |  | 338 |
Total revenues |  |  |  |  |  |  |  | 19 |  |  |  |  |  |  |  |  | 87 |  |  | 232 |  |  |  |  |  | 338 |
Operations costs |  |  |  |  |  |  |  | (11 | ) |  |  |  |  |  |  |  | (11 | ) |  | (27 | ) |  |  |  |  | (49 | )
Production taxes |  |  |  |  |  |  |  | (3 | ) |  |  |  |  |  |  |  |  |  |  | (94 | ) |  |  |  |  | (97 | )
Exploration expenses |  |  |  |  | (8 | ) |  |  |  |  |  |  |  |  |  |  | (45 | ) |  | (1 | ) |  |  |  |  | (54 | )
D.D. & A. and provision for abandonment |  |  |  |  | (1 | ) |  | (1 | ) |  |  |  |  |  |  |  | (44 | ) |  | (60 | ) |  |  |  |  | (106 | )
Other income (expense) |  |  |  |  | (1 | ) |  | 1 |  |  | (32 | ) |  |  |  |  | (3 | ) |  | (42 | ) |  |  |  |  | (77 | )
Pre-tax income from producing activities |  |  |  |  | (10 | ) |  | 5 |  |  | (32 | ) |  |  |  |  | (16 | ) |  | 8 |  |  |  |  |  | (45 | )
Income taxes |  |  |  |  |  |  |  | (4 | ) |  |  |  |  |  |  |  | (23 | ) |  | (17 | ) |  |  |  |  | (44 | )
Results of operations from E&P activities of equity-accounted entities (b) |  |  |  |  | (10 | ) |  | 1 |  |  | (32 | ) |  |  |  |  | (39 | ) |  | (9 | ) |  |  |  |  | (89 | )

(a) |  | Includes asset impairments amounting to euro 15 million in 2013 and euro 690 million in 2014.
(b) |  | The "Successful Effort Method" application according to accounting Eni policy would have led to an increase of euro 295 million in 2013 and euro 5 million in 2014 for the consolidated subsidiaries; a decrease of euro 6 million in 2013 and an increase of euro 24 million in 2014 for equity-accounted entities.

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Oil and natural gas reserves
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2014, the average price for the marker Brent crude oil was $101 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation22 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 report23. 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 2014, Ryder Scott Company and DeGolyer and MacNaughton23 provided an independent evaluation of about 27% of Eni’s total proved reserves as of December 31, 201424, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three-year period from 2012 to 2014, 94% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2014, the principal properties not subjected to independent evaluation in the last three years are M’Boundi (Congo) and Junin (Venezuela). 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 47%, 51% and 50% of total proved reserves as of December 31, 2012, 2013 and 2014, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 2%, 3% and 3% of total proved reserves on an oil-equivalent basis as of December 31, 2012, 2013 and 2014, 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 1.1%, 1% and 0.6% of total proved reserves as of December 31, 2012, 2013 and 2014, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; and (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.

(22) | i | From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott.
(23) | i | The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2014.

(24) | i | Including reserves of equity-accounted entities.

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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, 2012, 2013 and 2014.

Crude oil (including condensate and natural gas liquids)

(mmBBL) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2011 |  | 259 |  |  | 372 |  |  | 917 |  |  | 670 |  |  | 653 |  |  | 106 |  |  | 132 |  |  | 25 |  |  | 3,134 |
of which: developed |  | 184 |  |  | 195 |  |  | 622 |  |  | 483 |  |  | 215 |  |  | 34 |  |  | 92 |  |  | 25 |  |  | 1,850 |
of which: undeveloped |  | 75 |  |  | 177 |  |  | 295 |  |  | 187 |  |  | 438 |  |  | 72 |  |  | 40 |  |  |  |  |  | 1,284 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  | (9 | ) |  | 10 |  |  | 55 |  |  | 26 |  |  | 62 |  |  | (9 | ) |  | 40 |  |  | 6 |  |  | 181 |
Improved recovery |  |  |  |  | 1 |  |  | 20 |  |  | 7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 28 |
Extensions and discoveries |  |  |  |  | 3 |  |  | 10 |  |  | 65 |  |  |  |  |  |  |  |  | 8 |  |  |  |  |  | 86 |
Production |  | (23 | ) |  | (35 | ) |  | (98 | ) |  | (90 | ) |  | (22 | ) |  | (15 | ) |  | (26 | ) |  | (7 | ) |  | (316 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  | (6 | ) |  | (23 | ) |  |  |  |  |  |  |  |  |  |  | (29 | )
Reserves at December 31, 2012 |  | 227 |  |  | 351 |  |  | 904 |  |  | 672 |  |  | 670 |  |  | 82 |  |  | 154 |  |  | 24 |  |  | 3,084 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2011 |  |  |  |  |  |  |  | 17 |  |  | 22 |  |  |  |  |  | 110 |  |  | 151 |  |  |  |  |  | 300 |
of which: developed |  |  |  |  |  |  |  | 16 |  |  | 4 |  |  |  |  |  |  |  |  | 25 |  |  |  |  |  | 45 |
of which: undeveloped |  |  |  |  |  |  |  | 1 |  |  | 18 |  |  |  |  |  | 110 |  |  | 126 |  |  |  |  |  | 255 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  | 2 |  |  |  |  |  |  |  |  | 1 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  | 3 |  |  |  |  |  |  |  |  | 4 |
Production |  |  |  |  |  |  |  | (1 | ) |  | (1 | ) |  |  |  |  | (1 | ) |  | (4 | ) |  |  |  |  | (7 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  | (4 | ) |  |  |  |  |  |  |  | (28 | ) |  |  |  |  | (32 | )
Reserves at December 31, 2012 |  |  |  |  |  |  |  | 17 |  |  | 16 |  |  |  |  |  | 114 |  |  | 119 |  |  |  |  |  | 266 |
Reserves at December 31, 2012 |  | 227 |  |  | 351 |  |  | 921 |  |  | 688 |  |  | 670 |  |  | 196 |  |  | 273 |  |  | 24 |  |  | 3,350 |
Developed |  | 165 |  |  | 180 |  |  | 601 |  |  | 456 |  |  | 203 |  |  | 49 |  |  | 128 |  |  | 24 |  |  | 1,806 |
Consolidated subsidiaries |  | 165 |  |  | 180 |  |  | 584 |  |  | 456 |  |  | 203 |  |  | 41 |  |  | 109 |  |  | 24 |  |  | 1,762 |
Equity-accounted entities |  |  |  |  |  |  |  | 17 |  |  |  |  |  |  |  |  | 8 |  |  | 19 |  |  |  |  |  | 44 |
Undeveloped |  | 62 |  |  | 171 |  |  | 320 |  |  | 232 |  |  | 467 |  |  | 147 |  |  | 145 |  |  |  |  |  | 1,544 |
Consolidated subsidiaries |  | 62 |  |  | 171 |  |  | 320 |  |  | 216 |  |  | 467 |  |  | 41 |  |  | 45 |  |  |  |  |  | 1,322 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  | 16 |  |  |  |  |  | 106 |  |  | 100 |  |  |  |  |  | 222 |
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2012 |  | 227 |  |  | 351 |  |  | 904 |  |  | 672 |  |  | 670 |  |  | 82 |  |  | 154 |  |  | 24 |  |  | 3,084 |
of which: developed |  | 165 |  |  | 180 |  |  | 584 |  |  | 456 |  |  | 203 |  |  | 41 |  |  | 109 |  |  | 24 |  |  | 1,762 |
of which: undeveloped |  | 62 |  |  | 171 |  |  | 320 |  |  | 216 |  |  | 467 |  |  | 41 |  |  | 45 |  |  |  |  |  | 1,322 |
Purchase of minerals in place |  |  |  |  |  |  |  | 3 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3 |
Revisions of previous estimates |  | 19 |  |  | 16 |  |  | 12 |  |  | 83 |  |  | 31 |  |  | 62 |  |  | 11 |  |  | 2 |  |  | 236 |
Improved recovery |  |  |  |  |  |  |  |  |  |  | 5 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 5 |
Extensions and discoveries |  |  |  |  | 1 |  |  | 2 |  |  | 51 |  |  |  |  |  |  |  |  | 4 |  |  |  |  |  | 58 |
Production |  | (26 | ) |  | (28 | ) |  | (91 | ) |  | (88 | ) |  | (22 | ) |  | (16 | ) |  | (22 | ) |  | (4 | ) |  | (297 | )
Sales of minerals in place |  |  |  |  | (10 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (10 | )
Reserves at December 31, 2013 |  | 220 |  |  | 330 |  |  | 830 |  |  | 723 |  |  | 679 |  |  | 128 |  |  | 147 |  |  | 22 |  |  | 3,079 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2012 |  |  |  |  |  |  |  | 17 |  |  | 16 |  |  |  |  |  | 114 |  |  | 119 |  |  |  |  |  | 266 |
of which: developed |  |  |  |  |  |  |  | 17 |  |  |  |  |  |  |  |  | 8 |  |  | 19 |  |  |  |  |  | 44 |
of which: undeveloped |  |  |  |  |  |  |  |  |  |  | 16 |  |  |  |  |  | 106 |  |  | 100 |  |  |  |  |  | 222 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  |  |  |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production |  |  |  |  |  |  |  | (1 | ) |  |  |  |  |  |  |  | (2 | ) |  | (4 | ) |  |  |  |  | (7 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (111 | ) |  |  |  |  |  |  |  | (111 | )
Reserves at December 31, 2013 |  |  |  |  |  |  |  | 16 |  |  | 15 |  |  |  |  |  | 1 |  |  | 116 |  |  |  |  |  | 148 |
Reserves at December 31, 2013 |  | 220 |  |  | 330 |  |  | 846 |  |  | 738 |  |  | 679 |  |  | 129 |  |  | 263 |  |  | 22 |  |  | 3,227 |
Developed |  | 177 |  |  | 179 |  |  | 577 |  |  | 465 |  |  | 295 |  |  | 38 |  |  | 115 |  |  | 20 |  |  | 1,866 |
Consolidated subsidiaries |  | 177 |  |  | 179 |  |  | 561 |  |  | 465 |  |  | 295 |  |  | 38 |  |  | 96 |  |  | 20 |  |  | 1,831 |
Equity-accounted entities |  |  |  |  |  |  |  | 16 |  |  |  |  |  |  |  |  |  |  |  | 19 |  |  |  |  |  | 35 |
Undeveloped |  | 43 |  |  | 151 |  |  | 269 |  |  | 273 |  |  | 384 |  |  | 91 |  |  | 148 |  |  | 2 |  |  | 1,361 |
Consolidated subsidiaries |  | 43 |  |  | 151 |  |  | 269 |  |  | 258 |  |  | 384 |  |  | 90 |  |  | 51 |  |  | 2 |  |  | 1,248 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  | 15 |  |  |  |  |  | 1 |  |  | 97 |  |  |  |  |  | 113 |

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(mmBBL) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2013 |  | 220 |  |  | 330 |  |  | 830 |  |  | 723 |  |  | 679 |  |  | 128 |  |  | 147 |  |  | 22 |  |  | 3,079 |
of which: developed |  | 177 |  |  | 179 |  |  | 561 |  |  | 465 |  |  | 295 |  |  | 38 |  |  | 96 |  |  | 20 |  |  | 1,831 |
of which: undeveloped |  | 43 |  |  | 151 |  |  | 269 |  |  | 258 |  |  | 384 |  |  | 90 |  |  | 51 |  |  | 2 |  |  | 1,248 |
Purchase of minerals in place |  |  |  |  | 1 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |
Revisions of previous estimates |  | 49 |  |  | 35 |  |  | 32 |  |  | 70 |  |  | 35 |  |  | 16 |  |  | 22 |  |  | (7 | ) |  | 252 |
Improved recovery |  |  |  |  |  |  |  | 3 |  |  | 1 |  |  | 2 |  |  |  |  |  |  |  |  |  |  |  | 6 |
Extensions and discoveries |  | 1 |  |  |  |  |  | 2 |  |  | 36 |  |  |  |  |  |  |  |  | 5 |  |  |  |  |  | 44 |
Production |  | (27 | ) |  | (34 | ) |  | (91 | ) |  | (84 | ) |  | (19 | ) |  | (13 | ) |  | (27 | ) |  | (2 | ) |  | (297 | )
Sales of minerals in place |  |  |  |  | (1 | ) |  |  |  |  | (7 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  | (8 | )
Reserves at December 31, 2014 |  | 243 |  |  | 331 |  |  | 776 |  |  | 739 |  |  | 697 |  |  | 131 |  |  | 147 |  |  | 13 |  |  | 3,077 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2013 |  |  |  |  |  |  |  | 16 |  |  | 15 |  |  |  |  |  | 1 |  |  | 116 |  |  |  |  |  | 148 |
of which: developed |  |  |  |  |  |  |  | 16 |  |  |  |  |  |  |  |  |  |  |  | 19 |  |  |  |  |  | 35 |
of which: undeveloped |  |  |  |  |  |  |  |  |  |  | 15 |  |  |  |  |  | 1 |  |  | 97 |  |  |  |  |  | 113 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  |  |  |  |  |  |  | (1 | ) |  | 3 |  |  |  |  |  |  |  |  | 5 |  |  |  |  |  | 7 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production |  |  |  |  |  |  |  | (1 | ) |  | (1 | ) |  |  |  |  |  |  |  | (4 | ) |  |  |  |  | (6 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2014 |  |  |  |  |  |  |  | 14 |  |  | 17 |  |  |  |  |  | 1 |  |  | 117 |  |  |  |  |  | 149 |
Reserves at December 31, 2014 |  | 243 |  |  | 331 |  |  | 790 |  |  | 756 |  |  | 697 |  |  | 132 |  |  | 264 |  |  | 13 |  |  | 3,226 |
Developed |  | 184 |  |  | 174 |  |  | 534 |  |  | 477 |  |  | 306 |  |  | 64 |  |  | 142 |  |  | 12 |  |  | 1,893 |
Consolidated subsidiaries |  | 184 |  |  | 174 |  |  | 521 |  |  | 470 |  |  | 306 |  |  | 64 |  |  | 116 |  |  | 12 |  |  | 1,847 |
Equity-accounted entities |  |  |  |  |  |  |  | 13 |  |  | 7 |  |  |  |  |  |  |  |  | 26 |  |  |  |  |  | 46 |
Undeveloped |  | 59 |  |  | 157 |  |  | 256 |  |  | 279 |  |  | 391 |  |  | 68 |  |  | 122 |  |  | 1 |  |  | 1,333 |
Consolidated subsidiaries |  | 59 |  |  | 157 |  |  | 255 |  |  | 269 |  |  | 391 |  |  | 67 |  |  | 31 |  |  | 1 |  |  | 1,230 |
Equity-accounted entities |  |  |  |  |  |  |  | 1 |  |  | 10 |  |  |  |  |  | 1 |  |  | 91 |  |  |  |  |  | 103 |

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Natural gas (a)

(BCF) |  | Italy (b) |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2011 |  | 2,491 |  |  | 1,425 |  |  | 6,190 |  |  | 1,949 |  |  | 1,648 |  |  | 685 |  |  | 590 |  |  | 604 |  |  | 15,582 |
of which: developed |  | 1,977 |  |  | 995 |  |  | 3,070 |  |  | 1,437 |  |  | 1,480 |  |  | 528 |  |  | 385 |  |  | 491 |  |  | 10,363 |
of which: undeveloped |  | 514 |  |  | 430 |  |  | 3,120 |  |  | 512 |  |  | 168 |  |  | 157 |  |  | 205 |  |  | 113 |  |  | 5,219 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  | 154 |  |  | 45 |  |  |  |  |  | 284 |  |  | 141 |  |  | 18 |  |  | (41 | ) |  | 5 |  |  | 606 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  | 24 |  |  | 15 |  |  | 1 |  |  | 113 |  |  | 469 |  |  | 2 |  |  | 4 |  |  |  |  |  | 628 |
Production |  | (254 | ) |  | (168 | ) |  | (633 | ) |  | (196 | ) |  | (81 | ) |  | (143 | ) |  | (104 | ) |  | (37 | ) |  | (1,616 | )
Sales of minerals in place |  | (782 | ) |  |  |  |  |  |  |  | (89 | ) |  | (139 | ) |  |  |  |  |  |  |  |  |  |  | (1,010 | )
Reserves at December 31, 2012 |  | 1,633 |  |  | 1,317 |  |  | 5,558 |  |  | 2,061 |  |  | 2,038 |  |  | 562 |  |  | 449 |  |  | 572 |  |  | 14,190 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2011 |  |  |  |  | 2 |  |  | 20 |  |  | 338 |  |  |  |  |  | 3,033 |  |  | 1,307 |  |  |  |  |  | 4,700 |
of which: developed |  |  |  |  |  |  |  | 17 |  |  | 4 |  |  |  |  |  | 24 |  |  | 8 |  |  |  |  |  | 53 |
of which: undeveloped |  |  |  |  | 2 |  |  | 3 |  |  | 334 |  |  |  |  |  | 3,009 |  |  | 1,299 |  |  |  |  |  | 4,647 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  |  |  |  | (2 | ) |  | (2 | ) |  | 3 |  |  |  |  |  | 1 |  |  | 1,340 |  |  |  |  |  | 1,340 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  |  |  |  | 17 |  |  |  |  |  | 38 |  |  | 739 |  |  |  |  |  | 794 |
Production |  |  |  |  |  |  |  | (2 | ) |  | (2 | ) |  |  |  |  | (29 | ) |  |  |  |  |  |  |  | (33 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  | (3 | ) |  |  |  |  |  |  |  | (31 | ) |  |  |  |  | (34 | )
Reserves at December 31, 2012 |  |  |  |  |  |  |  | 16 |  |  | 353 |  |  |  |  |  | 3,043 |  |  | 3,355 |  |  |  |  |  | 6,767 |
Reserves at December 31, 2012 |  | 1,633 |  |  | 1,317 |  |  | 5,574 |  |  | 2,414 |  |  | 2,038 |  |  | 3,605 |  |  | 3,804 |  |  | 572 |  |  | 20,957 |
Developed |  | 1,325 |  |  | 925 |  |  | 2,736 |  |  | 1,429 |  |  | 1,401 |  |  | 774 |  |  | 340 |  |  | 459 |  |  | 9,389 |
Consolidated subsidiaries |  | 1,325 |  |  | 925 |  |  | 2,720 |  |  | 1,429 |  |  | 1,401 |  |  | 372 |  |  | 334 |  |  | 459 |  |  | 8,965 |
Equity-accounted entities |  |  |  |  |  |  |  | 16 |  |  |  |  |  |  |  |  | 402 |  |  | 6 |  |  |  |  |  | 424 |
Undeveloped |  | 308 |  |  | 392 |  |  | 2,838 |  |  | 985 |  |  | 637 |  |  | 2,831 |  |  | 3,464 |  |  | 113 |  |  | 11,568 |
Consolidated subsidiaries |  | 308 |  |  | 392 |  |  | 2,838 |  |  | 632 |  |  | 637 |  |  | 190 |  |  | 115 |  |  | 113 |  |  | 5,225 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  | 353 |  |  |  |  |  | 2,641 |  |  | 3,349 |  |  |  |  |  | 6,343 |
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2012 |  | 1,633 |  |  | 1,317 |  |  | 5,558 |  |  | 2,061 |  |  | 2,038 |  |  | 562 |  |  | 449 |  |  | 572 |  |  | 14,190 |
of which: developed |  | 1,325 |  |  | 925 |  |  | 2,720 |  |  | 1,429 |  |  | 1,401 |  |  | 372 |  |  | 334 |  |  | 459 |  |  | 8,965 |
of which: undeveloped |  | 308 |  |  | 392 |  |  | 2,838 |  |  | 632 |  |  | 637 |  |  | 190 |  |  | 115 |  |  | 113 |  |  | 5,225 |
Purchase of minerals in place |  |  |  |  |  |  |  | 5 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 5 |
Revisions of previous estimates |  | 105 |  |  | 103 |  |  | 253 |  |  | 475 |  |  | (3 | ) |  | 104 |  |  | 142 |  |  | 316 |  |  | 1,495 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  | 24 |  |  | 1 |  |  | 24 |  |  | 14 |  |  |  |  |  | 208 |  |  | 7 |  |  |  |  |  | 278 |
Production |  | (230 | ) |  | (157 | ) |  | (609 | ) |  | (176 | ) |  | (78 | ) |  | (130 | ) |  | (89 | ) |  | (40 | ) |  | (1,509 | )
Sales of minerals in place |  |  |  |  | (17 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (17 | )
Reserves at December 31, 2013 |  | 1,532 |  |  | 1,247 |  |  | 5,231 |  |  | 2,374 |  |  | 1,957 |  |  | 744 |  |  | 509 |  |  | 848 |  |  | 14,442 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2012 |  |  |  |  |  |  |  | 16 |  |  | 353 |  |  |  |  |  | 3,043 |  |  | 3,355 |  |  |  |  |  | 6,767 |
of which: developed |  |  |  |  |  |  |  | 16 |  |  |  |  |  |  |  |  | 402 |  |  | 6 |  |  |  |  |  | 424 |
of which: undeveloped |  |  |  |  |  |  |  |  |  |  | 353 |  |  |  |  |  | 2,641 |  |  | 3,349 |  |  |  |  |  | 6,343 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  |  |  |  |  |  |  | 1 |  |  | (18 | ) |  |  |  |  | 16 |  |  | (2 | ) |  |  |  |  | (3 | )
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production |  |  |  |  |  |  |  | (2 | ) |  | (5 | ) |  |  |  |  | (60 | ) |  |  |  |  |  |  |  | (67 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2,971 | ) |  |  |  |  |  |  |  | (2,971 | )
Reserves at December 31, 2013 |  |  |  |  |  |  |  | 15 |  |  | 330 |  |  |  |  |  | 28 |  |  | 3,353 |  |  |  |  |  | 3,726 |
Reserves at December 31, 2013 |  | 1,532 |  |  | 1,247 |  |  | 5,246 |  |  | 2,704 |  |  | 1,957 |  |  | 772 |  |  | 3,862 |  |  | 848 |  |  | 18,168 |
Developed |  | 1,266 |  |  | 904 |  |  | 2,447 |  |  | 1,295 |  |  | 1,488 |  |  | 300 |  |  | 315 |  |  | 561 |  |  | 8,576 |
Consolidated subsidiaries |  | 1,266 |  |  | 904 |  |  | 2,432 |  |  | 1,295 |  |  | 1,488 |  |  | 286 |  |  | 310 |  |  | 561 |  |  | 8,542 |
Equity-accounted entities |  |  |  |  |  |  |  | 15 |  |  |  |  |  |  |  |  | 14 |  |  | 5 |  |  |  |  |  | 34 |
Undeveloped |  | 266 |  |  | 343 |  |  | 2,799 |  |  | 1,409 |  |  | 469 |  |  | 472 |  |  | 3,547 |  |  | 287 |  |  | 9,592 |
Consolidated subsidiaries |  | 266 |  |  | 343 |  |  | 2,799 |  |  | 1,079 |  |  | 469 |  |  | 458 |  |  | 199 |  |  | 287 |  |  | 5,900 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  | 330 |  |  |  |  |  | 14 |  |  | 3,348 |  |  |  |  |  | 3,692 |

(a) |  | Values lower than 1 BCF are not disclosed in this table.
(b) |  | Including approximately 767 BCF of natural gas at December 31, 2011.

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##### Table of Contents

Natural gas (a) continued

(BCF) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2013 |  | 1,532 |  |  | 1,247 |  |  | 5,231 |  |  | 2,374 |  |  | 1,957 |  |  | 744 |  |  | 509 |  |  | 848 |  |  | 14,442 |
of which: developed |  | 1,266 |  |  | 904 |  |  | 2,432 |  |  | 1,295 |  |  | 1,488 |  |  | 286 |  |  | 310 |  |  | 561 |  |  | 8,542 |
of which: undeveloped |  | 266 |  |  | 343 |  |  | 2,799 |  |  | 1,079 |  |  | 469 |  |  | 458 |  |  | 199 |  |  | 287 |  |  | 5,900 |
Purchase of minerals in place |  |  |  |  | 21 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 21 |
Revisions of previous estimates |  | 113 |  |  | 99 |  |  | 668 |  |  | 214 |  |  | 165 |  |  | 156 |  |  | 23 |  |  | (1 | ) |  | 1,437 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  | 19 |  |  | 341 |  |  |  |  |  | 59 |  |  | 16 |  |  |  |  |  | 435 |
Production |  | (213 | ) |  | (195 | ) |  | (627 | ) |  | (185 | ) |  | (73 | ) |  | (113 | ) |  | (80 | ) |  | (40 | ) |  | (1,526 | )
Sales of minerals in place |  |  |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1 | )
Reserves at December 31, 2014 |  | 1,432 |  |  | 1,171 |  |  | 5,291 |  |  | 2,744 |  |  | 2,049 |  |  | 846 |  |  | 468 |  |  | 807 |  |  | 14,808 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2013 |  |  |  |  |  |  |  | 15 |  |  | 330 |  |  |  |  |  | 28 |  |  | 3,353 |  |  |  |  |  | 3,726 |
of which: developed |  |  |  |  |  |  |  | 15 |  |  |  |  |  |  |  |  | 14 |  |  | 5 |  |  |  |  |  | 34 |
of which: undeveloped |  |  |  |  |  |  |  |  |  |  | 330 |  |  |  |  |  | 14 |  |  | 3,348 |  |  |  |  |  | 3,692 |
Purchase of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revisions of previous estimates |  |  |  |  |  |  |  | 2 |  |  | 25 |  |  |  |  |  | (2 | ) |  |  |  |  |  |  |  | 25 |
Improved recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Extensions and discoveries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production |  |  |  |  |  |  |  | (2 | ) |  | (4 | ) |  |  |  |  | (8 | ) |  |  |  |  |  |  |  | (14 | )
Sales of minerals in place |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Reserves at December 31, 2014 |  |  |  |  |  |  |  | 15 |  |  | 351 |  |  |  |  |  | 18 |  |  | 3,353 |  |  |  |  |  | 3,737 |
Reserves at December 31, 2014 |  | 1,432 |  |  | 1,171 |  |  | 5,306 |  |  | 3,095 |  |  | 2,049 |  |  | 864 |  |  | 3,821 |  |  | 807 |  |  | 18,545 |
Developed |  | 1,192 |  |  | 887 |  |  | 2,125 |  |  | 1,360 |  |  | 1,553 |  |  | 271 |  |  | 399 |  |  | 675 |  |  | 8,462 |
Consolidated subsidiaries |  | 1,192 |  |  | 887 |  |  | 2,110 |  |  | 1,271 |  |  | 1,553 |  |  | 261 |  |  | 393 |  |  | 675 |  |  | 8,342 |
Equity-accounted entities |  |  |  |  |  |  |  | 15 |  |  | 89 |  |  |  |  |  | 10 |  |  | 6 |  |  |  |  |  | 120 |
Undeveloped |  | 240 |  |  | 284 |  |  | 3,181 |  |  | 1,735 |  |  | 496 |  |  | 593 |  |  | 3,422 |  |  | 132 |  |  | 10,083 |
Consolidated subsidiaries |  | 240 |  |  | 284 |  |  | 3,181 |  |  | 1,473 |  |  | 496 |  |  | 585 |  |  | 75 |  |  | 132 |  |  | 6,466 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  | 262 |  |  |  |  |  | 8 |  |  | 3,347 |  |  |  |  |  | 3,617 |

(a) |  | Values lower than 1 BCF are not disclosed in this table.

Standardized measure of discounted future net cash flows
Estimated future cash inflows represent the revenues that would be received from production and are determined by applying the year-end average prices during the years ended.

Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered.

The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor.

Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates.

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

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

(euro million) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

December 31, 2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Future cash inflows |  | 30,308 |  |  | 38,912 |  |  | 108,343 |  |  | 56,978 |  |  | 53,504 |  |  | 7,881 |  |  | 11,008 |  |  | 4,957 |  |  | 311,891 |
Future production costs |  | (5,900 | ) |  | (8,190 | ) |  | (18,555 | ) |  | (14,844 | ) |  | (9,561 | ) |  | (2,854 | ) |  | (2,520 | ) |  | (921 | ) |  | (63,345 | )
Future development and abandonment costs |  | (3,652 | ) |  | (7,511 | ) |  | (8,412 | ) |  | (6,873 | ) |  | (3,802 | ) |  | (1,974 | ) |  | (1,502 | ) |  | (197 | ) |  | (33,923 | )
Future net inflow before income tax |  | 20,756 |  |  | 23,211 |  |  | 81,376 |  |  | 35,261 |  |  | 40,141 |  |  | 3,053 |  |  | 6,986 |  |  | 3,839 |  |  | 214,623 |
Future income tax |  | (6,911 | ) |  | (15,063 | ) |  | (44,256 | ) |  | (21,348 | ) |  | (10,293 | ) |  | (903 | ) |  | (2,906 | ) |  | (1,181 | ) |  | (102,861 | )
Future net cash flows |  | 13,845 |  |  | 8,148 |  |  | 37,120 |  |  | 13,913 |  |  | 29,848 |  |  | 2,150 |  |  | 4,080 |  |  | 2,658 |  |  | 111,762 |
10 % discount factor |  | (5,519 | ) |  | (2,630 | ) |  | (16,539 | ) |  | (4,976 | ) |  | (17,943 | ) |  | (496 | ) |  | (1,337 | ) |  | (1,030 | ) |  | (50,470 | )
Standardized measure of discounted future net cash flows |  | 8,326 |  |  | 5,518 |  |  | 20,581 |  |  | 8,937 |  |  | 11,905 |  |  | 1,654 |  |  | 2,743 |  |  | 1,628 |  |  | 61,292 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Future cash inflows |  |  |  |  | 1 |  |  | 658 |  |  | 3,594 |  |  |  |  |  | 6,689 |  |  | 18,132 |  |  |  |  |  | 29,074 |
Future production costs |  |  |  |  |  |  |  | (203 | ) |  | (576 | ) |  |  |  |  | (2,216 | ) |  | (5,003 | ) |  |  |  |  | (7,998 | )
Future development and abandonment costs |  |  |  |  | (1 | ) |  | (17 | ) |  | (101 | ) |  |  |  |  | (1,061 | ) |  | (2,563 | ) |  |  |  |  | (3,743 | )
Future net inflow before income tax |  |  |  |  |  |  |  | 438 |  |  | 2,917 |  |  |  |  |  | 3,412 |  |  | 10,566 |  |  |  |  |  | 17,333 |
Future income tax |  |  |  |  |  |  |  | (36 | ) |  | (1,291 | ) |  |  |  |  | (795 | ) |  | (5,729 | ) |  |  |  |  | (7,851 | )
Future net cash flows |  |  |  |  |  |  |  | 402 |  |  | 1,626 |  |  |  |  |  | 2,617 |  |  | 4,837 |  |  |  |  |  | 9,482 |
10 % discount factor |  |  |  |  |  |  |  | (206 | ) |  | (962 | ) |  |  |  |  | (1,747 | ) |  | (3,621 | ) |  |  |  |  | (6,536 | )
Standardized measure of discounted future net cash flows |  |  |  |  |  |  |  | 196 |  |  | 664 |  |  |  |  |  | 870 |  |  | 1,216 |  |  |  |  |  | 2,946 |
Total consolidated subsidiaries and equity-accounted entities |  | 8,326 |  |  | 5,518 |  |  | 20,777 |  |  | 9,601 |  |  | 11,905 |  |  | 2,524 |  |  | 3,959 |  |  | 1,628 |  |  | 64,238 |
December 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Future cash inflows |  | 28,829 |  |  | 33,319 |  |  | 92,661 |  |  | 58,252 |  |  | 50,754 |  |  | 12,487 |  |  | 10,227 |  |  | 5,294 |  |  | 291,823 |
Future production costs |  | (6,250 | ) |  | (6,836 | ) |  | (16,611 | ) |  | (15,986 | ) |  | (9,072 | ) |  | (3,876 | ) |  | (2,379 | ) |  | (1,417 | ) |  | (62,427 | )
Future development and abandonment costs |  | (4,593 | ) |  | (6,202 | ) |  | (8,083 | ) |  | (7,061 | ) |  | (3,445 | ) |  | (3,960 | ) |  | (1,561 | ) |  | (279 | ) |  | (35,184 | )
Future net inflow before income tax |  | 17,986 |  |  | 20,281 |  |  | 67,967 |  |  | 35,205 |  |  | 38,237 |  |  | 4,651 |  |  | 6,287 |  |  | 3,598 |  |  | 194,212 |
Future income tax |  | (5,776 | ) |  | (12,746 | ) |  | (35,887 | ) |  | (20,491 | ) |  | (9,939 | ) |  | (1,391 | ) |  | (2,387 | ) |  | (1,093 | ) |  | (89,710 | )
Future net cash flows |  | 12,210 |  |  | 7,535 |  |  | 32,080 |  |  | 14,714 |  |  | 28,298 |  |  | 3,260 |  |  | 3,900 |  |  | 2,505 |  |  | 104,502 |
10 % discount factor |  | (5,048 | ) |  | (2,110 | ) |  | (14,327 | ) |  | (5,619 | ) |  | (16,984 | ) |  | (1,683 | ) |  | (1,353 | ) |  | (1,201 | ) |  | (48,325 | )
Standardized measure of discounted future net cash flows |  | 7,162 |  |  | 5,425 |  |  | 17,753 |  |  | 9,095 |  |  | 11,314 |  |  | 1,577 |  |  | 2,547 |  |  | 1,304 |  |  | 56,177 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Future cash inflows |  |  |  |  |  |  |  | 524 |  |  | 4,041 |  |  |  |  |  | 262 |  |  | 17,239 |  |  |  |  |  | 22,066 |
Future production costs |  |  |  |  |  |  |  | (164 | ) |  | (1,465 | ) |  |  |  |  | (38 | ) |  | (5,467 | ) |  |  |  |  | (7,134 | )
Future development and abandonment costs |  |  |  |  |  |  |  | (17 | ) |  | (85 | ) |  |  |  |  | (73 | ) |  | (2,299 | ) |  |  |  |  | (2,474 | )
Future net inflow before income tax |  |  |  |  |  |  |  | 343 |  |  | 2,491 |  |  |  |  |  | 151 |  |  | 9,473 |  |  |  |  |  | 12,458 |
Future income tax |  |  |  |  |  |  |  | (20 | ) |  | (1,617 | ) |  |  |  |  | (61 | ) |  | (4,156 | ) |  |  |  |  | (5,854 | )
Future net cash flows |  |  |  |  |  |  |  | 323 |  |  | 874 |  |  |  |  |  | 90 |  |  | 5,317 |  |  |  |  |  | 6,604 |
10 % discount factor |  |  |  |  |  |  |  | (175 | ) |  | (401 | ) |  |  |  |  | (20 | ) |  | (3,681 | ) |  |  |  |  | (4,277 | )
Standardized measure of discounted future net cash flows |  |  |  |  |  |  |  | 148 |  |  | 473 |  |  |  |  |  | 70 |  |  | 1,636 |  |  |  |  |  | 2,327 |
Total consolidated subsidiaries and equity-accounted entities |  | 7,162 |  |  | 5,425 |  |  | 17,901 |  |  | 9,568 |  |  | 11,314 |  |  | 1,647 |  |  | 4,183 |  |  | 1,304 |  |  | 58,504 |

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(euro million) |  | Italy |  | Rest of Europe |  | North Africa |  | Sub-Saharan Africa |  | Kazakhstan |  | Rest of Asia |  | Americas |  | Australia and Oceania |  | Total

December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Future cash inflows |  | 24,951 |  |  | 29,140 |  |  | 96,372 |  |  | 65,853 |  |  | 55,740 |  |  | 13,664 |  |  | 10,955 |  |  | 4,849 |  |  | 301,524 |
Future production costs |  | (6,374 | ) |  | (6,856 | ) |  | (19,906 | ) |  | (18,236 | ) |  | (9,878 | ) |  | (4,158 | ) |  | (2,680 | ) |  | (1,092 | ) |  | (69,180 | )
Future development and abandonment costs |  | (4,698 | ) |  | (5,292 | ) |  | (9,673 | ) |  | (9,139 | ) |  | (4,576 | ) |  | (4,600 | ) |  | (1,892 | ) |  | (356 | ) |  | (40,226 | )
Future net inflow before income tax |  | 13,879 |  |  | 16,992 |  |  | 66,793 |  |  | 38,478 |  |  | 41,286 |  |  | 4,906 |  |  | 6,383 |  |  | 3,401 |  |  | 192,118 |
Future income tax |  | (3,583 | ) |  | (10,595 | ) |  | (35,484 | ) |  | (20,514 | ) |  | (10,400 | ) |  | (1,462 | ) |  | (2,401 | ) |  | (989 | ) |  | (85,428 | )
Future net cash flows |  | 10,296 |  |  | 6,397 |  |  | 31,309 |  |  | 17,964 |  |  | 30,886 |  |  | 3,444 |  |  | 3,982 |  |  | 2,412 |  |  | 106,690 |
10 % discount factor |  | (4,064 | ) |  | (1,464 | ) |  | (13,905 | ) |  | (7,164 | ) |  | (19,699 | ) |  | (1,900 | ) |  | (1,353 | ) |  | (1,106 | ) |  | (50,655 | )
Standardized measure of discounted future net cash flows |  | 6,232 |  |  | 4,933 |  |  | 17,404 |  |  | 10,800 |  |  | 11,187 |  |  | 1,544 |  |  | 2,629 |  |  | 1,306 |  |  | 56,035 |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Future cash inflows |  |  |  |  |  |  |  | 485 |  |  | 3,861 |  |  |  |  |  | 200 |  |  | 18,871 |  |  |  |  |  | 23,417 |
Future production costs |  |  |  |  |  |  |  | (165 | ) |  | (692 | ) |  |  |  |  | (33 | ) |  | (5,724 | ) |  |  |  |  | (6,614 | )
Future development and abandonment costs |  |  |  |  |  |  |  | (18 | ) |  | (104 | ) |  |  |  |  | (51 | ) |  | (2,032 | ) |  |  |  |  | (2,205 | )
Future net inflow before income tax |  |  |  |  |  |  |  | 302 |  |  | 3,065 |  |  |  |  |  | 116 |  |  | 11,115 |  |  |  |  |  | 14,598 |
Future income tax |  |  |  |  |  |  |  | (23 | ) |  | (426 | ) |  |  |  |  | (45 | ) |  | (4,608 | ) |  |  |  |  | (5,102 | )
Future net cash flows |  |  |  |  |  |  |  | 279 |  |  | 2,639 |  |  |  |  |  | 71 |  |  | 6,507 |  |  |  |  |  | 9,496 |
10 % discount factor |  |  |  |  |  |  |  | (158 | ) |  | (1,442 | ) |  |  |  |  | (11 | ) |  | (4,327 | ) |  |  |  |  | (5,938 | )
Standardized measure of discounted future net cash flows |  |  |  |  |  |  |  | 121 |  |  | 1,197 |  |  |  |  |  | 60 |  |  | 2,180 |  |  |  |  |  | 3,558 |
Total consolidated subsidiaries and equity-accounted entities |  | 6,232 |  |  | 4,933 |  |  | 17,525 |  |  | 11,997 |  |  | 11,187 |  |  | 1,604 |  |  | 4,809 |  |  | 1,306 |  |  | 59,593 |

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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, 2012, 2013 and 2014, are as follows:

(euro million) |  | Consolidated subsidiaries |  | Equity-accounted entities |  | Total

Standardized measure of discounted future net cash flows at December 31, 2011 |  | 62,238 |  |  | 2,660 |  |  | 64,898 |
Increase (Decrease): |  |  |  |  |  |  |  |  |
- sales, net of production costs |  | (28,595 | ) |  | (325 | ) |  | (28,920 | )
- net changes in sales and transfer prices, net of production costs |  | 2,264 |  |  | (56 | ) |  | 2,208 |
- extensions, discoveries and improved recovery, net of future production and development costs |  | 4,868 |  |  | 812 |  |  | 5,680 |
- changes in estimated future development and abandonment costs |  | (3,802 | ) |  | (357 | ) |  | (4,159 | )
- development costs incurred during the period that reduced future development costs |  | 8,199 |  |  | 409 |  |  | 8,608 |
- revisions of quantity estimates |  | 3,725 |  |  | 824 |  |  | 4,549 |
- accretion of discount |  | 12,527 |  |  | 477 |  |  | 13,004 |
- net change in income taxes |  | 2,207 |  |  | (830 | ) |  | 1,377 |
- purchase of reserves-in-place |  |  |  |  |  |  |  |  |
- sale of reserves-in-place |  | (1,509 | ) |  | (615 | ) |  | (2,124 | )
- changes in production rates (timing) and other |  | (830 | ) |  | (53 | ) |  | (883 | )
Net increase (decrease) |  | (946 | ) |  | 286 |  |  | (660 | )
Standardized measure of discounted future net cash flows at December 31, 2012 |  | 61,292 |  |  | 2,946 |  |  | 64,238 |
Increase (Decrease): |  |  |  |  |  |  |  |  |
- sales, net of production costs |  | (24,576 | ) |  | (261 | ) |  | (24,837 | )
- net changes in sales and transfer prices, net of production costs |  | (3,632 | ) |  | (223 | ) |  | (3,855 | )
- extensions, discoveries and improved recovery, net of future production and development costs |  | 1,699 |  |  | 3 |  |  | 1,702 |
- changes in estimated future development and abandonment costs |  | (6,821 | ) |  | (427 | ) |  | (7,248 | )
- development costs incurred during the period that reduced future development costs |  | 8,456 |  |  | 665 |  |  | 9,121 |
- revisions of quantity estimates |  | 6,385 |  |  | (298 | ) |  | 6,087 |
- accretion of discount |  | 11,937 |  |  | 521 |  |  | 12,458 |
- net change in income taxes |  | 5,587 |  |  | 379 |  |  | 5,966 |
- purchase of reserves-in-place |  | 74 |  |  |  |  |  | 74 |
- sale of reserves-in-place |  | (252 | ) |  | (770 | ) |  | (1,022 | )
- changes in production rates (timing) and other |  | (3,972 | ) |  | (208 | ) |  | (4,180 | )
Net increase (decrease) |  | (5,115 | ) |  | (619 | ) |  | (5,734 | )
Standardized measure of discounted future net cash flows at December 31, 2013 |  | 56,177 |  |  | 2,327 |  |  | 58,504 |
Increase (Decrease): |  |  |  |  |  |  |  |  |
- sales, net of production costs |  | (21,795 | ) |  | (192 | ) |  | (21,987 | )
- net changes in sales and transfer prices, net of production costs |  | (12,053 | ) |  | (500 | ) |  | (12,553 | )
- extensions, discoveries and improved recovery, net of future production and development costs |  | 1,667 |  |  |  |  |  | 1,667 |
- changes in estimated future development and abandonment costs |  | (6,047 | ) |  | 223 |  |  | (5,824 | )
- development costs incurred during the period that reduced future development costs |  | 8,745 |  |  | 451 |  |  | 9,196 |
- revisions of quantity estimates |  | 8,085 |  |  | (325 | ) |  | 7,760 |
- accretion of discount |  | 11,064 |  |  | 512 |  |  | 11,576 |
- net change in income taxes |  | 7,049 |  |  | 704 |  |  | 7,753 |
- purchase of reserves-in-place |  | 67 |  |  |  |  |  | 67 |
- sale of reserves-in-place |  | (271 | ) |  |  |  |  | (271 | )
- changes in production rates (timing) and other |  | 3,347 |  |  | 358 |  |  | 3,705 |
Net increase (decrease) |  | (142 | ) |  | 1,231 |  |  | 1,089 |
Standardized measure of discounted future net cash flows at December 31, 2014 |  | 56,035 |  |  | 3,558 |  |  | 59,593 |

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SIGNATURES

The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: April 2, 2015

Eni SpA
/s/ANTONIO CRISTODORO
Antonio Cristodoro
Title: Head of Corporate Secretary's Staff Office

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EXHIBIT 1

By-laws of Eni SpA1

> Part I – Formation – Name – Registered Office and Duration of the Company

ARTICLE 1
1.1 |  | 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.
1.2 |  | The first letter of the Company’s name may be written in either upper or lower case.
ARTICLE 2
2.1 |  | The Company’s registered office is located in Rome, and it has two branch offices in San Donato Milanese (Milan).
2.2 |  | 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 fundraising on a public basis and the performance 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.

> 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.
5.2 |  | Shares may not be split and each share gives entitlement to one vote.
5.3 |  | The status of shareholder in itself constitutes approval of these By-laws.
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.

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|  | 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 |  | The Shareholders’ Meeting may resolve to increase the Company share capital and set the terms, conditions and means thereof.
9.2 |  | 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 |  | Payments in respect of shares may be called by the Board of Directors in one or more installments.
10.2 |  | 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 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.

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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 the Company or 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.
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 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.

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ARTICLE 15
15.1 |  | The Shareholders’ Meeting is chaired by the Chairman of the Board of Directors, or in the event of the Chairman’s absence or impediment, by the Chief Executive Officer; in their absence, the 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 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

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|  | 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) |  | 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;
|  | b) |  | 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;

|  | c) |  | 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 these candidates; the candidates who do not meet 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;

|  | c-bis) |  | 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
|  | d) |  | 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 slate voting procedure shall apply only to the election of the entire Board of Directors.
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.

17.5 |  | 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.
18.2 |  | The Board, acting upon a proposal of the Chairman, shall appoint a Secretary, who need not be affiliated with the Company.

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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 |  | TThe 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 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.

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|  | 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. 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

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|  | 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.

28.3 |  | Statutory Auditors may be re-elected.
28.4 |  | 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.

> 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.
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.

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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 45 – Other information about investments – Information on Eni’s investments as of December 31, 2014 – of the Notes on Consolidated Financial Statements".

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EXHIBIT 11

Code of Ethics

Approved by the Board of Directors of Eni SpA on April 10, 2014
The English text is a translation of the Italian official "Code of Ethics"
For any conflict or discrepancies between the two texts the Italian text shall prevail

TABLE OF CONTENTS

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. Code Promotion Team
3. Code review
4. Contractual value of the Code

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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 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 acknowledgement and safeguarding of the dignity, freedom and equality of human beings, to 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 the United Nations Universal Declaration of Human Rights, the Fundamental Conventions of the ILO – International Labor Organization – and the OECD Guidelines on Multinational Enterprises.
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. Subject to compliance with applicable laws and obligations arising under 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.
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

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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
eni undertakes to provide outside 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.
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.

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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 socio-economic 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-profit" activities which demonstrate the Company’s commitment to help meet the needs of those 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; and
• |  | 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;

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• |  | 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; and

• |  | 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. ENI’S MANAGEMENT, EMPLOYEES, COLLABORATORS

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; and
• |  | 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. 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 non-intentional 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.

(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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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; and
• |  | 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; and
• |  | 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; and
• |  | 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. SYSTEM OF INTERNAL CONTROL

eni is committed to promoting and maintaining an adequate internal control and risk management system, by adopting and implementing all the 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 financial data, and ensuring a proper process of identification, measurement, management and monitoring of key 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 auditors and transactions with related parties.

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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; and

• |  | 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; and
• |  | 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; and
• |  | 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.

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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. 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; and

• |  | 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; and
• |  | 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.

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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 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 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; and
• |  | 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; and
• |  | 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; and
• |  | 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 "Technical Secretariat of the Watch Structure 231 of eni spa", which reports to it. The Technical Secretariat is supported by the competent structures of eni spa and also activates and maintains an adequate flow of reporting and communication with the Guarantors of the subsidiaries.

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Each information flow to the Guarantor may be sent to the following email address:
organismo_di_vigilanza@eni.com.
2.2. Code Promotion Team
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.
In order to promote awareness and facilitate the implementation of the Code, the Promotion Team of the Code reports to the Guarantor of eni spa. The Team promotes in eni the provision of every possible instrument for understanding and clarifying the interpretation and implementation of the Code.
The members of the Team are chosen by the Chief Executive Officer of eni spa upon proposal of the Guarantor of eni spa.

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.

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Certifications as separate documents filed as exhibits

EXHIBIT 12.1

Certification

I, Claudio Descalzi, certify that:

| 1. |  | I have reviewed this Annual Report on Form 20-F of Eni SpA;

| 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: April 2, 2015

/s/ CLAUDIO DESCALZI
Claudio Descalzi Title: Chief Executive Officer

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EXHIBIT 12.2

Certification

I, Massimo Mondazzi, certify that:

| 1. |  | I have reviewed this Annual Report on Form 20-F of Eni SpA;

| 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: April 2, 2015

/s/MASSIMO MONDAZZI
Massimo Mondazzi Title: Chief Financial and Risk Management Officer

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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, 2014 (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: April 2, 2015

/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.

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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, 2014 (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: April 2, 2015

/s/MASSIMO MONDAZZI
Massimo Mondazzi Title: Chief Financial and Risk Management 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.

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EXHIBIT 15.a(i)

D E G OLYER A ND M AC N AUGHTON
5001 S PRING V ALLEY R OAD
S UITE 800 E AST
D ALLAS, T EXAS 75244

> > > February 28, 2015

> > > Eni S.p.A.
> > > E&P Division
> > > Ms. Manuela Feudaroli
> > > Vice President, Reserves
> > > Via Emilia 1
> > > 20097 San Donato Milanese
> > > Milano, Italy

> > > Dear Ms. Feudaroli:

> > > Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved crude oil, condensate, liquefied petroleum gas (LPG), and natural gas reserves, as of December 31, 2014, of certain properties in Africa, Asia, Australia and Oceania, and Europe in which Eni S.p.A. (Eni) has represented that it owns an interest. This evaluation was completed on February 28, 2015. Eni has represented that these properties account for 23.7 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2014, 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. 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, 2014, 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 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, 2014. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Eni after deducting interests owned by others.

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D E G OLYER A ND M AC N AUGHTON | 2

> > > Estimates of oil, condensate, LPG, and natural 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

> > > Our 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.

> > > 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 ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of

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D E G OLYER A ND M AC N AUGHTON | 3

> > > 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 where more complete data were available.

> > > Eni has represented that its estimates of condensate and LPG are reported only in combination, 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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D E G OLYER A ND M AC N AUGHTON | 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 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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D E G OLYER A ND M AC N AUGHTON | 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

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D E G OLYER A ND M AC N AUGHTON | 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 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 related to our estimates of reserves:

> > > Oil, Condensate, and LPG Prices

> > > > > Eni provided all pricing information, and it has represented that the provided oil, LPG, and condensate 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 101.00 United States dollars (U.S.$) per barrel (U.S.$/bbl) was the resulting reference price (rounded to nearest dollar). Where appropriate, Eni supplied differentials by field to the relevant reference price, and the prices were held constant thereafter. The volume-weighted average prices in this report were as follows:

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D E G OLYER A ND M AC N AUGHTON | 7

|  | Oil (U.S.$/bbl) |  | Condensate and LPG (U.S.$/bbl)

Africa | 101.88 | 81.04
Asia | NA | 93.14
Australia and Oceania | 98.44 | 94.48
Europe | 98.45 | 58.06
Average for Total | 98.95 | 86.04
NA = Not Applicable |  |

> > > Natural Gas Prices

> > > > > Eni has represented that the provided natural 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.$8.35 per thousand cubic feet. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices in this report were as follows, expressed in United States dollars per thousand cubic feet (U.S.$/Mcf):

> > > > > > |  | Gas (U.S.$/Mcf)

> > > > > > Africa | NA
> > > > > > Asia | 0.49
> > > > > > Australia and Oceania | 6.22
> > > > > > Europe | 9.12
> > > > > > Average for Total | 5.38

> > > > > > NA = Not Applicable

> > > 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

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D E G OLYER A ND M AC N AUGHTON | 8

> > > > > because of anticipated changes in operating conditions. These costs were not escalated for inflation.

> > > 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, 2014, estimated herein.

> > > Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Africa, Asia, Australia and Oceania, and Europe are based on the definitions of proved reserves of the SEC. Eni represents that its estimates of the net proved reserves attributable to these properties, which represent 23.7 percent of Eni’s reserves on a net equivalent basis, are 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, 2014

> |  | Oil, Condensate, and LPG (MMbbl) |  | Natural Gas (Bcf) |  | Oil Equivalent (MMboe)
> Properties reviewed by DeGolyer and MacNaughton |  |  |  |  |  |
> Total Proved |  | 904 |  | 3,636 |  | 1,566

Note: | Gas is converted to oil equivalent using a factor of 5,492 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 natural 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.

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D E G OLYER A ND M AC N AUGHTON | 9

> > > 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 5.0 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, do not differ materially from those prepared by us.

> > > 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/ LLOYD W. CADE, P.E.
| Lloyd W. Cade, P.E.
[SEAL] | Senior Vice President
| DeGolyer and MacNaughton

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D E G OLYER A ND M AC N AUGHTON |

CERTIFICATE of QUALIFICATION

> > > I, Lloyd W. Cade 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 the letter report addressed to Eni dated February 28, 2015, and that I, as Senior Vice President, was responsible for the preparation of this report.
> > > 2. |  | That I attended the Kansas State University, and that I graduated with a Bachelor of Science degree in Mechanical Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and reserves evaluations.

> > > SIGNED: February 28, 2015

| /s/ LLOYD W. CADE, P.E.
| Lloyd W. Cade, P.E.
[SEAL] | Senior Vice President
| DeGolyer and MacNaughton

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EXHIBIT 15.a(ii)

Eni S.p.A.

Estimated

Future Reserves and Income

Attributable to Certain

Interests

SEC Parameters

As of

December 31, 2014

\s\ HERMAN G. ACUÑA |  | \s\ GABRIELLE GUERRE
Herman G. Acuña, P.E. |  | Gabrielle Guerre, P.E.
TBPE License No. 92254 |  | TBPE License No. 109935
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

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February 17, 2015

Eni S.p.A
E&P Division
Ms. Manuela Feudaroli
Vice President Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

Dear Ms. Feudaroli:

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, 2014 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 6, 2015 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 3.5 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations:

> > > > > > • Africa
> > > > > > • Asia
> > > > > > • Americas

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, 2014 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.

SUITE 600, 1015 4TH STREET, S.W. |  | CALGARY, ALBERTA T2R 1J4 |  | TEL (403) 262-2799 |  | FAX (403) 262-2790
621 17TH STREET, SUITE 1550 |  | DENVER, COLORADO 80293-1501 |  | TEL (303) 623-9147 |  | FAX (303) 623-4258

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Eni S.p.A. – Third Party
February 17, 2015
Page 2

The conclusions discussed in this report, as of December 31, 2014, are related to hydrocarbon prices. Eni has informed us the hydrocarbon prices used in the preparation of this report are based on 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, 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, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 17, 2015
Page 3

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 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 singularly 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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 17, 2015
Page 4

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 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 December 2014 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 December 2014. 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

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Eni S.p.A. – Third Party
February 17, 2015
Page 5

reviewed such factual data for its reasonableness; however, we have not conducted an independent 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
February 17, 2015
Page 6

Eni furnished us with the above mentioned average prices in effect on December 31, 2014. 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 $101/bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. All gas prices shown below are in dollars per thousand cubic meters ($/km3). The average realized prices provided by Eni and used in our evaluation are as follows:

Geographic Area | Product | Average Proved Realized Prices
Africa | Gas | $402.54/km3
Oil | $101.02/bbl
Condensate | $59.00/bbl
Americas | Oil | $85.39/bbl
Asia | Gas | $156.84/km3
Condensate | $96.16/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, 2014. 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 subjected to and received the internal approvals required by Eni’s management at the appropriate local,

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Eni S.p.A. – Third Party
February 17, 2015
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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, 2014, 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.

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Eni S.p.A. – Third Party
February 17, 2015
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. ACUNA, P.E.
| Herman G. Acuna, P.E.
| Texas P.E. License No. 92254
| Managing Senior Vice President – International
| [SEAL]
| \s\ GABRIELLE GUERRE
| Gabrielle Guerre, P.E.
| TBPE License No. 109935
| Senior Petroleum Engineer
| [SEAL]
HGA(DPR)/pl |

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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.

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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.

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PETROLEUM RESERVES DEFINITIONS
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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.

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PETROLEUM RESERVES DEFINITIONS
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> (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.

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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.

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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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> 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.

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