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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
————————————————————
Form 20-F

(Mark One)

		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015
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.

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.

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.

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.

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.

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).

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):

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

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.

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).

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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	25
I	I	History and development of the Company	I	25
I	I	BUSINESS OVERVIEW	I	30
I	I	Exploration & Production	I	30
I	I	Gas & Power	I	59
I	I	Refining & Marketing	I	64
I	I	Corporate and Other activities	I	69
I	I	Discontinued operations	I	69
I	I	Research and development	I	71
I	I	Insurance	I	73
I	I	Environmental matters	I	73
I	I	Regulation of Eni’s businesses	I	81
I	I	Property, plant and equipment	I	86
I	I	Organizational structure	I	86
Item 4A.	I	UNRESOLVED STAFF COMMENTS	I	86
Item 5.	I	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	I	87
I	I	Discontinued operations	I	87
I	I	Executive summary	I	87
I	I	Critical accounting estimates	I	92
I	I	2013-2015 Group results of operations	I	92
I	I	Liquidity and capital resources	I	103
I	I	Recent developments	I	109
I	I	Management's expectations of operations	I	109
Item 6.	I	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	I	118
I	I	Directors and Senior Management	I	118
I	I	Compensation	I	126
I	I	Board practices	I	136
I	I	Employees	I	145
I	I	Share ownership	I	146
Item 7.	I	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	I	147
I	I	Major Shareholders	I	147
I	I	Related party transactions	I	147
Item 8.	I	FINANCIAL INFORMATION	I	148
I	I	Consolidated Statements and other financial information	I	148
I	I	Significant changes	I	148
Item 9.	I	THE OFFER AND THE LISTING	I	149
I	I	Offer and listing details	I	149
I	I	Markets	I	150
Item 10.	I	ADDITIONAL INFORMATION	I	152
I	I	Memorandum and Articles of Association	I	152
I	I	Material contracts	I	158
I	I	Exchange controls	I	158
I	I	Taxation	I	159
I	I	Documents on display	I	163
Item 11.	I	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	I	164
Item 12.	I	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	I	167
12A.	I	Debt securities	I	167
12B.	I	Warrants and rights	I	167
12C.	I	Other securities	I	167
12D.	I	American Depositary Shares	I	167
II	I	I	I	I
PART II	I	I	I	I
Item 13.	I	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	I	169
Item 14.	I	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	I	169
Item 15.	I	CONTROLS AND PROCEDURES	I	169
Item 16.	I	I	I	II
16A.	I	Board of Statutory Auditors financial expert	I	170
16B.	I	Code of Ethics	I	170
16C.	I	Principal accountant fees and services	I	170
16D.	I	Exemptions from the Listing Standards for Audit Committees	I	171
16E.	I	Purchases of equity securities by the issuer and affiliated purchasers	I	171
16F.	I	Change in Registrant’s Certifying Accountant	I	171
16G.	I	Significant Differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual	I	172
16H.	I	Mine safety disclosure	I	174
PART IIII	I	I	I	II
Item 17.	I	FINANCIAL STATEMENTS	I	175
Item 18.	I	FINANCIAL STATEMENTS	I	175
Item 19.	I	EXHIBITS	I	175

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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&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, Chemical and Corporate and Other activities.

References to Versalis or Chemical are to Eni’s chemical activities engaged through its fully-owned subsidiary Versalis and Versalis’ controlled entities.

 

STATEMENTS REGARDING COMPETITIVE POSITION

Statements made in "Item 4 – Information on the Company" referring to Eni’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and Eni’s internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.

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GLOSSARY

A glossary of oil&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&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&gas reserves are those quantities of oil&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&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&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&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&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

 

 

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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, 2011, 2012, 2013, 2014 and 2015.

Eni’s results of operations and cash flow as at and for the twelve months ended December 31, 2015 have been prepared in addition to the consolidated basis, stating separately continuing operations from discontinued operations, the latter accounted for in accordance to IFRS 5. Discontinued operations comprise:
•		The Engineering & Construction operating segment which is managed by Eni’s subsidiary Saipem SpA. On January 22, 2016, there was the closing of the preliminary agreements signed on October 27, 2015 with the Fondo Strategico Italiano (FSI). Those include the sale of a 12.503% stake of the share capital of Saipem to FSI and the concurrent enter into force of a shareholder agreement with Eni, which was intended to establish joint control over the former Eni subsidiary. Therefore effective for the full year, Saipem revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition as provided by IFRS 5, Eni’s net assets in Saipem have been aligned to the lower of their carrying amount and fair value given by the share price at the reporting date.
•		The Chemical segment managed by Eni’s wholly-owned subsidiary Versalis SpA. As of the reporting date, negotiations were underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business. Therefore, effective for the full year, likewise Saipem, Versalis revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition, Eni’s net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the transaction that is underway.

Comparative results of operations and cash flow for the year 2014 and 2013 have been restated accordingly as dictated by IFRS 5.

Also the selected historical financial data for the years 2012 and 2011 have been restated accordingly.

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,

	2011		2012		2013		2014		2015

CONSOLIDATED PROFIT STATEMENT DATA
Net sales from continuing operations		90,978			109,412			98,547			93,187			67,740
Operating profit (loss) by segment from continuing operations
Exploration & Production		15,887			18,470			14,868			10,766			(144	)
Gas & Power		(323	)		(3,129	)		(2,923	)		64			(1,258	)
Refining & Marketing		(276	)		(1,260	)		(1,534	)		(2,107	)		(552	)
Corporate and Other activities		(746	)		(641	)		(736	)		(518	)		(497	)
Impact of unrealized intragroup profit elimination and other consolidation adjustments (1)		(26	)		(607	)		(1,808	)		(620	)		(330	)
Operating profit (loss) from continuing operations		14,516			12,833			7,867			7,585			(2,781	)
Net profit (loss) attributable to Eni from continuing operations		4,675			2,097			3,472			101			(7,680	)
Net profit (loss) attributable to Eni from discontinued operations		2,185			5,693			1,688			1,190			(1,103	)
Net profit (loss) attributable to Eni		6,860			7,790			5,160			1,291			(8,783	)
Data per ordinary share (euro) (2)
Operating profit (loss):
- basic		4.01			3.54			2.17			(0.17	)		(0.77	)
- diluted		4.01			3.54			2.17			(0.17	)		(0.77	)
Net profit (loss) attributable to Eni basic and diluted from continuing operations		1.29			0.58			0.96			0.03			(2.13	)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		0.60			1.57			0.46			0.33			(0.31	)
Net profit (loss) attributable to Eni basic and diluted		1.89			2.15			1.42			0.36			(2.44	)
Data per ADR ($) (2) (3)
Operating profit (loss):
- basic		11.16			9.10			5.77			(0.46	)		(1.71	)
- diluted		11.16			9.10			5.77			(0.46	)		(1.71	)
Net profit (loss) attributable to Eni basic and diluted from continuing operations		3.59			1.48			2.55			0.08			(4.73	)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		1.68			4.04			1.22			0.88			(0.69	)
Net profit (loss) attributable to Eni basic and diluted		5.26			5.53			3.77			0.96			(5.42	)

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(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 2015 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 12, 2016.
(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/USD 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 2011 through 2014 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively.
		The dividend for 2015 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 0.80 per ADR) at the Noon Buying Rate recorded on the payment date on October 7, 2015, while the balance of euro 0.80 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2015. The balance dividend for 2015 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 25, 2016 to holders of Eni shares, being the ex-dividend date May 23, 2016, while ADRs holders will be paid on June 7, 2016.

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	As of December 31,

	2011		2012		2013		2014		2015

CONSOLIDATED BALANCE SHEET DATA
Total assets		142,945		140,192		138,341		146,207		134,792
Short-term and long-term debt		29,597		24,192		25,560		25,891		27,776
Capital stock issued		4,005		4,005		4,005		4,005		4,005
Minority interest		4,921		3,357		2,839		2,455		1,916
Shareholders’ equity - Eni share		55,472		59,060		58,210		59,754		51,753
Capital expenditures from continuing operations		11,909		12,805		11,584		11,264		10,775
Weighted average number of ordinary shares outstanding (fully diluted - shares million)		3,623		3,623		3,623		3,610		3,601
Dividend per share (euro) (1)		1.04		1.08		1.10		1.12		0.80
Dividend per ADR ($) (1) (2)		2.73		2.82		2.99		2.65		1.77

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(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 2015 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 12, 2016.
(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/USD 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 2011 through 2014 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively.
		The dividend for 2015 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 0.80 per ADR) at the Noon Buying Rate recorded on the payment date on October 7, 2015, while the balance of euro 0.80 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2015. The balance dividend for 2015 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 25, 2016 to holders of Eni shares, being the ex-dividend date May 23, 2016, while ADRs holders will be paid on June 7, 2016.

 

 

 

 

 

 

 

 

 

 

 

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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, 2011, 2012, 2013, 2014 and 2015.

	Year ended December 31,

	2011		2012		2013		2014		2015

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)		3,134		3,084		3,079		3,077		3,372
of which developed		1,850		1,762		1,831		1,847		2,100
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)		300		266		148		149		187
of which developed		45		44		35		46		48
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF)		15,582		14,190		14,442		14,808		14,302
of which developed		10,363		8,965		8,542		8,342		8,899
Proved reserves of natural gas of equity-accounted entities at period end (BCF)		4,700		6,767		3,726		3,737		3,993
of which developed		53		424		34		120		1,402
Proved reserves of hydrocarbons of consolidated subsidiaries at period end (mmBOE)		5,940		5,667		5,708		5,772		5,975
of which developed		3,716		3,394		3,387		3,366		3,720
Proved reserves of hydrocarbons of equity-accounted entities at period end (mmBOE)		1,146		1,499		827		830		915
of which developed		54		122		40		67		303
Average daily production of liquids (KBBL/d) (1)		845		882		833		828		908
Average daily production of natural gas available for sale (mmCF/d) (2)		3,763		4,118		3,868		3,782		4,284
Average daily production of hydrocarbons available for sale (KBOE/d) (2)		1,523		1,631		1,537		1,517		1,688
Hydrocarbon production sold (mmBOE)		548.5		598.7		555.3		549.5		614.1
Oil and gas production costs per BOE (2)		10.86		10.82		12.19		12.00		9.18
Profit (loss) per barrel of oil equivalent (3)		16.98		15.95		15.46		9.90		(3.20	)

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(1)		Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (321, 383, 451, 442 and 397 mmCF/d in 2011, 2012, 2013, 2014 and 2015, respectively).
(2)		Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment 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&gas information in "Item 18 – Notes on Consolidated Financial Statements".
(3)		Expressed in U.S. dollars. Results of operations from oil&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&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,

	2011		2012		2013		2014		2015

Sales of natural gas to third parties (1)		77.84		77.87		77.67		76.11		79.06
Natural gas consumed by Eni (1)		6.21		6.43		5.93		5.62		5.88
Sales of natural gas of affiliates (Eni’s share) (1)		9.85		8.29		6.96		4.38		2.78
Total sales and own consumption of natural gas of the Gas & Power segment (1)		93.90		92.59		90.56		86.11		87.72
E&P natural gas sales in Europe and in the Gulf of Mexico (1)		2.86		2.73		2.61		3.06		3.16
Worldwide natural gas sales (1)		96.76		95.32		93.17		89.17		90.88
Electricity sold (2)		40.28		42.58		35.05		33.58		34.88
Refinery throughputs (3)		31.96		30.01		27.38		25.03		26.41
Balanced capacity of wholly-owned refineries (4)		574		574		574		404		388
Retail sales (in Italy and rest of Europe) (3)		11.37		10.87		9.69		9.21		8.89
Number of service stations at period end (in Italy and rest of Europe)		6,287		6,384		6,386		6,220		5,846
Average throughput per service station (in Italy and rest of Europe) (5)		2,206		2,064		1,828		1,725		1,754
Employees at period end (number) (6)		28,209		30,350		30,970		29,403		29,053

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(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	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,
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
2015		1.20		1.05		1.11		1.09

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(1)

Average of the Noon Buying Rates for the last business day of each month in the period.

	High		Low		At period end

(U.S. dollars per euro)

October 2015		1.14		1.10		1.10
November 2015		1.10		1.06		1.06
December 2015		1.10		1.06		1.09
January 2016		1.10		1.07		1.08
February 2016		1.14		1.09		1.09
March 2016		1.14		1.08		1.14

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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 $1.14 per euro 1.00.

 

 

Risk factors

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

 

Eni’s operating results and cash flow and future rate of growth are exposed to the effects of fluctuating prices of crude oil, natural gas and oil products

Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni’s control. These factors include among other things:
•		global and regional dynamics of oil&gas supply and demand. The price of crude oil has been on a downtrend since the second half of 2014 with oil prices falling from the level of approximately 110 $/BBL (where "BBL" means barrel) by mid-year, down to multi-year lows below the 30-dollar mark in January 2016. For the full year 2015, the benchmark Brent crude oil price averaged 53 $/BBL with a reduction of approximately 50% year-on-year. This decline was driven by structural imbalances in the global oil market on the back of continued oversupplies fuelled by production growth in both Organization of the Petroleum Exporting Countries ("OPEC") and non-OPEC countries, as well as uncertainties about the pace of macroeconomic growth. However, according to our records, demand for fuels held remarkably well in 2015, posting one of the best increase of the latest years, which was spurred by price elasticity and other factors. Looking forward, we believe that there are risks of further price erosion in 2016, as witnessed by trends in crude oil prices in the first months of the year, reflecting continued oversupplies, increased risks of a slowdown in global economic activity, a rise in global stockpiles of crude oil and the return of Iran’s oil to the global market as sanctions are being lifted following its nuclear agreement with Western countries. Furthermore, uncertainties exist among market participants about the long-term prospects of the global energy demand also considering the growing political and institutional focus on energy conservation and reduction in Greenhouse Gas ("GHG") emissions;
•		global political developments, including sanctions imposed on certain producing countries and conflict situations;
•		global economic and financial market conditions;
•		the influence of OPEC over world supply and therefore oil prices;
•		prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables);
•		weather conditions;
•		operational issues;
•		governmental regulations and actions;
•		success in development and deployment of new technologies for the recovery of crude oil and natural gas reserves and technological advances affecting energy consumption; and
•		the effect of worldwide energy conservation and environmental protection efforts.

All these factors can affect the global balance between demand and supply for oil and prices of oil.

Management believes that a gradual absorption of the supply glut in the medium to long-term may occur, as a result of reduced investments by international oil companies, possible oil-producing countries’ agreements to curb output, a reduction in OPEC’s spare capacity and the probable forcing of less efficient players, such as the operators in the U.S. tight oil production which we believe to have a cost structure no longer sustainable under the current scenario, out of the market. However, management has evaluated a number of risks and uncertainties inherent in such expectations, including structural changes that have been affecting oil industry – e.g. the increase in oil supply following U.S. tight oil revolution – reduced impact of geopolitical crises and the greater role played by renewable energy sources, as well as risks associated with internationally-agreed measures intended to reduce GHG emissions. Based on this outlook, Eni’s management has revised downwards its pricing assumptions of the Brent crude oil marker utilized in each of the periods of the Company’s 2016-2019 strategic plan, in particular the long-term reference price has been reduced to 65 $/BBL, down from the 90-dollar scenario utilized in the previous planning assumptions and in evaluating recoverability of the carrying amounts of our oil&gas assets.

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Price fluctuations have had in 2015 and may continue to have a material adverse effect on the Group’s results of operations and cash flow. See "Item 5 – Operating and Financial Review and Prospects". Lower oil prices from one year to another negatively affect the Group’s consolidated results of operations and cash flow, because revenues are price sensitive; such current prices are reflected in revenues recognized in the Exploration & Production segment at the time of the price change, whereas expenses in this segment are either fixed or less sensitive to changes in crude oil prices than revenues. Eni estimates that its consolidated net profit and cash flow vary by approximately euro 0.2 billion for each one-dollar change in the price of the Brent crude oil benchmark with respect to the price scenario assumed in Eni’s financial projections for 2016 at 40 $/BBL. Free cash flow is expected to reduce/increase by a corresponding amount.

In addition to the adverse effect on revenues, profitability and cash flow, lower oil&gas prices could result in the debooking of proved reserves, if they become economically unfavorable in this type of environment, and asset impairments. In 2015, we debooked 84 million BOE of proved reserves because decreases in commodity prices shortened the economic lives of certain producing properties and caused certain development projects to become economically unfavorable. In 2015, we recorded impairment losses at our oil&gas properties in the region of euro 5 billion (euro 3.5 billion post-tax) which were mainly driven by our revised outlook for commodity prices.

Depending on the significant and speed of a decrease in crude oil prices, Eni may also need to review investment decisions and the viability of development projects. Lower oil&gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flow and hence the funds available to finance expansion projects, further reducing the Company’s ability to grow future production and revenues. In addition, they may reduce returns at development projects, either planned or implemented, forcing the Company to reschedule, postpone or cancel development projects. We are currently planning a capital budget of approximately euro 37 billion in the next four years excluding expenditures associated with our planned disposals, which is significantly lower than our previous financial projections, down by 21% on constant exchange rate basis, to take into account the expected lower cash flow from operations under our reduced price outlook in the years 2016-2019. We are forecasting crude oil prices in the range of 40 to 65 $/BBL in the next four years, which is significantly lower than our previous planning assumption of 55-90 $/BBL. Finally, lower oil prices over prolonged periods may trigger a review of the future recoverability of the Company’s carrying amounts of oil&gas properties, resulting in the recognition of significant further impairment charges. In response to weakened oil&gas industry conditions and resulting revisions made to rating agency commodity price assumptions, lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating by rating agencies, including Standard & Poor’s Ratings Services ("S&P") and Moody’s Investor Services Inc ("Moody’s"). These downgrades negatively affect our cost of capital, increase our financial expenses, and may limit our ability to access capital markets and execute aspects of our business plans. See also "Item 18 – note 28 – Long-term debt and current portion of long-term debt – of the Notes on Consolidated Financial Statements".

Eni estimates that movements in oil prices affect approximately 50% of Eni’s current production. The remaining portion of Eni’s current production is insulated from crude oil price movements considering that the Company’s property portfolio is characterized by a sizeable presence of production sharing contracts, where, due to the cost recovery mechanism, the Company is entitled to a larger number of barrels in case of a fall in crude oil prices. (See also the section on the specific risks of the Exploration & Production segment "Risks associated with the exploration and production of oil and natural gas" below).

Because of the above mentioned risks, an extended continuation of the current commodity price environment, or further declines in commodity prices, will materially and adversely affect our business prospects, financial condition, results of operations, cash flows, liquidity, ability to finance planned capital expenditures and commitments and may impact shareholder returns, including dividends and the share price.

In gas markets, price volatility reflects the dynamics of demand and supply for natural gas. Over the latest years, in the face of weak demand dynamics in Europe due to the economic downturn and competition from coal and renewable sources in the production of gas-fired power, gas supplies in Europe have continued to rise. Factors underlying this rise comprise the increased availability of liquefied natural gas ("LNG") on a global scale, which in the future will be fuelled by an expected growth in LNG exports from the U.S., and volumes of contracted supplies of European gas wholesalers under long-term arrangements with take-or-pay clauses. See also the other trends described in the specific risk-factors section of Eni’s Gas & Power business below. The increased liquidity of European hubs has put significant downward pressure on spot prices. Eni expects those trends to continue in the foreseeable future due to a weak outlook for gas demand and continued oversupplies. In case Eni fails to renegotiate its long-term gas supply contracts in order to make its gas competitive as market conditions evolve, its profitability and cash flow in the Gas & Power segment would be significantly affected by current downward trends in gas prices.

The Group’s results from its Refining & Marketing business are primarily dependent upon the supply and demand for refined products and the associated margins on refined product sales, with the impact of changes in oil prices on results of these segments being dependent upon the speed at which the prices of products adjust to reflect movements in oil prices.

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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 Eni’s margins and its market shares. Eni’s ability to remain competitive requires continuous focus on technological innovation, reducing unit costs and improving efficiency. It also depends on Eni’s ability to get 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 flow may be adversely affected.
•		In the Gas & Power segment, Eni faces strong competition from gas and energy players to sell gas to the industrial segment, the thermoelectric sector and the retail customers both in the Italian market and in markets across Europe. Competition has been fuelled by ongoing weak trends in demand due to the downturn and macroeconomic uncertainties and continued oversupplies in the marketplace. These have been driven by rising production of LNG on global scale and inter-fuel competition. The use of gas in gas-fired power plants has registered a dramatic decline due to the replacement with coal reflecting cost advantages and a dramatic growth in the adoption of renewable sources of energy (photovoltaic and solar). The large-scale development of shale gas in the United States was another fundamental trend that aggravated the oversupply situation in Europe because many LNG projects that originally targeted the U.S. market ended to supply the already saturated European sector. 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 until 2020 and beyond driven by economic growth and the increased adoption of gas in firing power production. European gas wholesalers including Eni committed to purchasing large amounts of gas under long-term supply contracts with so-called "take-or-pay" clauses from the main producing countries bordering Europe (namely Russia and Algeria). They also made significant capital expenditures to upgrade existing pipelines and to build new infrastructures in order to expand gas import capacity to continental markets. Long-term gas supply contracts with take-or-pay clauses expose gas wholesalers to a volume risk, as they are contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price. Due to the trends described above of the prolonged economic downturn and inter-fuel competition, the projected increases in gas demand failed to materialize, resulting in a situation of oversupply and pricing pressure. As demand contracted across Europe, gas supplies increased, thus driving the development of very liquid continental hubs to trade spot gas. Spot prices at continental hubs have become the main benchmarks to which selling prices are indexed across all end-markets, including large industrial customers, thermoelectric utilities and the retail segment. The profitability of gas operators was negatively impacted by falling sales prices at those hubs, where prices have been pressured by intense competition among gas operators in the face of weak demand, oversupplies and the constraint to dispose of minimum annual volumes of gas to be purchased under long-term supply contracts. Eni does not expect any 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 energy mix. Additionally, supplies at continental hubs will continue to build given the expected ramp-up of LNG exports from the United States due to steady growth in gas production and ongoing projects to reconvert LNG regasification facilities into liquefaction export units and the start of several LNG projects in the Pacific region and elsewhere. Eni believes that these ongoing negative trends may adversely affect the Company’s future results of operations and cash flows, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of gas in accordance 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 Italy who sell electricity in the Italian market. Going forward, the Company expects continuing competition due to the projections of moderate economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production on the Italian market. The economics of the gas-fired electricity business have dramatically changed over the latest

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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 benefit from governmental subsidies, and a recovery in the production of coal-fired electricity which was helped by a substantial reduction in the price of this fuel on the back of a massive oversupply of coal which occurred on a global scale. As a result of falling electricity prices, margins on the production of gas-fired electricity went into negative territory. Eni believes that the profitability outlook in this business will remain weak in the foreseeable future.
•		In the Refining & Marketing segment, Eni faces strong competition both in the industrial and in the commercial activities. Refining margins have been negatively impacted by declining demand due to growing energy efficiency and the economic downturn, as well as by growing competition from new large scale refineries in the Middle East, benefiting of low production costs. In 2015, refining margins rebounded as a consequence of falling oil price and a recovery in oil products demand. Looking forward, management believes that refining margins will remain under pressure. In 2016, Eni forecasts a lower refining margin than in 2015. In marketing Eni faces the challenges of a growing competition from no logo operators and large retailers, which leverage on the price awareness of the final consumers to increase their market share.

 

Safety, security, environmental and other operational risks

The Group engages in the exploration and production of oil and natural gas, processing, transportation, and refining of crude oil, transport of natural gas, storage and distribution of petroleum products. 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 the Exploration & Production segment, Eni faces natural hazards and other operational risks including those relating to the physical characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni’s personnel and risks of blowout, fire or explosion. Accidents at a single well can lead to loss of life, damage or destruction to properties, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operations, liquidity, reputation and prospects of the Group, including the share price and the dividends.

Eni’s activities in the Refining & Marketing segment entails health, safety and environmental risks related to the handling, transformation and distribution of oil and oil products. These risks arise from the inherent characteristics of hydrocarbons, in particular flammability and toxicity. Also environmental risks are involved in the use of oil products, such as GHG emissions, soil and groundwater contaminations.

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

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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 such as the 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 above mentioned could have a material adverse impact on the Group’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ returns and damage the Group’s reputation.

The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Company.

 

Risks associated with the exploration and production of oil and natural gas

The exploration and production of oil and natural gas require high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil&gas fields. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production.

A description of the main risks facing the Company’s business in the exploration and production of oil&gas is provided below.

 

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

Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2015, approximately 52% of Eni’s total oil&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&gas industry are inherently riskier than onshore activities. Offshore accidents and spills could have impacts also of catastrophic proportions on the ecosystem and health and security of people due to the objective difficulties in handling hydrocarbons containment, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Further, offshore operations are subject to marine risks, including storms and other adverse weather conditions and vessel collisions, as well as interruptions or termination by governmental Authorities based on safety, environmental and other considerations. Failure to manage these risks could result in injury or loss of life, damage to property, environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to Eni’s reputation and could have a material adverse effect on Eni’s operations, results, liquidity, reputation, business prospects and the share price.

 

Exploratory drilling efforts may be unsuccessful

Exploration drilling for oil&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 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

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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 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 2015, the Company spent euro 0.8 billion to conduct exploration projects and plans to spend approximately euro 0.9 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 exploration projects.

 

Development projects bear significant operational risks, which may adversely affect actual returns

Eni is executing or is planning to execute several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or environmentally sensitive locations. Eni’s future results of operations and liquidity depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include:
•		the outcome of negotiations with 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;
•		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 is seeking 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 deliver major projects on time and on budget could negatively affect 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&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.

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 losses of capitalized costs associated with reduced future cash flows of those projects.

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For example, we have incurred cost overruns and continuing delays in the achievement of first oil at the Kashagan offshore field in the Kazakh section of the Caspian Sea. The latest issue related to a pipeline for the transport of acid gas where a spillage occurred, forcing the Consortium to shut down production. The damaged pipeline needs to be replaced and activities are underway. Management believes that production will resume as early as in late 2016. See "Item 4 – Exploration & Production – Kashagan".

 

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 reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The opposite occurs in case of lower oil prices. Future oil&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&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, cash flow and business prospects.

 

Uncertainties in estimates of oil and natural gas reserves

Several uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of proved reserve estimates depend on a number of factors, assumptions and variables, among which the most important are the following:
•		the quality of available geological, technical and economic data and their interpretation and judgment;
•		projections regarding future rates of production and costs and timing of development expenditures;
•		changes in the prevailing tax rules, other government regulations and contractual conditions;
•		results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and
•		changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.

Reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s production sharing agreements and similar contractual schemes.

The prices used in calculating Eni’s estimated proved reserves are, in accordance with the U.S. Securities and Exchange Commission (the "U.S. SEC") requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ending December 31, 2015, average prices were based on 54 $/BBL for the Brent crude oil which compared to a price reference of 101 $/BBL in 2014. This decline in the price of crude oil triggered the downward revision of those reserves that have become uneconomic in this type of environment, amounting to approximately 84 mmBOE.

Commodity prices declined significantly in the fourth quarter of 2015 and in the first quarter of 2016 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 counterbalanced in full or in part by increased reserves corresponding to the additional volume entitlements under Eni’s PSAs 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.

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Many of these factors, assumptions and variables involved in estimating proved reserves are subject to change over time, therefore impact 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 be ultimately recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition.

 

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced

At December 31, 2015, approximately 42% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2015 includes estimates of total future development costs associated with our proved undeveloped reserves of approximately euro 38 billion (undiscounted). We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company’s development plans to develop of those reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves.

 

Oil and gas activity are subject to high levels of income taxes

The oil&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&gas operations in a number of countries where the Company conducts its upstream operations. Because of these trends, management estimates that the tax rate applicable to the Company’s oil&gas operations is materially higher than the Italian statutory tax rate for corporate profit, which currently stands at 27.5 per cent. See also "Item 18 – note 42 – Income taxes – of the Notes on Consolidated Financial Statements".

The effective tax rate of the Company’s Exploration & Production segment for the fiscal year 2015 was estimated at approximately 80 per cent driven by: (i) the recognition of a major part of positive pre-tax results in PSA contracts, which, although more resilient in a low-price environment, nonetheless bear higher-than-average rates of tax; and (ii) a higher incidence of certain non-deductible expenses on the pre-tax profit that has been lowered by the scenario. Also this outsized tax rate was due to the fact that in certain jurisdictions we were unable to match before-tax losses with the recognition of deferred tax assets due to lack of expected future taxable profit against which those asset can be utilized. Looking forward management believes that the tax rate in this segment will continue being negatively affected by those factors due to the persistence of weak commodity prices.

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&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.

 

The present value of future net revenues from Eni’s proved reserves will not necessarily be the same as the current market value of Eni’s estimated crude oil and natural gas reserves and, in particular, may be reduced due to the recent significant decline in commodity prices

Investors should not assume the present value of future net revenues from Eni’s proved reserves is the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with U.S. SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially

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higher or lower than the U.S. SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
•		the actual prices Eni receives for sales of crude oil and natural gas;
•		the actual cost and timing of development and production expenditures;
•		the timing and amount of actual production; and
•		changes in governmental regulations or taxation.

The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni’s reserves or the crude oil and natural gas industry in general.

At December 31, 2015, the net present value of Eni’s proved reserves totaled approximately euro 37.8 billion, calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932), significantly lower than in 2014 due to reduced commodity prices. The average price used to estimate Eni’s proved reserves and the net present value at December 31, 2015, as calculated in accordance with U.S. SEC rules, was 54 $/BBL for the Brent crude oil that compares to 101 $/BBL in 2014. 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 Eni’s year-end reserve estimates were in line with the pricing environment existing in the first quarter of 2016, Eni’s PV-10 at December 31, 2016 could decrease significantly.

 

Political considerations

A substantial portion of Eni’s oil&gas reserves and gas supplies are located in countries outside the EU and the North America, mainly in Africa, Central Asia and Central-Southern America, where the socio-political framework and macroeconomic outlook is less stable than in the OECD countries. In those less stable countries, Eni is exposed to a wide range of risks and uncertainties which could materially impact the ability of the Company to conduct its operations in a safe, reliable and profitable manner.

As of December 31, 2015, approximately 81% of Eni’s proved hydrocarbon reserves were located in such countries and 60% of Eni’s supplies of natural gas came from outside OECD countries. Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions, inflation levels, exchange rates and similar events in those non-OECD countries may negatively impair Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues:
•		lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
•		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&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 share of profit from a given project, thereby reducing Eni’s profit share. They can also render different interpretations of contractual clauses relating to the recovery of certain expenses incurred by the Company to produce hydrocarbons reserves in any given projects. As of the balance sheet date receivables for euro 773 million relating to cost recovery under certain petroleum contracts in a non-OECD country were the subject of an arbitration proceeding;
•		restrictions on exploration, production, imports and exports;
•		tax or royalty increases (including retroactive claims);
•		political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar incidents. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, the loss of personnel or assets. They may force Eni to evacuate personnel for security reasons and to increase spending on security. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographic areas in which Eni operates;
•		difficulties in finding qualified suppliers in critical operating environment; and
•		complex process in granting authorizations or licenses affecting time-to-market of certain development projects.

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Areas where Eni operates, where the Company is particularly exposed to the political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Indonesia, Kazakhstan, Venezuela, Iraq and Russia. In addition, any possible reprisals because of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on Eni’s business, results of operations and financial condition.

In recent years, Eni’s production levels in Libya were negatively impacted by an internal revolution and a change of regime in 2011, which led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political development forced Eni to temporarily interrupt or reduce its producing activities, negatively affecting Eni’s results of operations and cash flow until the situation began to stabilize. Although our production levels in Libya for the year 2015 returned to levels not seen from the outbreak of the civil war, the geopolitical situation remains unstable and unpredictable. In 2015, Libya accounted for approximately 20% of the Group total hydrocarbons production for the year and going forward its contribution albeit slowing down will remain significant. In case of major unfavorable geopolitical developments in Libya including but not limited to, a resurgence of civil war, renewed internal tensions, civil disorder or any other outbreak of violence, we could be forced to shut down our operations and interrupt production which could significantly and negatively affect our results of operations, cash flow, business prospects and shareholder value. 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 geopolitical outlook in Libya and unsafe operational conditions onshore Nigeria were factored up to a certain extent in the Company’s projections of future production levels in these two countries. See "Item 5 – Management’s expectations of operations".

In the current depressed environment for crude oil prices, the financial outlook of certain countries where Eni’s hydrocarbons reserves are located has significantly deteriorated due to lower proceeds from the exploitation of hydrocarbons resources. This trend has increased the risk of sovereign default, which may cause political and macroeconomic instability and trigger one or more of the above mentioned risks factors. State-owned petroleum companies of those countries are exposed to a liquidity risk too. Eni is partnering those national oil companies in executing certain oil&gas development projects. A possible sovereign default might jeopardize the financial feasibility of ongoing projects or increase the financial exposure of Eni, which is contractually obligated to finance the share of development expenditures of the first party in case of a financial shortfall of the latter. 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.

In Egypt, we have experienced continued difficulties in collecting overdue trading receivables for the supply of our share of oil&gas production to local oil&gas companies. As of December 31, 2015, Eni owned a significant amount of trade receivables due (euro 771 million) in respect of supplies of its oil&gas entitlements to local companies. Management is currently addressing the recoverability of the Company’s trade receivables vs. Egyptian counterparties leveraging various initiatives and commercial agreements. Eni has not experienced any disruptions in its producing activities in the Country to date.

Eni closely monitors political, social and economic risks of approximately 60 countries in which has invested or intends to invest, in order to evaluate the economic and financial return of certain projects and to selectively evaluate projects. While the occurrence of those events is unpredictable, it is likely that the occurrence of any such events could adversely affect Eni’s results from operations, cash flow and business prospects.

 

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

Eni is closely monitoring developments to the political situation in Russia, Ukraine and the Crimea Region and is adapting its business activities to the sanctions adopted by the relevant authorities in Europe and the U.S. targeting the financial sector and the energy sector in Russia in view of Russia’s actions intended to destabilize the political framework in Ukraine. Eni will adapt to any further related regulations and/or economic sanctions that could be adopted by the Authorities. The EU enacted Regulation No. 833/2014, which is restricting, inter alia, the supply of certain oil&gas items to Russia and certain forms of financing related to the oil and gas sector in Russia.

Approximately 30% of Eni’s natural gas is supplied by Russia and Eni is currently partnering the Russian company Rosneft in executing exploration activities in the Russian sections of the Barents Sea and the Black Sea. Contracts pertaining to the above mentioned exploration licenses were entered into before enactment of the restrictive measures and have been put on hold since then. Eni started the required authorization procedure before the relevant EU Member States’ Authorities who granted the Company certain authorizations that are valid throughout the whole European Union. However, given the uncertainty surrounding this matter, Eni cannot exclude major delays in certain ongoing or planned oil&gas projects in Russia.

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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

We expect a weak trading environment in our Gas & Power segment, which will negatively affect the profitability outlook in this business

Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the four-year planning period. Those include weak demand growth due to macroeconomic uncertainties, muted thermoelectric consumption, continuing oversupplies and strong competition. Eni believes that those trends will negatively affect the gas marketing business future results of operations and cash flows by reducing gas selling prices and margins. Our financial outlook has factored in the rigidities of the Company’s long-term supply contracts with take-or-pay clauses, where the Company is obligated to offtake a contractually set minimum volume of gas supplies or, in case of failure, to pay the contractual price (see below).

The main source of risk is concerning Eni’s wholesale business which results are exposed to the volatility of the spreads between spot prices at European hubs and Italian spot prices because our supply costs are mainly indexed to spot prices at European hubs, whereas a large part of our selling volumes are indexed to Italian spot prices.

Against this backdrop, Eni’s management will continue to execute its strategy of renegotiating the Company’s long-term gas supply contracts in order to align pricing and volume terms to current market conditions as they evolve. The revision clauses provided by these contracts states the right of each counterparty to renegotiate the economic terms and other contractual conditions periodically, in relation to ongoing changes in the gas scenario. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately achieved and the timing of recognition in profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, the claiming party has faculty to open an arbitration procedure to obtain revised contractual conditions. This would add to the level of uncertainty surrounding the outcome and timing of those renegotiations. In 2015, the results of operations in the Gas & Power segment were negatively affected by a delay in the settlement of an arbitration procedure with a long-term supplier, which management had budgeted to recognize in that year, owing to the complexity of the matter. These considerations also apply to ongoing renegotiations with our long-term buyers. In 2015, the performance of our Gas & Power business was negatively affected by the unfavorable outcome of an arbitration procedure with one of our long-term buyer, where the amount of the discount on the price of gas awarded to the claimant was higher than our initial provision. Based on these risk factors, we believe that future results of the Gas Marketing activities are subject to increasing 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 certain key producing countries, which include Russia, Algeria, Libya, Norway and the Netherlands, where most of European gas supplies are sourced from.

These contracts have a residual life of approximately 12 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.

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 if the Company fulfills its minimum take obligation in a given year and within the limit of the maximum annual quantity. Similar considerations apply to ship-or-pay contractual obligations.

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Looking forward, management believes that the current market outlook which will be driven by a weak recovery in gas demand, continued oversupplies and strong competitive pressures as well as any possible change in sector-specific regulation represents a risk factor to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts. Adding to this risk, the Company is currently forecasting sales volumes to remain flat or to decrease slightly in 2016 and in the subsequent years compared to 2015.

Furthermore, the above mentioned take-or-pay clause exposes the Company to a price risk because the cost of gas that the Company recognizes at the incurrence of the take-or-pay clause may be higher than the current cost of gas supplies in the year when the accrued gas is actually reversed through profit and loss. In 2015, the segment operating profit was hit by a euro 150 million charge in connection to this factor.

 

Risks associated with sector-specific regulations in Italy

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

Eni’s Gas & Power segment is exposed to regulatory risks mainly in its domestic market in Italy. Developments in the regulatory framework may negatively affect future sales margins of gas and electricity, operating results and cash flow. Below is provided an overview of the most important aspects of the ongoing regulatory framework of the gas sector in Italy including management’s evaluation of the possible impacts on the future results of operations in the Gas & Power segment.

The Italian Authority for Electricity and Gas (the "Authority") is entrusted with certain powers in the matter of natural gas pricing. Specifically, the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential users. Accordingly, decisions of the Authority 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.

In 2013, the Authority changed 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, by this way replacing the former oil-linked indexation. The new regulatory regime was introduced in a market scenario where gas spot prices were significantly lower than gas prices under long-term, oil-linked contracts, as the Brent price at the time was about 100 $/BBL. Subsequently, the Authority introduced a compensation mechanism to promote the renegotiation of long-term gas supply contracts. This compensation mechanism was intended to mitigate the impact of the new tariff regime to operators with long-term supply contracts (typically oil-linked) by reimbursing to them part of the higher long term gas supply costs which would be no longer recoverable trough tariffs. This compensation mechanism applies to the three thermal years, from October 2013 through October 2016.

The Authority set the initial amount of the compensation in 2013 based on the documentation filed by each operator, taking into account the price differential between the average price of a basket of theoretically efficient long-term contract and spot prices at the Dutch platform TTF. The Authority elaborated a projection of the supply costs of gas that Eni would incur in the future thermal year of the compensation mechanism, under various oil prices assumptions. Based on those projections and on gas forward prices and volume forecast for Eni, the Authority established a maximum compensation of euro 160 million, to which Eni would be entitled for the three-thermal year period of the mechanism implementation. The Authority resolution envisages that 40% of the compensation is due in the first thermal year, 40% in the second year and 20% in the third thermal year. In each thermal year, the Authority would update the compensation mechanism to verify the ongoing right of gas operators to receive compensation in the light of evolving trends in costs and prices of gas. Based on this, the initial amount of the compensation would be confirmed or, in case trends in spot prices vs. oil-linked prices reverse, operator would have to compensate customers by paying to the Authority up to three time the amount of the initial compensation, plus giving back any tranche of the compensation already cashed in.

In thermal year 2014, the Authority updated the index of supply costs applicable to Eni’s portfolio. Under a 100 $/BBL scenario, the AEEGSI verified that Eni’s costs of supplies were higher than spot prices and accordingly ratified the first tranche of the compensation equal to euro 60 million (or the 40% of the initial amount). This gain was recognized in the group consolidated financial statements for the year 2014. In November 2015, the Authority updated the index of procurement cost for thermal year 2015 and resolved that Eni’s supply costs have evolved coherently to the Authority projections made in 2013. Under this scenario, the Authority confirmed the initial amount of the compensation of euro 160 million and Eni recognized a second tranche equal to 40% of that amount (approximately euro 60 million) in the 2015 Financial Statements.

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In spite of these favorable developments, considering the current market scenario, it is possible that the Authority might determine an unfavorable update of the supply cost index for the thermal year 2016. Under this scenario, Eni could incur a loss up to three times the amount of the initial compensation or euro 480 million, giving back the amounts already recognized in 2014 and 2015.

The final outcome is expected in the fourth quarter of 2016 when the AEEGSI is scheduled to update the supply cost index for the thermal year 2016, on which basis Eni is due to recognize the profit and loss impact (positive or negative as the case may be).

In the light of current market scenario, Eni prudently contested the Resolution 549/2014/R/gas, which implements the compensation mechanism. Eni claimed that the Resolution did not provided sufficient criteria for updating the compensation and could potentially determine unfair results, also contending its legitimacy.

 

Environmental, health and safety regulations

Eni has incurred in the past, will continue incurring material operating expenses and expenditures, and is exposed to business risk in relation to compliance with applicable environmental, health and safety regulations in future years, including compliance with any national or international regulation on GHG emissions

Eni is subject to numerous EU, international, national, regional and local laws and regulations about the impacts of its operations on the environment and health and safety of employees, contractors, communities and properties. Generally, these laws and regulations require acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining 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&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 and other Group’s operations.

Different kinds of limits and restrictions on the activities of exploring and producing hydrocarbons could be enacted also in OECD countries due to environmental reasons or other motivations as it would occur in case of a favorable outcome of an Italian referendum scheduled April 17, 2016 on whether to abrogate an environmental rule that currently allows oil&gas operators to continue production at offshore fields located in territorial waters beyond relevant concessions term till fields depletion. Eni is currently operating 29 concessions in Italy’s territorial waters. These concessions account for approximately 1% of the Company’s proved reserves at December 31, 2015 (6,890 mmBOE). Within such amount and factoring in the portion of those reserves that could be produced before the expirations of the underlying concessions, in case of an unfavorable outcome of the above mentioned referendum and assuming that those concessions would be revoked upon expiration, the Company’s results of operations and cash flow might be negatively affected also considering the negative impact associated with higher amortization charges and accelerated wind down of decommissioning liabilities.

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 Italian Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations and to safeguard the environment, safety 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);

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

Risks of environmental, health and safety incidents and liabilities are inherent in many of Eni’s operations and products. Management believes that Eni adopts high operational standards to ensure safety in running its operations and safeguard of the environment and the health of employees, contractors and communities. In spite of those measures, it is possible that incidents like blowouts, oil spills, contaminations, pollution, and release in the air, soil and ground water of pollutants and other dangerous materials, liquids or gases, and other similar events could occur that would result in damage, also of large proportion and reach, to the environment, employees, contractors, communities and property. The occurrence of any such events could have a material adverse impact on the Group business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ return and damage to the Group reputation.

Eni has incurred in the past and may incur in the future material environmental liabilities in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental 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 of operations that was lawful at the time it occurred or the conduct of prior operators or other third parties. In addition, plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case, the Company is held liable of violations of any environmental laws or regulations.

Eni is notified from time to time of potential liabilities at the Italian sites where the Company has conducted industrial operations in the past. 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. The Group believes that it cannot be held liable for contaminations occurred in past years (as permitted by applicable regulations in case of declaration rendered by a guiltless owner i.e. as a result of Eni’s conduct that was lawful at the time it occurred) or because Eni took over operations from third parties. However, state or local public administrations sued Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company, or which the Company committed to perform.

Eni expects remedial and clean-up activities at Eni’s sites to continue in the foreseeable future impacting Eni’s liquidity. As of December 31, 2015, 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 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

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environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites.

As a result of those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni’s liquidity, results of operations, consolidated financial condition, business prospects, reputation and shareholders’ value, including dividends and the share price.

 

Laws and regulations related to climate change may adversely affect the Group’s businesses

Growing public concern in a number of countries over GHG emissions and climate change, as well as a multiplication of stricter regulations in this area, could adversely affect the Group’s businesses, increase its operating costs and reduce its profitability.

The scientific community has established a link between climate change and increasing GHG emissions. The worldwide goal to limit global warming has led to the need to gradually reduce fossil fuel use notably through the diversification of the energy mix. The share of natural gas, the least GHG-emitting fossil energy source, represented 46% of Eni’s production in 2015 on available-for-sale basis.

In December 2015, a global climate agreement was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The agreement, which goes into effect in 2020, resulted in nearly 200 countries committing to work towards limiting global warming and agreeing to a monitoring and review process of GHG emissions. The agreement includes binding and non-binding elements and did not require ratification by countries. Nonetheless, the agreement may result in increased political pressure worldwide to adopt measures intended to reduce and monitor GHG emissions and may spur further initiatives aimed at reducing GHG emissions in the future.

Changes in environmental requirements related to GHG and climate change may negatively impact demand for oil and natural gas and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of GHG in areas in which Eni conducts business. Because Eni’s business depends on the global demand for oil and natural gas, existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including incentives to 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.

The adoption and implementation of regulations that require reporting of GHG or otherwise limit emissions of GHG from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or install new equipment to reduce emissions of GHG associated with our operations.

Finally, it should be noted some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. If any such effects were to occur as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.

 

Risks related to legal proceedings and compliance with anti-corruption legislation

Eni is the defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of December 31, 2015 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

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anticorruption 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 is constantly monitoring the oil&gas market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks connected to acquisitions materialize, Eni’s financial performance and shareholders’ returns may be adversely affected.

 

Risks deriving from Eni’s exposure to weather conditions

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing business, as well as the comparability of results over different periods may be affected by such changes in weather conditions. In general, the effects of climate change could result in less stable weather patterns, resulting in more severe storms and other weather conditions that could interfere with Eni’s operations and damage Eni’s facilities. Furthermore, Eni’s operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to Eni’s operations and consequent loss or damage of properties and facilities, as well as loss of output, revenues, maintenance and repair expenses and cash flow shortfall.

 

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 period could prolong the impact of any disruption and could severely affect business, operations and financial results. 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 with negative consequences on results of operations and cash flow.

 

Exposure to financial risk

Eni’s business activities are inherently exposed to financial risk. This includes exposure to market risk, including commodity price risk, interest rate risk and foreign currency risk, as well as liquidity risk, and credit risk.

Eni’s primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil&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.

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 risks.

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

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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 incurred in euros. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity. The Exploration & Production segment is particularly affected by movements in the 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 2015, the Exploration & Production results of operations were positively affected by trends in the exchange rate of the euro against the U.S. dollar as the euro depreciated on average by 16.5% against the U.S. dollar.

 

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

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may rise in connection with variations in sovereign rating risks or company rating risks, as well as the general conditions of capital markets.

 

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively affect the Group results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. European and global financial markets are currently subject to volatility amid uncertainties relating to a weak macroeconomic outlook, particularly in the Euro-zone, and the financial stress of certain emerging economies or countries whose financial conditions depends upon the proceeds of the sale of hydrocarbon resources following an ongoing slump in commodity prices. 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&gas industry is capital intensive. Eni makes and expect to continue to make substantial capital expenditures in its business for the exploration, development, exploitation and production of oil and natural gas reserves. In 2015, we invested approximately euro 10.2 billion in our Exploration & Production segment, down by approximately 17% from 2014 at constant exchange rates, in response to weak oil prices. Our capital budget for the four-year plan 2016-2019 amounts euro 37 billion, excluding capex associated with our disposal plan, and is substantially lower than our previous industrial plan (down by an estimated 21% at constant exchange rates) as a result of a planned reduction in spending prompted by significantly depressed commodity prices. This capital plan is directed for about 90% to the E&P segment. We have budgeted euro 9.4 billion for capital expenditure in 2016 relating to continuing operations which are 20% lower than in 2015 at constant exchange rates. We may find that additional reductions in our 2016 capital spending become necessary depending on market conditions.

Historically, Eni’s capital expenditures have been financed with cash generated by operations, proceeds from asset disposal, borrowings under its credit facilities and proceeds from the issuance of debt and bonds.

The actual amount and timing of future capital expenditures may differ materially from Eni’s estimates as a result of, among others, changes in commodity prices, available cash flows, lack of access to capital, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments.

Eni’s cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to:
•		the amount of Eni’s proved reserves;
•		the volume of crude oil and natural gas Eni is able to produce and sell from existing wells;
•		the prices at which crude oil and natural gas are sold;
•		Eni’s ability to acquire, find and produce new reserves; and

•

the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds.

If revenues or Eni’s ability to borrow decrease significantly due to factors like a prolonged decline in crude oil and natural gas prices, Eni might have limited ability to obtain the capital necessary to sustain its planned capital expenditures. If cash generated by operations, cash from asset disposal, or cash available under Eni’s liquidity reserve or its credit facilities is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of Eni’s reserves, which in turn could adversely affect its business, financial condition, results of operations, and cash flows and its ability to achieve its growth plans.

With respect to the 2016-2019 business plan in particular, management expects to deliver approximately euro 7 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of stakes in our exploration assets thereby in essence monetizing some of the Group’s recent exploration successes and reserves. These additional cash flows are intended to provide funding to support organic growth and our planned shareholders distributions in a manner consistent with our target capital structure. The Company is seeking to complete such disposals in large part within 2016-2017. However, asset disposals are subject to execution risk and may fail to be completed, and the proceeds received from such disposals may not reflect values that management currently believes are achievable, particularly if the disposals are carried out in difficult market conditions. The failure to achieve the planned disposal program could negatively affect the achievement of our financial targets forcing us to either curtail capital expenditure thus hampering growth or take on more finance debt.

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

In addition, funding Eni’s capital expenditures with additional debt will increase its leverage and the issuance of additional debt will require a portion of Eni’s cash flows from operations to be used for the payment of interest and principal on its debt, thereby reducing its ability to use cash flows to fund capital expenditures and dividends.

 

Credit risk

Credit risk arise from the exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In the latest years, the Group has experienced a 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. Furthermore, a collapse in oil prices has stressed the financial condition of many State-owned entities, which are party to our upstream projects for exploring and developing hydrocarbons. In Eni’s 2015 Consolidated Financial Statements, it was accrued an allowance against doubtful accounts amounting to euro 581 million (compared to euro 518 million in 2014), 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. 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 Eni cannot exclude the recognition of significant provisions for doubtful accounts.

 

Digital infrastructure is an important part of maintaining Eni’s operations. A breach of Eni’s digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs

The reliability and security of Eni’s digital infrastructure is critical to maintaining the availability of Eni’s business applications, including the reliable operation of technology in Eni’s various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. If Eni’s systems for protecting Eni’s digital security prove to be ineffective, either due to intentional actions such as cyber attacks or 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. Furthermore, in some circumstances, failures to protect digital infrastructure could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

 

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. SEC, as auditor of companies that are traded publicly in the United States and firms registered with the Public Company Accounting Oversight Board ("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 out of the reach of PCAOB inspections. PCAOB inspections of audit firms have identified holes and 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 Eni’s 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 of the continuing operations engages in oil&gas exploration, development and production, marketing of gas, electricity and LNG, power generation, refining and marketing of petroleum products and, commodity trading. In 2015, the Group commenced a plan to divest its Engineering & Construction segment, which is managed by the subsidiary Saipem (Eni’s interest being 42.9%), and its Chemical business which is managed by Eni’s wholly-owned subsidiary Versalis. In the 2015 Consolidated Financial Statements, the two segments have been accounted for in accordance with IFRS 5 "non-current assets held for sale and discontinued operations". Therefore, they have been disclosed as discontinued operations and have been measured at the lower of their carrying amounts and fair value; results of operations and cash flow of the comparative periods have been restated accordingly. Eni has operations in 66 countries and 29,053 employees (excluding Saipem and Versalis) as of December 31, 2015.

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 42 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2015, Eni average daily production amounted to 1,688 KBOE/d on an available-for-sale basis. As of December 31, 2015, Eni’s total proved reserves amounted to 6,890 mmBOE; proved reserves of subsidiaries totaled 5,975 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 915 mmBOE. In 2015, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 21,436 million and an operating loss of euro 144 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 2015, Eni’s worldwide sales of natural gas amounted to 90.88 BCM. Sales in Italy amounted to 38.44 BCM, while sales in European markets were 52.44 BCM which included 4.61 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, 2015. In 2015, electricity sold totaled 34.88 TWh. In 2015, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 52,096 million and an operating loss of euro 1,258 million. The Gas & Power segment comprises results of the Group activities intended to manage commodity risk and of asset-backed trading activities. Through the trading department of the parent company and its wholly-owned subsidiary Eni Trading & Shipping SpA, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. 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. Since 2015, of the Gas & Power segment also comprises the result of activities of crude oil and products supply, trading and shipping services provided on behalf of Group companies, which were formerly reported in the Refining & Marketing segment (see Item 5). Previous reporting periods data have been restated accordingly.

Eni’s Refining & Marketing segment engages in crude oil supply and refining and petroleum products marketing in retail and wholesale markets mainly in Italy and in the rest of Europe. In 2015, processed volumes of crude oil and other feedstock amounted to 26.41 mmtonnes and sales of refined products were 35.24 mmtonnes, of which 26.53 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 8.89 mmtonnes in Italy and in the rest of Europe. In 2015, Eni’s retail market share in Italy through its "Eni" branded network of service stations was

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24.5%. In 2015, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 18,458 million and operating loss of euro 552 million.

A list of Eni’s subsidiaries is provided in "Item 18 – note 46 – Other information about investments – of the Notes on Consolidated Financial Statements".

 

Strategy

In order to manage a sharply deteriorated commodity 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 on results and cash flow and to preserve the Group financial structure, particularly in the short to medium term. Our financial projections for the four-year plan 2016-2019 and capital project evaluations are based on the assumption of a long-term Brent reference price of 65 $/BBL that is significantly lower than our previous long-term price assumption of 90 $/BBL. Our new long-term price assumption is reflective of our view of worsened market fundamentals driven by continued oversupplies and uncertainties about the pace of energy demand growth in the long term. We are forecasting a Brent price of 40 $/BBL in 2016 and a progressive recovery along the plan period up to the long term case of 65 $/BBL due to an expected better balance between supply and demand in the light of reduced capital expenditure plans by oil majors, the possible exit from the market of producers with unsustainable cost structure and any possible agreements on part of producing countries to curb output.

Against the backdrop of a depressed commodity price environment in the short to medium term, our primary target remains to generate adequate cash flow from operations which will be underpinned by well-designed industrial actions, capital discipline, focus on Exploration & Production activities and a large disposal plan.

In particular, our strategic guidelines could be articulated along different time horizons:
•		in the near-term, we will seek to maximize cash-flow generation in order to preserve the company’s financial structure by increasing efficiency programs, and by modulating and re-phasing capital expenditures;
•		in the medium-term, we will focus on capital discipline to develop our portfolio of hydrocarbons resources which we believe offer us many options to profitably grow production due to the low break-even price of our new projects, also targeting to maintain a strong reserve replacement ratio; and
•		in the long-term, we intend to lie the foundation to adapt our business model to a competitive landscape where oil companies will be required to reduce significantly GHG emissions.

In approving the capital expenditure plan for the 2016-2019 period the Company identified actions designed to reconfigure and re-phase long-term projects and to reduce the costs of the supply of upstream plants and facilities and other field services by renegotiating contracts leveraging on the deflationary pressure induced by low oil prices. This optimization will result in euro 37 billion capital expenditures in the next four years net of the capex associated with the disposal plan, down by approximately 21% compared to the previous plan, at constant exchange rates. The disposal plan, amounting to approximately euro 7 billion in the 2016-2019 period, is based on the dilution of our working interests in certain promising exploration assets and will provide additional financial flexibility. The Company forecasts that the planned industrial actions, the reduction in expenditures and the disposal plan will enable Eni to preserve its financial structure during the worst phase of the oil downturn, targeting to maintain the leverage below the threshold of 0.3 throughout the oil cycle. In projecting our cash flows and cash requirement we planned to confirm the current level of our cash dividend. 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 higher than 3% 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 capital expenditure 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 due to continued weak demand, strong competition and oversupplies which will affect sale prices and margins.
		Our 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 streamlining operations optimizating logistic costs focusing on the development and growth in value added segments (retail sales of gas and electricity, LNG, trading), and in the medium term, exploiting synergies in connection with better monetization of equity gas in international markets thanks to our knowledge in trading.

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•

Our priority in the Refining & Marketing segment is to strengthen profitability and cash generation even in a depressed downstream oil environment. We plan to lower our break-even refining margin, maintaining the current refining capacity, leveraging on optimizations in existing plants (increasing the conversion capacity of our refineries in order to process low-quality crudes), the ramp-up of Venice green refinery and the completion of a new green refinery in Gela, while maintaining a strong focus on efficiency. In the marketing business in Italy we will enhance profitability leveraging on innovation of products and services, as well as on efficiency. Outside Italy, Eni plans to grow selectively in target European markets (Germany, Austria, Switzerland and France).

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".

 

2015 disposal activity

In the last months of 2015, Eni carried out a complex transaction to restructure the share ownership of its listed subsidiary Saipem through a transaction involving a new shareholder, Fondo Strategico Italiano (FSI), an entity controlled by the Italian Minister of Economy and Finance, which also included the reimbursement of intercompany loans owed by Saipem to Eni. The transaction was in line with the Group strategy aimed to:
1.		focus on Group’s upstream core business, by making available additional financial sources to be reinvested in the development of oil&gas reserves; and
2.		strengthen the Group capital structure on the back of the weak oil scenario.

On January 22, 2016, following the satisfaction of all the conditions precedent, among which the consensus of Consob to the share capital increase resolved by Saipem, Eni closed the Sale and Purchase Agreement regarding the sale of 12.503% of the share capital of Saipem to the Fondo Strategico Italiano (FSI). The transaction refers to No. 55,176,364 Saipem shares at an average price of euro 8.39 per share for a total consideration of euro 463 million. The reference price for the transaction was determined as the arithmetic average of the official prices of the Saipem shares recorded in the trading days immediately before and after the announcement to the markets of the transaction, on October 28, 2015. The total consideration has been paid by FSI in a single installment, at closing.

At the closing of the Sale and Purchase Agreement, the preliminary Shareholders’ Agreement signed by Eni and FSI on October 27, 2015 became effective. The Agreement establishes the terms and conditions that shall govern, from the closing date onwards, the two parties’ respective relationships as shareholders of Saipem, particularly with reference to the entity corporate governance and any possible transaction relating each party’s interest in Saipem.

Each of Eni and FSI are contributing to the Shareholders’ Agreement an equal number of Saipem shares not exceeding 12.503% of the Company’s ordinary share capital (therefore up to a total amount slightly above 25% of Saipem ordinary share capital). The Shareholders’ Agreement which entered into force on the closing date has a three-year term, with automatic renewal for a further period of three years, unless terminated by notice.

The key elements of the Shareholders’ Agreement provides, inter alia: (a) for the future renewal of corporate bodies, the submission by Eni and FSI of a single list for the appointment of the board of directors (where the President and the CEO will be designated jointly by the parties) and the panel of statutory auditors of Saipem and the relevant vote commitments; (b) mutual commitments to stand-still and lock-up commitment on all the shares contributed to the Shareholders’ Agreement, and certain other restriction regarding the transfer of shares not contributed to the Shareholders’ Agreement; and (c) obligations to engage in consultation before exercising voting rights and, to the extent permitted by law, voting commitments (also regarding Saipem shares not contributed to the Shareholders’ Agreement) in relation to all resolutions submitted to the shareholders meetings of Saipem and certain resolutions of Saipem’s Board of Directors that are conventionally considered relevant, among which the approval of the industrial plan.

Based on the new corporate governance setup of Saipem, Eni and FSI have joint control of Saipem.

Finally Eni and FSI committed towards Saipem to subscribe pro-rata the share capital increase resolved by the entity for euro 3.5 billion.

The agreements provides the reimbursement of intercompany financing receivables owed by Saipem to Eni through the proceeds of the share capital increase and the refinancing with certain third-party financing institutions.

Considering that the transactions disclosed above were closed after the 2015 reporting date, in Eni’s Consolidated Financial Statements for the year 2015 Saipem is still fully consolidated and presented as "discontinued operation"

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based on the guidelines of IFRS 5 on disposal assets. Therefore, effective for the full year, Saipem revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition, Eni’s net assets in Saipem have been aligned to the lower of their carrying amount and their fair value given by Saipem share price at the reporting date (euro 7.49 per share) (see "Item 5" for further information).

Therefore, the economic and financial impacts of the Saipem transaction will be recorded in Eni 2016 accounts, as described below:
•		considering that the corporate governance of Saipem as defined in the Shareholders Agreement has established joint control over the entity, Eni is set to derecognise the former subsidiary’s asset and liabilities, revenues and expenses, effective January 22, 2016. The residual stake in Saipem of 30.42% will be recognized as an investment in an equity-accounted joint venture with initial carrying amount aligned to Saipem share price at the closing date of the transaction (euro 4.2 per share) equal to an overall value of euro 564 million and a loss to be recognized through profit and loss of euro 441 million (resulting from the difference between the fair value on the closing date and the book value at December 31, 2015). This loss will be recognized in the Group consolidated accounts for the first quarter 2016 as part of gains and losses of the discontinued operations. Considering the pro-quota subscription of Saipem’s share capital increase, the book value of Eni’s residual interest in the former subsidiary currently amounts to euro 1,614 million;
•		a reduction of euro 4.8 billion in net borrowings resulting from the reimbursement by Saipem to Eni of intercompany financing receivables (euro 5.4 billion as of December 31, 2015), the proceeds from the disposal of Eni’s stake (euro 0.4 billion), net of the amount cashed out to subscribe Saipem share capital increase (euro 1.07 billion); and
•		assuming the effects of the transaction at December 31, 2015, the Group leverage would improve significantly.

At the end of February 2016, following completion of the subscription of the share capital increase and assumption by Saipem of third-party refinancing, Saipem reimbursed intercompany loans owed to Eni.

As of the date of the transaction agreement, Eni is subjected to the de facto control of the MEF (Italian Ministry of Economy and Finance). FSI is also indirectly controlled by MEF. Therefore the transaction is a transaction between Eni and one of its related parties. In executing this transaction Eni has complied with all relevant applicable listing standards, market regulation and internal procedures set to ensure fairness and formal and substantial correctness of the transaction as well as the fact that the transaction was in the best interest of the Company.

In 2015, the Group commenced a plan to reduce its exposure to the Chemical business managed by Eni’s wholly-owned subsidiary Versalis SpA. At the reporting date negotiations were underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business.

Therefore, effective for the full year, like Saipem, Versalis revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition, Eni’s net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the proposal transaction. See "Item 5 – Discontinued operations".

 

Other significant business and portfolio developments

The significant business and portfolio developments that occurred in 2015 and to date in 2016 were the following:
•		In March 2016, Eni was awarded the operatorship of the exploration license Cape Three Points Block 4 (Eni’s interest 42.47%), located in the offshore of Ghana.
•		In March 2016, Eni signed a Farm-Out Agreement (FOA) with Chariot Oil & Gas that includes the operatorship to Eni and a 40% stake enter into Rabat Deep Offshore exploration permits I-VI offshore Morocco. The completion of this FOA is subject to the authorization of the Moroccan Authorities, to current partners’ approval and other conditions precedent.
•		In March 2016, production was started up at the Goliat field, located within the Production License 229, off Norway. Goliat, the first oil field to start production in the Barents Sea, was developed through the floating cylindrical production and storage vessel (FPSO). The Unit has a capacity of 1 million barrels of oil. The daily output will reach 100,000 BOE/d (65,000 BOE/d net to Eni).
•		In February 2016, Mozambique Authorities sanctioned the development of the first development phase of Coral, targeting to put into production 5 TCF of gas.
•		In December 2015, in Mozambique, following the signing of the Unitization and Unit Operating Agreement (UUOA) and in full agreement with all the concessionaries of the projects, a unitization was set out for the development of the natural gas reservoirs straddling Areas 4 (operated by Eni) and 1 (operated by Anadarko) in the Rovuma Basin, offshore Mozambique. In accordance with the UUOA, the development of the straddling reservoirs will be carried out at an early stage in a separated but coordinated way by the two

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		operators. Future developments will be jointly pursued by Area 4 and Area 1 concessionaires. The Final Investment Decision relating the Mamba field in Eni’s operating Area is expected in 2017.
•		In December 2015, Eni entered Mexico’s upstream sector by signing the Production Sharing Contract as operator (Eni’s interest 100%) of Block 1 to develop the oilfields of Amoca, Miztón e Tecoalli. The delineation campaign of the fields was submitted to the Mexican Authorities in the first quarter of 2016 and plans the drilling of four wells in order to define a fast track and synergic development plan.
•		In August 2015, Eni made a large discovery at the Zohr exploration prospect in the deep waters of the Egyptian section of the Mediterranean Sea. Based on ongoing studies management considers that this discovery contains a large amount of gas resources.
•		In July 2015, Eni started production at the Perla gas field, offshore Venezuela. Perla is one of Eni’s most important start-ups of 2015 and has been developed in just 5 years, an industry leading time-to-market. A production plateau is expected at approximately 1,200 mmCF/d. Gas is sold to the national oil&gas company PDVSA under a Gas Sales Agreement running until 2036.
•		In June 2015:

	-		Eni signed a preliminary agreement with KazMunayGas to acquire 50% of the mineral rights in the Isatay block in the Caspian Sea; and
	-		Eni signed an agreement to supply 1.4 mmtonnes/y of LNG from the Eni-operated Jangkrik field (Eni’s interest 55%) to the Indonesian state-run company PT Pertamina, effective in 2017. The agreement will support the development of the Jangkrik field.

•		In March 2015, Eni has finalized a strategic oil agreement in Egypt, which provides investment of up to $5 billion (at 100%) to develop the Egypt’s oil&gas reserves in future years. Eni has also agreed on new terms for ongoing oil contracts, with the economic effects retroactive to January 1, 2015. Set new measures to reduce overdue amounts of trade receivables relating to hydrocarbon supplies to Egyptian State-owned companies.
•		In January 2015, Eni sanctioned the final investment decision for the integrated Offshore Cape Three Points (OCTP) oil&gas project (Eni 47.22%, operator), in Ghana. The first oil is expected in 2017.
•		In 2015, in addition to the large Zohr discovery, the main discoveries were made: (i) in the prospect Nkala Marine in the Marine XII block in Congo; (ii) in Egypt, with a gas and condensates discovery in the Noroos prospect in the West Abu Madi license, which has entered production in just two months and the Melehia West Deep discovery in the Western Egyptian Desert; (iii) in Libya, in the contractual area D with a gas and condensates discovery; and (iv) in Indonesia, in the Merakes field.

In addition, Eni closed the following transactions:
•		in January 2016, Eni received reimbursement of the bonds exchangeable into ordinary shares of Snam, through the receipt of approximately 288 million shares equal to approximately 8.22% of the share capital of the company. Eni holds a residual interest of the 0.03% of Snam share capital; and
•		in November 2015, Eni completed the sale of a residual 4% interest in Galp with proceeds of euro 325 million at a price of euro 9.81 per share. The transaction was carried out through an accelerated book-building procedure aimed at institutional investors.

In 2015, capital expenditures of continuing operations amounted to euro 10,775 million, entirely relating to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 9,341 million) deployed mainly in Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia, Italy and the United States, and exploratory projects (euro 820 million) carried out primarily in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia; (ii) refining, supply and logistics in Italy and outside Italy (euro 282 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 126 million); and (iii) initiatives to upgrade combined-cycle power plants (euro 69 million).

In 2014, capital expenditures of continuing operations amounted to euro 11,264 million and primarily related to: (i) development of oil&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) 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 (iii) initiatives to improve flexibility of the combined-cycle power plants (euro 98 million).

In 2013, capital expenditures of continuing operations amounted to euro 11,584 million, and primarily related to: (i) development of oil&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) 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 (iii) initiatives to improve flexibility of the combined-cycle power plants (euro 119 million).

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BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 42 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2015, Eni average daily production amounted to 1,688 KBOE/d on an available-for-sale basis. As of December 31, 2015, Eni’s total proved reserves amounted to 6,890 mmBOE; proved reserves of subsidiaries totaled 5,975 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 915 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 more than 3% on average in the next 2016-2019 four-year period. Our production plans are incorporating our Brent price scenario of 40 $/BBL in 2016 and a gradual recovery in the subsequent years up to our long-term case of 65 $/BBL in 2019 and going forwards (on constant monetary term compared to 2019, i.e. from 2020 onwards crude oil prices will grow in line with a projected inflationary rate); as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under "Item 5 – Management’s expectations of operations".

Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations including, North Africa, Sub-Saharan Africa, Barents Sea, Kazakhstan, and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. Planned start-ups over the next four years will add more than 800 KBOE/d of new production by 2019; over 90% of these new projects have already been sanctioned and 90% 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 37 billion to explore for and to develop reserves over the next four years, with a decrease of 18% 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.

Exploration projects will attract some euro 3.5 billion with a reduction of 37% net of exchange rate effects in 2016 and 28% over the plan period. Exploration expenditure will be focused on proven plays, near field and appraisal exploration, where we plan to drill 80% of our scheduled wells. The most important amounts of exploration expenditure will be incurred in 2018.

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 years 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.

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For the year 2016, management plans to spend over euro 8.6 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&gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.

Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil&gas reserves can be designated as "proved", the accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information.

Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme applies to buy-back and service contracts.

 

Reserves governance

Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.

Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has stated that those guidelines comply with the SEC rules¹. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines.

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserves data.

The head of the Reserves Department attended the "Università degli Studi di Milano" and received a Master of Science degree in Physics in 1988. He has more than 25 years of experience in the oil&gas industry and more than 15 years of experience in evaluating reserves.

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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 2015, Ryder Scott Company, DeGolyer and MacNaughton and Gaffney, Cline & Associates provided an independent evaluation of approximately 31% of Eni’s total proved reserves at December 31, 2015⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation⁵.

In the 2013-2015 three-year period, 86% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2015, the main Eni properties not subjected to independent evaluation in the last three years were Kashagan (Kazakhstan) and CAFC-MLE (Algeria).

 

 

 

 

 

 

 

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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, 2015, 2014 and 2013. Net proved reserves are set out in more detail under the heading "Supplemental oil and gas information" on page F-139.

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, 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
Year ended Dec. 31, 2015		465		495		1,694		1,282		1,198		422		269		150		5,975
developed		362		404		1,010		764		689		159		217		115		3,720
undeveloped		103		91		684		518		509		263		52		35		2,255
Equity-accounted entities
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
Year ended Dec. 31, 2015						14		87				4		810				915
developed						14		22				2		265				303
undeveloped								65				2		545				612
Consolidated subsidiaries and equity-accounted entities
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
Year ended Dec. 31, 2015		465		495		1,708		1,369		1,198		426		1,079		150		6,890
developed		362		404		1,024		786		689		161		482		115		4,023
undeveloped		103		91		684		583		509		265		597		35		2,867

 

 

 

 

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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, 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
Year ended Dec. 31, 2015		228		305		821		787		771		262		189		9		3,372
developed		171		237		542		511		355		126		149		9		2,100
undeveloped		57		68		279		276		416		136		40				1,272
Equity-accounted entities
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
Year ended Dec. 31, 2015						13		16						158				187
developed						13		6						29				48
undeveloped								10						129				139
Consolidated subsidiaries and equity-accounted entities
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
Year ended Dec. 31, 2015		228		305		834		803		771		262		347		9		3,559
developed		171		237		555		517		355		126		178		9		2,148
undeveloped		57		68		279		286		416		136		169				1,411

 

 

 

 

 

 

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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, 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
Year ended Dec. 31, 2015		1,304		1,044		4,798		2,714		2,354		878		439		771		14,302
developed		1,051		919		2,566		1,390		1,830		185		373		585		8,899
undeveloped		253		125		2,232		1,324		524		693		66		186		5,403
Equity-accounted entities
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
Year ended Dec. 31, 2015						13		387				12		3,581				3,993
developed						13		85				9		1,295				1,402
undeveloped								302				3		2,286				2,591
Consolidated subsidiaries and equity-accounted entities
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
Year ended Dec. 31, 2015		1,304		1,044		4,811		3,101		2,354		890		4,020		771		18,295
developed		1,051		919		2,579		1,475		1,830		194		1,668		585		10,301
undeveloped		253		125		2,232		1,626		524		696		2,352		186		7,994

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 139 mmBOE as of December 31, 2015 (282 and 536 mmBOE as of December 31, 2014 and 2013, respectively). Said volumes are not included in reserves volumes shown in the table herein.

	Subsidiaries		Equity-accounted entities

	2013		2014		2015		2013		2014		2015

Additions to proved reserves		621			643			849						11			98
Purchases of minerals-in-place		4			4
Sales of minerals-in-place		(13	)		(8	)		(17	)		(652	)
Production for the year (a)		(571	)		(575	)		(629	)		(20	)		(8	)		(13	)

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(a)

The difference over production sold of 642.4 mmBOE (555.3 mmBOE in 2013 and 549.5 mmBOE in 2014) reflected natural gas volumes of 26.4 mmBOE consumed in operations (30 mmBOE in 2013 and 29.4 mmBOE in 2014), changes in inventories and other factors.

	Subsidiaries and equity-accounted entities

	2013		2014		2015

Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources

(7)

112

145

Eni’s proved reserves as of December 31, 2015 totaled 6,890 mmBOE (liquids 3,559 mmBBL; natural gas 18,295 BCF). Eni’s proved reserves reported an increase of 288 mmBOE, or 4.4%, from December 31, 2014. All sources

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additions to proved reserves booked in 2015 were 947 mmBOE; of which 849 mmBOE came from Eni’s subsidiaries and 98 mmBOE from Eni’s share of equity-accounted entities.

Price effects were globally positive, leading to an upward revision of 278 mmBOE, due to higher volume entitlements at our PSA contracts because of the cost recovery mechanism reflecting a lowered Brent price used in the reserve estimation process down to 54 $/BBL in 2015 compared to 101 $/BBL in 2014, which was marginally offset by our having to remove certain volumes of reserves which have become uneconomical in that environment. Further information about how to determine year-end amounts of proved reserves and the relevant net present value is provided in "Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas".

The methods (or technologies) used in the Eni’s proved reserves assessment in 2015 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates.

The all sources reserves replacement ratio achieved by Eni’s subsidiaries and equity-accounted entities was 145% in 2015 (112% in 2014 and negative in 2013). Excluding the portfolio activities the organic reserves replacement ratio was 148% (112% in 2014 and 105% in 2013). The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities - Oil & Gas (Topic 932) (see the supplemental oil and gas information in "Item 18 – Consolidated Financial Statements"). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserve replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, reservoir performance, application of new technologies to improve the recovery factor as well as changes in oil&gas prices, political risks and geological and environmental risks. See "Item 3 – Risks associated with the exploration and production of oil and natural gas – Uncertainties in estimates of oil and natural gas reserves".

The average reserves life index of Eni’s proved reserves was 10.7 years as of December 31, 2015 which included reserves of both subsidiaries and equity-accounted entities.

 

Eni’s subsidiaries

Eni’s subsidiaries added 849 mmBOE of proved oil&gas reserves in 2015. This comprised 636 mmBBL of liquids and 1,175 BCF of natural gas. Additions to proved reserves derived from: (i) revisions of previous estimates were 781 mmBOE mainly reported in Kazakhstan, Iraq, Egypt and Congo due to contractual revisions, continuous development activities and field performances; (ii) extensions and discoveries were 66 mmBOE, with major increases booked in Egypt and Indonesia following new discoveries and proved area extensions; (iii) improved recovery were 2 mmBOE mainly reported in Egypt; and (iv) sales of mineral-in-place related to the divestment of assets in Nigeria (16 mmBOE) and the United States (1 mmBOE).

 

Eni’s share of equity-accounted entities

Additions in Eni’s share of equity-accounted entities’ proved oil&gas amounted to 98 mmBOE in 2015 and derived from revisions of previous estimates reported in Venezuela and Angola.

 

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2015 totaled 2,867 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,411 mmBBL, mainly concentrated in Africa and Kazakhstan. Proved undeveloped reserves of natural gas amounted to 7,994 BCF, mainly located in Africa and Americas. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,272 mmBBL of liquids and 5,403 BCF of natural gas.

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In 2015, total proved undeveloped reserves decreased by 302 mmBOE mainly due to: (i) reclassification to proved developed reserves (down by 550 mmBOE); and (ii) divestments (down by 5 mmBOE) in Nigeria. Partially offset by: (i) revisions of previous estimates (up by 204 mmBOE) mainly reported in Venezuela, Iraq and Egypt; (ii) extensions and discoveries (up by 48 mmBOE), in particular in Indonesia, Egypt and Ghana; and (iii) improved recovery (up 1 mmBOE) in particular in Egypt.

During 2015, Eni converted 550 mmBOE of proved undeveloped reserves to proved developed reserves due to the progress of development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the following fields/projects: Perla (Venezuela), Goliat and Midgard (Norway), Litchendjili (Congo) and M’Pungi (Angola).

In 2015, capital expenditure amounted to approximately euro 9 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 0.8 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 reserves as a result of hooking-up new producing wells which are currently being completed and plant capacity expansion as a part of the sanctioned Phase 1 of the global development plan of the Kashagan field; (ii) certain Libyan gas fields (0.2 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields which are expected to be put in production over the next several years; and (iii) other 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).

Eni remains strongly committed to put these projects into production over the next few years. The length of the development period is a function of a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project.

 

Delivery commitments

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

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 479 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria, Norway and Venezuela.

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

Eni has met all contractual delivery commitments as of December 31, 2015.

 

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.

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In 2015, oil and natural gas production available for sale averaged 1,688 KBOE/d (1,517 KBOE/d in 2014) increased by 11.3% from 2014. The increase was driven by new field start-ups and the continuing ramp-up of production at fields started in 2014, mainly reported in Angola, Venezuela, the United States and the United Kingdom, higher production in Libya and Iraq as well as the recovery of trade receivables for past investments in Iran (See "Disclosure pursuant to Section 13(r) of the Exchange Act"). These positive effects were partly offset by the decline of mature fields. New field start-ups and ramp-ups of production added an estimated 139 KBOE/d of new production.

Liquids production (908 KBBL/d) increased by 80 KBBL/d, or 9.7%, due to higher production in Libya, Iran and Iraq as well as new fields start-ups and ramp-ups in particular in Angola, the United States and Norway.

Natural gas production (4,284 mmCF/d) reported an increase of 502 mmCF/d, or 13.3% from 2014. The start-ups in Venezuela, the United Kingdom, Egypt and the United States, as well as higher production in Libya more than offset the decline of mature fields.

Oil and gas production sold amounted to 614.1 mmBOE. The 1.9 mmBOE difference over production on an available-for-sale basis (616 mmBOE) reflected mainly changes in inventories and other factors. Approximately 61% of liquids production sold (330.1 mmBBL) was destined to Eni’s mid-downstream sectors. About 25% of natural gas production sold (1,560 BCF) was destined to Eni’s Gas & Power segment.

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

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

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(a)

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

 

 

 

 

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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

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(a)

It excludes production volumes of natural gas consumed in operations. Said volumes were 442 mmCF/d, or 29.4 mmBOE.

 

2015 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)		161		179		631		324		92		123		120		25		1,655
		(mmBOE)		59		65		230		119		33		45		44		9		604
Eni share of equity-accounted entities		(KBOE/d)						4						5		24				33
		(mmBOE)						1						2		9				12
Liquids production
Eni consolidated subsidiaries		(KBBL/d)		69		85		268		256		56		77		75		5		891
		(mmBBL)		25		31		98		93		20		28		28		2		325
Eni share of equity-accounted entities		(KBBL/d)						4						1		12				17
		(mmBBL)						1						1		4				6
Natural gas production
Eni consolidated subsidiaries		(mmCF/d)		503		515		1,990		378		199		259		243		107		4,194
		(BCF)		183		188		727		138		73		94		89		39		1,531
Eni share of equity-accounted entities		(mmCF/d)						3						19		68				90
		(BCF)						1						7		25				33

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(a)

It excludes production volumes of natural gas consumed in operations. Said volumes were 397 mmCF/d, or 26.4 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 84 KBOE/d, 78 KBOE/d and 67 KBOE/d in 2015, 2014 and 2013, respectively.

The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. Also Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided. The average production cost does not include any ad valorem or severance taxes.

 

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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

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
2015
Consolidated subsidiaries
Oil and condensates, per BBL		43.46		45.88		46.66		49.91		48.26		40.10		43.36		45.84		46.46
Natural gas, per KCF		6.92		6.30		4.69		1.49		0.47		4.83		2.20		5.07		4.54
Average production cost, per BOE		11.08		10.93		5.72		14.08		7.93		6.48		11.61		14.49		9.18
Equity-accounted entities
Oil and condensates, per BBL						18.03						27.89		38.18				35.15
Natural gas, per KCF						3.78						9.27		4.24				5.30
Average production cost, per BOE						8.98						8.67		16.48				14.51

 

Development activities

In 2015, a total of 335 development wells were drilled (132.4 of which represented Eni’s share) as compared to 440 development wells drilled in 2014 (191 of which represented Eni’s share) and 463 development wells drilled in 2013 (187.2 of which represented Eni’s share). The drilling of 103 development wells (35 of which represented Eni’s share) is currently underway.

The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2015. 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,

		2013		2014		2015		2015

(units)

Productive

Dry

Productive

Dry

Productive

Dry

Gross

Net

Italy		7.4		1.0		12.5				6.0				6.0		3.6
Rest of Europe		6.3				9.8		1.0		10.2		0.1		14.0		3.0
North Africa		61.6		3.3		54.5		1.0		30.5		2.8		17.0		9.2
Sub-Saharan Africa		26.3		1.2		31.6				22.0		2.5		28.0		4.8
Kazakhstan		0.3				1.5				4.7				16.0		3.1
Rest of Asia		61.7		4.3		54.2		1.6		29.7		5.9		6.0		2.3
Americas		13.8				22.1		0.7		17.4		0.1		16.0		9.0
Australia and Oceania						0.1		0.4		0.5
Total including equity-accounted entities		177.4		9.8		186.3		4.7		121.0		11.4		103.0		35.0

 

Exploration activities

In 2015, a total of 29 new exploratory wells were drilled (19.1 of which represented Eni’s share), as compared to 44 exploratory wells drilled in 2014 (25.8 of which represented Eni’s share) and 53 exploratory wells drilled in 2013 (27.8 of which represented Eni’s share).

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The overall commercial success rate was 16.7% (25.1% net to Eni) as compared to 31.3% (38.0% net to Eni) and 36.9% (38.5% net to Eni) in 2014 and 2013, 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, 2015. 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)

		2013		2014		2015		2015

(units)

Productive

Dry

Productive

Dry

Productive

Dry

Gross

Net

taly								0.6						4.0		2.8
Rest of Europe				3.4				4.3				2.2		9.0		2.3
North Africa		4.9		5.4		3.5		4.3		3.3		5.8		15.0		12.5
Sub-Saharan Africa		3.2		6.6		7.3		7.3		0.6		2.9		34.0		17.8
Kazakhstan				0.4										6.0		1.1
Rest of Asia		4.3		2.7		1.3		4.3				3.4		7.0		2.3
Americas		0.2		1.2		2.0		1.4		1.0		0.3		4.0		2.5
Australia and Oceania				0.5				0.9						1.0		0.3
Total including equity-accounted entities		12.6		20.2		14.1		23.1		4.9		14.6		80.0		41.6

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(1)

Includes temporary suspended wells pending further evaluation.

 

Oil and gas properties, operations and acreage

In 2015, Eni performed its operations in 42 countries located in five continents. As of December 31, 2015, Eni’s mineral right portfolio consisted of 852 exclusive or shared rights of exploration and development activities for a total acreage of 342,708 square kilometers net to Eni of which developed acreage of 40,640 square kilometers and undeveloped acreage of 302,068 square kilometers net to Eni. In 2015, changes in total net acreage mainly derived from: (i) new leases mainly in Egypt, Mexico, Myanmar, the United Kingdom and Ivory Coast for a total acreage of approximately 21,500 square kilometers; (ii) the total relinquishment of licenses mainly in Congo, Ghana, Italy, Nigeria, Norway, Pakistan, Tunisia and the United States, covering an acreage of approximately 15,600 square kilometers; and (iii) interest increase in Australia and partial relinquishment in Indonesia for a total net acreage of 2,000 square kilometers.

 

 

 

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The table below provides certain information about the Company’s oil&gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2015. A gross acreage is one in which Eni owns a working interest.

	December 31, 2014		December 31, 2015

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		44,842		274		15,873		52,732		68,605		10,989		34,134		45,123
Italy		17,297		147		10,647		10,436		21,083		8,924		8,051		16,975
Rest of Europe		27,545		127		5,226		42,296		47,522		2,065		26,083		28,148
Cyprus		10,018		3				12,523		12,523				10,018		10,018
Croatia		987		2		1,975				1,975		987				987
Greenland		1,909		2				4,890		4,890				1,909		1,909
Norway		3,672		56		2,310		7,594		9,904		452		2,662		3,114
Portugal		6,370		3				9,099		9,099				6,370		6,370
United Kingdom		744		48		941		1,501		2,442		626		1,279		1,905
Other countries		3,845		13				6,689		6,689				3,845		3,845
AFRICA		159,341		283		63,142		260,577		323,719		19,788		137,653		157,441
North Africa		21,693		119		30,392		26,704		57,096		13,778		11,921		25,699
Algeria		1,179		42		3,222		187		3,409		1,148		31		1,179
Egypt		4,946		57		5,623		17,829		23,452		2,121		7,547		9,668
Libya		13,294		10		17,947		8,688		26,635		8,951		4,343		13,294
Tunisia		2,274		10		3,600				3,600		1,558				1,558
Sub-Saharan Africa		137,648		164		32,750		233,873		266,623		6,010		125,732		131,742
Angola		4,327		72		7,688		13,608		21,296		987		3,417		4,404
Congo		2,883		26		1,794		943		2,737		971		383		1,354
Gabon		7,615		6				7,615		7,615				7,615		7,615
Ghana		1,664		2				226		226				100		100
Ivory Coast				1				1,431		1,431				429		429
Kenya		40,426		7				61,363		61,363				40,426		40,426
Liberia		1,841		3				7,364		7,364				1,841		1,841
Mozambique		5,103		6				3,911		3,911				1,956		1,956
Nigeria		7,638		36		23,268		8,747		32,015		4,052		3,380		7,432
South Africa		32,847		1				82,202		82,202				32,881		32,881
Other countries		33,304		4				46,463		46,463				33,304		33,304
ASIA		109,237		70		17,556		202,632		220,188		5,803		111,380		117,183
Kazakhstan		869		6		2,391		2,542		4,933		442		427		869
Rest of Asia		108,368		64		15,165		200,090		215,255		5,361		110,953		116,314
China		7,075		8		77		7,056		7,133		13		7,056		7,069
India		6,167		11		206		16,546		16,752		109		6,058		6,167
Indonesia		26,248		14		3,218		31,415		34,633		1,217		23,907		25,124
Iraq		446		1		1,074				1,074		446				446
Myanmar		7,065		4				24,080		24,080				20,050		20,050
Pakistan		9,467		15		10,390		11,486		21,876		3,396		5,414		8,810
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		180		1		200				200		180				180
Vietnam		26,384		5				30,777		30,777				23,132		23,132
Other countries		3,244		1				14,600		14,600				3,244		3,244
AMERICAS		7,943		211		5,245		9,458		14,703		3,351		3,277		6,628
Ecuador		1,985		1		1,985				1,985		1,985				1,985
Mexico				3				67		67				67		67
Trinidad & Tobago		66		1		382				382		66				66
United States		3,500		192		1,617		2,301		3,918		803		1,315		2,118
Venezuela		1,066		6		1,261		1,543		2,804		497		569		1,066
Other countries		1,326		8				5,547		5,547				1,326		1,326
AUSTRALIA AND OCEANIA		13,376		14		1,140		21,679		22,819		709		15,624		16,333
Australia		13,376		14		1,140		21,679		22,819		709		15,624		16,333
Total		334,739		852		102,956		547,078		650,034		40,640		302,068		342,708

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

 

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The table below 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, 2015. 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 wells capable of production. The total number of oil and natural gas productive wells is 9,241 (3,667.5 of which represent Eni’s share).

Productive oil&gas wells at Dec. 31, 2015 ^(a)

		Oil wells		Natural gas wells

(units)		Gross		Net		Gross		Net

Italy		238.0		192.1		605.0		523.6
Rest of Europe		363.0		59.7		179.0		100.6
North Africa		1,782.0		941.1		211.0		90.7
Sub-Saharan Africa		3,065.0		613.4		344.0		27.2
Kazakhstan		185.0		50.7
Rest of Asia		688.0		457.2		998.0		380.9
Americas		230.0		121.1		328.0		101.6
Australia and Oceania		7.0		3.8		18.0		3.8
Total including equity-accounted entities		6,558.0		2,439.1		2,683.0		1,228.4

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(a)

Multiple completion wells included above: approximately 2,234 (799.1 net to Eni).

 

Eni’s principal oil&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 2015, Eni’s oil&gas production amounted to 161 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 (51 operated onshore and 64 operated offshore) and exploration licenses (11 onshore and 9 offshore).

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		The Adriatic and Ionian Sea represents Eni’s main production area, accounting for 47% of Eni’s domestic production in 2015. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela-Angelina, Hera Lacinia, Bonaccia and Porto Garibaldi. 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. On March 31, 2016, as part of an investigation commenced by the Italian Public Prosecutor of Potenza for alleged environmental crimes that is disclosed in the legal proceeding section in the notes to the financial statements (see page F-86), it was ordered the seizure of certain plants that are functional to the activity of hydrocarbons production, which has been shut down. The interruption is currently affecting a production of approximately 60 KBOE/d net to Eni. The value-in-use of the Val d’Agri CGU determined as part of the impairment review of 2015 significantly exceeds the CGU carrying amount, so to exclude that even under the worst-case production shutdown among the currently foreseeable scenarios a reduction of the CGU book value at the reporting date might occur. In Sicily, Eni operates 12 production concessions onshore and 3 offshore. The main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2015 accounted for approximately 11% of Eni’s production in Italy.
Development activities included: (i) a new gas treatment unit realized at the Val d’Agri concession; (ii) maintenance and optimization of production, mainly at the Barbara, Anemone, Annalisa, Armida and Guendalina fields; and (iii) start-up of the Bonaccia NW project and ongoing development activities at the Clara field. 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 fields decline. Rest of Europe Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the United Kingdom. In 2015, the Rest of Europe accounted for 11% of Eni’s total worldwide production of oil and natural gas. Croatia. Eni has been present in Croatia since 1996. In 2015, Eni’s production of natural gas averaged approximately 19 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula. Exploration and production activities in Croatia are regulated by PSAs. The main producing gas fields are Annamaria, Ivana, Ika & Ida, Ika JZ, Ana, Marica and Katarina and are operated by Eni through a 50/50 joint operating company with the Croatian oil company INA. Norway. Eni has been operating in Norway since 1965. Eni’s activities are performed in the Norwegian

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Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 103 KBOE/d in 2015.

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 2015 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 2015 produced approximately 24 KBOE/d net to Eni and accounted for 23% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.

Eni is currently performing development activities in the Barents Sea. In 2015, 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. In March 2016, production start-up was achieved at the Goliat field. Production plateau is estimated at 65 KBBL/d net to Eni. The project includes a subsea system consisting of 22 wells, of which 12 are oil producers, 7 water injectors and 3 gas injectors, linked to the cylindrical FPSO by subsea production and injection flowlines.

At the beginning of 2015, production start-up was achieved at the Eldfisk 2 field (Eni’s interest 12.39%) in the North Sea and in September 2015, Åsgard Subsea Compression project started up in order to optimize production from Mitgard (Eni’s interest 14.8%) and Mikkel fields (Eni’s interest 14.9%) in the Norwegian Sea. Other activities concerned the maintenance and optimization of the production at the Ekofisk field (Eni’s interest 12.39%) and start-up of the FSU at Heidrun field (Eni’s interest 5.2%) in the Norwegian Sea. In 2015, Eni was awarded two exploration licenses: (i) the operatorship and a 40% interest in the PL 806 license in the Barents Sea; and (ii) a 13.12% interest in the PL 044C license in the North Sea. Focus of the exploration activity in 2015 were the preparatory activities for an exploration drilling campaign planned for 2016. 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 and the Irish Sea. In 2015, Eni’s net production of oil&gas averaged 72 KBOE/d. Exploration and production activities in the United Kingdom are regulated by concession contracts. Eni currently holds interests in 5 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other fields are Elgin/Franklin (Eni’s interest 21.87%), J Block and Jasmine (Eni’s interest 33%), Jade (Eni’s interest 7%) and MacCulloch (Eni’s interest 40%), which in 2015 accounted for 59% of Eni’s production in the United Kingdom.

Eni started production of the Phase 2 at the West Franklin field (Eni’s interest 21.87%), following the completion of two productive wells.

Development activities concerned drilling activities for the completion of the development of Jasmine field (Eni’s interest 33%).

In 2015, Eni was awarded four exploration licenses in the Central North Sea, with interests ranging from 9.13% to 100%. In addition, Eni finalized the acquisition of three licenses in the Southern North Sea, with a 100% interest.

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North Africa Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2015, North Africa accounted for 38% of Eni’s total worldwide production of oil and natural gas. Algeria. Eni has been present in Algeria since 1981. In 2015, Eni’s oil&gas production averaged 89 KBOE/d. Operated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the country: (i) blocks 403a/d (Eni’s interest from 65% to 100%); (ii) block Rom North (Eni’s interest 35%); (iii) blocks 401a/402a (Eni’s interest 55%); (iv) 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 Production Sharing Agreements (PSAs) and concession contracts. Production in blocks 403a/d and Rom North comes mainly from the HBN and Rom and satellites fields and represented approximately 21% of Eni’s production in Algeria in 2015. In 2015, Eni signed with relevant authorities a five-year extension for the operated field Rom East (Eni’s interest 100%).

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 2015.

The main fields in block 403 are BRN, BRW and BRSW, which accounted for approximately 10% of Eni’s production in Algeria in 2015.

The main fields in block 404 are HBN and HBNS and satellites, which accounted for approximately 21% of Eni’s production in Algeria in 2015.

Production in block 405b comes mainly from MLE-CAFC project and accounted for approximately 16% of Eni’s production in the country. In 2015, development and optimization activities progressed at the MLE-CAFC production fields, by means of construction and infilling activities, as well as production optimization. The project includes an additional oil phase with a start-up expected in 2017, targeting a production plateau more than 30 KBOE/d net to Eni. The El-Merk field is the main production project in the block 208 and accounted for approximately 18% of Eni’s production in Algeria in 2015. Activities during the year concerned infilling wells and production optimization in all operated and participated blocks in the Country. Egypt. Eni has been present in Egypt since 1954. In 2015, Eni’s share of production in this country amounted to 177 KBOE/d and accounted for 10% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Melehia (Eni’s interest 76%) and the Ras Qattara (Eni’s interest 75%) concessions. Gas production mainly comes from the operated or participated concession of North Port

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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 2015, production from these large concessions accounted for approximately 92% of Eni’s production in Egypt.

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

In March 2015, Eni and the Egyptian Ministry of Petroleum and Mineral Resources signed a framework agreement, which comprises a plan to invest up to $5 billion (at 100%) in the development of the Country’s oil&gas reserves over the next few years. The agreement also includes a revision of certain Eni’s ongoing oil contracts, with the economic effects retroactive to January 1, 2015. The agreement also comprises the identification of new measures to reduce overdue amounts of trade receivables relating to hydrocarbons supplies to Egyptian State-owned companies. In November 2015, as foreseen by the agreements, Eni signed three amendments for the concessions of Sinai 12 (Eni’s interest 100%) and Abu Madi, North Port Said (Eni’s interest 100%) and Baltim (Eni operator with a 50% interest), for the realization of projects to be implemented in the next years. In addition, Eni signed a new Concession Agreement for the Ashrafi area (Eni’s interest 25%). Certain planned activities are currently in the execution phase and one additional well in Baltim concession has already been put into production.

In 2015, Concession Agreements were ratified for the following blocks: (i) the Southwest Melehia (Eni’s interest 100%) in the Western Desert; (ii) Karawan (Eni operator with a 50% interest) and North Leil (Eni’s interest 100%) in the deep offshore of Mediterranean Sea; and (iii) North El Hammad (Eni operator with 37.5% interest) and North Ras El Esh (Eni’s interest 50%) in the offshore Nile Delta, which is still expected to be ratified by the Country’s Authorities.

Exploration activities yielded positive results with the following discoveries: (i) the large Zohr gas discovery, in the operated Shorouk license (Eni’s interest 100%) located in the deep offshore of Mediterranean Sea. Based on ongoing studies management believes that this discovery contains a large amount of gas resources. In February 2016, the Egyptian Ministry of Petroleum and Mineral Resources has approved to award to Eni the Zohr Development Lease that allows the start-up of the development program at the Zohr gas field. The first gas is expected at the end of 2017. In addition, appraisal activity yielded positive results with the Zohr 2X well, the first delineation well. The delineation campaign provides the drilling of three additional wells; (ii) oil&gas discovery with the Melehia West Deep well in the Melehia concession (Eni’s interest 76%) located in the Western Desert; (iii) the Sidri-18 oil discovery in the Abu Rudeis concession (Eni’s interest 100%) in the Gulf of Suez; and (iv) an important gas discovery in the Nooros exploration prospect, located in the Abu Madi West license (Eni’s interest 75%) in the Nile Delta. The discovery was put into production in two months time through a tie-in to the existing Abu Madi gas treatment plant. In February 2016, new success exploration was achieved with the drilling of the Nidoco North 1X well. Production start-up is expected in the second quarter 2016 and will allow to achieve an overall production of 45 KBOE/d in the area.

Production activities during the year concerned mainly infilling wells in the Gulf of Suez and Western Desert areas and for gas in El Temsah and Baltim and other production optimization activities aimed to optimize reserve recovery. Libya. Eni started operations in Libya in 1959. In recent years, Eni’s production levels in Libya were negatively impacted by an internal revolution and a change of regime in 2011, which led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political development forced Eni to temporarily interrupt or reduce its producing activities, negatively affecting Eni’s results of operations and cash flow until the situation began to stabilize. Eni expects that those risks will continue to affect Eni’s operations in the country. Particularly, the uncertain socio-political outlook in Libya was factored in the Company’s projections of future production levels. In 2015, Eni’s facilities in Libya produced on average 358 KBOE/d, registering an increase of approximately 54% compared to 2014. 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

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field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).

In the exploration phase, Eni is operator 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 Agreement contracts (EPSA). The licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil&gas properties, respectively.

In January 2015, Eni and the State company NOC signed an agreement that ensures during the 2015-2018 four-year period the sale of the associated gas to the production of the Bu Attifel oilfield in the contractual area B.

Development activities in the contractual area D concerned: (i) the linkage and the start-up of three infilling wells, in addition to the activity of production optimization at the Wafa field; and (ii) the start-up of the second development phase of the Bahr Essalam field by means of the start-up of drilling campaign and the award of EPC contract for the construction of linkage subsea facility to the onshore treatment plans.

Exploration activities near-field yielded positive results in the contractual area D, with gas and condensates discoveries: (i) in the offshore Bahr Essalam South exploration prospect, nearby to the Bahr Essalam production field; and (ii) in the offshore Bouri North exploration prospect, nearby to the Bouri production field.

Morocco. In March 2016, Eni signed a Farm-Out Agreement (FOA) with Chariot Oil & Gas that includes the operatorship to Eni and a 40% stake enter into Rabat Deep Offshore exploration permits I-VI offshore Morocco. The completion of this FOA is subject to the authorization of the Moroccan Authorities, to current partners’ approval and other conditions precedent.

Tunisia. Eni has been present in Tunisia since 1961. In 2015, Eni’s production amounted to 11 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 2015, Sub-Saharan Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas. Angola. Eni has been present in Angola since 1980. In 2015, Eni’s production averaged 95 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore. The main Eni’s asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest) with the West Hub project, where production started up in 2014 and the East Hub development project is underway with start-up expected in 2017. Eni participates in other producing blocks: (i) Block 0 in Cabinda (Eni’s interest 9.8%) north

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of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; (iv) the Lianzi Development Area in the Block 14K/A IMI (Eni’s interest 10%), where a unitization was implemented with the Congo-Brazaville area; and (v) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin.

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

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

In 2015, Eni and the State company Sonangol signed certain agreements aimed at strengthening strategic and operational partnership, which include: (i) the commitment to upgrade the current development plans for the Lobito refinery, owned by the Angolan national company, with Eni’s expertise and know-how in the downstream sector including the potential synergies deriving from existing refineries; and (ii) the commitment to progress the ongoing evaluation of the gas resources in the Lower Congo Basin. In addition, Eni and Sonangol agreed a revision of certain contractual terms to support investments in the Block 15/06, where in January 2015, Eni obtained a three-year extension of the exploration period.

The development program of the West Hub project plans to hook up the Block’s discoveries to the N’Goma FPSO in order to support production plateau. In April 2015, production start-up was achieved at the Cinguvu field, following the first oil of the Sangos field, and in January 2016, Eni started production from the M’Pungi field, with an overall production of approximately 25 KBBL/d net to Eni.

In addition, Eni started production at: (i) the Kizomba satellites Phase 2 project (Eni’s interest 20%), in the deep offshore of the Country, by means of the start-up of further three fields connected to the existing FPSO. The peak production is estimated at approximately 80 KBBL/d; (ii) the Lianzi project (Eni’s interest 10%), with the start-up of the first two wells which yielded approximately 25 KBBL/d by the end of the year. The start-up of an additional well in 2016 will allow to reach a production peak of approximately 35 KBBL/d; and (iii) the Gazela field (Eni’s interest 12%), with a production of approximately 3 KBBL/d. Other development activities concerned the Mafumeira project (Eni’s interest 9.8%) with production start-up expected at the end of 2016. In the medium term, management expects to increase Eni’s production to above 140 KBOE/d reflecting additions from ongoing development projects. Congo. Eni has been present in Congo since 1968. In 2015, production averaged 97 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.

Other relevant not operated 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.

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Eni achieved production start-up of the Litchendjili field in the Marine XII block (Eni operator with a 65% interest) by means of the installation of a production platform, the construction of transport facilities and onshore treatment plant. Peak production is estimated at 14 KBOE/d net to Eni and is expected in 2016.

Development activities progressed at the Nené Marine production field started up in 2014, located in the Marine XII block, with the completion and start-up of the two additional productive wells. In 2015, the final investment decision for the Phase 2 of Nené Marine was sanctioned and start-up is expected in the second half of 2016.

Exploration activities yielded positive results in the Marine XII block with: (i) the Minsala N1 appraisal well, confirming the mineral potential of the Minsala discovery; and (ii) the Nkala Marine discovery.

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

Ghana. Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni’s interest 47.22%) permits which is regulated by a concession agreement. The license expires in 2036.

In 2015, Eni defined and signed a Gas Sale Agreement with the Ghana Authorities, as well as other agreements related to the guarantees for the sale of natural gas from the operated OCTP project, sanctioned and approved by the Ministry of Petroleum in December 2014. The integrated oil&gas development plan provides to put into production the Sankofa, Sankofa East and Gye Nyame discoveries. The first oil is expected in 2017 and the first gas in 2018. Peak production is estimated at 40 KBOE/d net to Eni in 2019.

In the year development activities concerned: (i) main contracts awarded for the realization of FPSO and offshore facilities; and (ii) the start-up of the development activities with the drilling of 5 development wells.

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

Mozambique. Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 block (Eni operator with a 50% interest) located in the offshore Rovuma Basin. In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by Anadarko. In 2012, Eni made the Coral gas discovery which falls entirely in Area 4.

During the exploration period which has expired in 2015, six Discovery Areas (DA) have been identified. Multiple plans of development can be submitted in respect of each DA, which upon approval will give right to identify a Development and Production Area for a term of 30 years, further extendable.

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

In November 2015, according to a Decree Law approved in December 2014, which defines the Rovuma Basin fiscal regime and the terms for the onshore liquefaction projects, all the concessionaries of Area 4 and Area 1 signed the Utilization and Unit Operating Agreement (UUOA). The agreement concerns the development of the Mamba and Prosperidade natural gas straddling reservoirs. In addition, the two operators jointly submitted to the Authorities the request for the allocation of the areas designated to the construction of the onshore liquefaction facilities. The development plan of the first phase of the Mamba project includes construction of two onshore LNG trains with a combined capacity of 10 mmtonnes/y and the drilling of 16 subsea wells, with start-up in 2022. Eni expects to produce up to 12 TCF of gas according to its independent industrial plan, coordinated with the operator of Area 1. The FID is expected in 2017.

In February 2016, the local Authorities approved the first stage of the development plan of the Coral discovery. The project plans to put into production 5 TCF of gas and includes the construction of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG - FLNG) with a capacity of 3.4 mmtonnes/y fed by 6 subsea wells. Start-up is expected in 2021. The EPCIC contracts award recommendation for the construction, installation and commissioning of the FLNG and supply of subsea equipment and drilling rig have been issued. Furthermore, the long-term LNG sale contract have been finalized. The FID is expected in 2016, after approval of all contracts and commercial agreements by Mozambique Authorities and JV partners.

In October 2015, Eni was awarded the operatorship of the exploration offshore Block A-5A (Eni’s interest 34%). The block is located in the deep offshore of Zambesi covering an area of approximately 5,000 square kilometers.

Nigeria. Eni has been present in Nigeria since 1962. In 2015, Eni’s oil&gas production averaged 132 KBOE/d located mainly onshore and offshore the Niger Delta.

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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 19 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks.

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

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

Eni completed activities and achieved production start-ups at: (i) the Bonga NW project, by means of the linkage of additional productive and infilling wells to the existing FPSO; and (ii) the Abo project Phase 3, by means of the linkage of two additional production wells to the existing production facilities in the area.

Development activities concerned: (i) the OML 28 block (Eni’s interest 5%), where the drilling campaign progressed within the integrated project in the Gbara-Ubie area, aimed to supply natural gas to the Bonny liquefaction plant with start-up expected in 2016; and (ii) the OML 43 block (Eni’s interest 5%), where the development plan of the Forkados-Yokri field provides the drilling of 24 producing wells, the upgrading of existing flowstations and the construction of transport facilities. Start-up is expected in 2016.

Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant is operational, with a treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. 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 currently provided under gas supply agreements with an expiring date in eighteen years from the SPDC JV and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an average amount of approximately 2,825 mmCF/d for the next four years (approximately 268 mmCF/d net to Eni corresponding to approximately 48 KBOE/d). LNG production is sold

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under long-term contracts and exported to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co. During 2015, six new vessels were launched.

In the medium term, management expects to increase Eni’s production in Nigeria to approximately 140 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 2015, Eni’s operations in Kazakhstan accounted for 5% of its total worldwide production of oil and natural gas.

In June 2015, Eni and KazMunayGas (KMG) signed an agreement on the transfer to Eni of the 50% stake for exploration and production activities in the Isatay block located in the Kazakh sector of the Caspian Sea. The transfer is expected to be finalized after all necessary approvals required by law. The Isatay block is estimated to have significant potential oil resources and will be operated by a joint operating company established by KMG and Eni on a 50/50 basis. In addition, after the finalization of the FEED, the activities related to the contracts’ award for the construction of a shipyard in Kuryk started, as provided by the agreements signed in 2014.

Kashagan. Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources which will eventually be developed in phases. The NCSPSA expires at the end of 2041.

In addition to Eni, the partners of the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, CNPC with 8.33%, and Inpex with 7.56%.

On June 13, 2015, the Consortium completed the process of setting up a new operating model which had started in October 2014, when Eni transferred its 100% interest in Agip Kazakhstan North Caspian Operating Co NV (AKCO) to the operator North Caspian Operating Co BV (NCOC BV), and AKCO was redenominated North Caspian Operating Co NV (NCOC NV). Subsequent merge transactions with NCOC BV and other agents of NCOC BV were completed in June 2015 resulting in the current operating model which provides that the company NCOC NV, participated by the seven partners of the Consortium, acts as the sole operator of all exploration, development and production activities at the Kashagan field. The objective of the restructuring is to execute the development of the project targeting streamlined decision-making process, increased efficiency in operations and lower costs.

In December 2015, the Authority of the Republic of Kazakhstan approved the Amendment 5 to the development plan and budget for the Phase 1 of the Kashagan project (the so-called "Experimental Program") which defines the update to the project schedule and budget and the activities for the replacement of the damaged pipelines, which forced the Consortium to shut down the production at the Kashagan field soon after the start-up in September 2013.

During the year activities progressed to replace the damaged pipelines and the Consortium expects to complete the installation works in the second half of 2016 with production re-start by the end of 2016. The production capacity of 370 KBBL/d planned for the Phase 1 is expected to be achieved during 2017.

The Phase 1 includes a further increase available production capacity up to 450 KBBL/d by installing additional gas compression capacity for reinjection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities.

Management believes that significant capital expenditures will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and subsequent to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures. In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets.

As of December 31, 2015, Eni’s proved reserves booked for the Kashagan field amounted to 611 mmBOE, recording an increase of 31 mmBBL compared to 2014 mainly due to lower marker Brent price. The major part of these reserves are classified proved undeveloped. See the discussion in "Proved Undeveloped Reserves" section.

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

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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, 2015, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.2 billion (euro 8.4 billion at the EUR/USD exchange rate of December 31, 2015). This capitalized amount included: (i) $6.8 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.4 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years.

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.

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. Eni’s interest in the Karachaganak project is 29.25%. In 2015, production of the Karachaganak field averaged 239 KBBL/d of liquids (56 net to Eni) and 858 mmCF/d of natural gas (199 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 48%) 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 93% 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. In June 2015, the Gas Sales Agreement for the Karachaganak field was extended until 2038. The agreement provides the supply of currently produced gas volumes to the Orenburg treatment plant, including additional new development projects to support the current liquids and gas production.

The Expansion Project is currently under study. The project targets to install, in stages, the gas treatment plants and re-injection facilities to support liquids’ production profile. The development plan is currently in the phase of technical and marketing definition of its first development phase, aimed to increase the capacity of gas re-injection.

As of December 31, 2015, Eni’s proved reserves booked for the Karachaganak field amounted to 587 mmBOE, reporting an increase of 98 mmBOE from 2014 mainly due to lower marker Brent price.

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

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

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Rest of Asia

In 2015, Eni’s operations in the rest of Asia accounted for 8% 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 2015, Eni’s production amounted to 3 KBOE/d.

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

In 2015, hydrocarbons were produced from the offshore Blocks 16/19 through 3 platforms connected to an FPSO.

Indonesia. Eni has been present in Indonesia since 2001. In 2015, Eni’s production mainly composed of gas, amounted to 14 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 14 blocks.

Exploration and production activities in Indonesia are regulated by PSAs.

The ongoing development activities that will ensure gas supplies to the Bontang liquefaction plant include: (i) the Jangkrik project (Eni operator with a 55% interest) in the Kalimantan offshore. This project provides for the drilling of production wells linked to a Floating Production Unit for gas and condensate treatment, as well as the construction of transportation facilities. 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.

In June 2015, Eni and its partners of the Jangkrik project signed two agreements with PT Pertamina for the purchase and sale of 1.4 mmtonnes/y of LNG coming from Jangkrik field development project, starting from 2017.

Exploration activities yielded positive results with appraisal activities at the Merakes gas discovery in the deep offshore of the East Sepinngan block (Eni operator with an 85% interest).

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. In 2015, Eni’s contractual reimbursements were equivalent to a production of 22 KBBL/d, approximately 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 "Disclosure pursuant to Section 13(r) of the Exchange Act".

Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companies and the national oil company Missan Oil, holds a 41.6% interests in the Zubair oil field.

Development and production activities at the Zubair field are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to Production Sharing contracts.

In 2015, production of the Zubair field averaged 40 KBBL/d net to Eni.

The first stage of development activities (Rehabilitation Plan) of Zubair field were substantially completed. At the beginning of March 2016, three new generation plants for the oil, gas and water treatment (Initial Production Facilities - IPF) started. Those plants together with existing restructured and modernized facilities increased oil and natural gas treatment capacity of Zubair field to approximately 650 KBBL/d and will ensure the maximization of the associated gas utilization. In addition, these new facilities have also a water re-injection capacity of approximately 300 KBBL/d that will boost the Zubair’s hydrocarbons production.

The Zubair project includes an additional development phase (Enhanced Redevelopment Plan), started in 2014, to achieve a production plateau of 850 KBBL/d.

In September 2015, Occidental of Iraq Llc, a partner of Eni BV Iraq in Zubair project, announced to exit the Zubair project, and in December 2015, SOC, the Iraqi state oil company, expressed its decision to take the place of the Occidental of Iraq Llc as a part of the project. Negotiations are underway between the parties involved.

Myanmar. In March 2015, Eni signed two Production Sharing Contracts for offshore blocks MD-02 and MD-04 (Eni operator with an 80% interest in both leases). The contracts foresee a study period of two years, followed by an exploration period of six years, subdivided in 3 phases.

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Pakistan. Eni has been present in Pakistan since 2000. In 2015, Eni’s production mainly composed of gas amounted to 39 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 2015 accounted for 75% of Eni’s production in Pakistan.

Production optimization through infilling activities represents the main activity currently performed in the above listed fields to mitigate the natural field production decline.

Exploration activities yielded positive results with the Latif South 1 discovery well.

Russia. Eni has been present in Russia through three joint ventures with Rosneft for the development of Fedynsky and Central Barents licenses (Eni’s interest 33.33%) located in the Russian Barents Sea and Western Chernomorsky license (Eni’s interest 33.33%) in the Black Sea since 2013.

The activity was temporary and partially suspended after the restrictive EU and U.S. sanctions targeting the Russia-Ukraine crisis that were issued in summer 2014.

Following the adoption of these measures, Eni started the required authorization before competent Authorities of the Member States of the European Union who granted the Company certain authorization for the execution of exploration activities in Russia under the terms of pre-existing contracts.

In 2015, Eni has restarted the exploration activity in line with the existing restrictive measures. 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 2015, Eni’s production averaged 10 KBOE/d.

Exploration and production activities in Turkmenistan are regulated by PSAs.

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

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

Americas

In 2015, Eni’s operations in Americas area accounted for 9% 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 2015, Eni’s production averaged 11 KBBL/d.

Exploration and production activities in Ecuador are regulated by a service contract that expires in 2033, following a ten-year extension signed in December 2015.

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

Mexico. In December 2015, Eni signed the Production Sharing Contract as operator of the Block 1 (Eni’s interest 100%) to develop the Amoca, Miztón and Tecoalli fields, located in the Gulf of Mexico shallow waters. The delineation campaign of the fields was submitted to the Mexican Authorities in the first quarter of 2016 and plans the drilling of four wells in order to define a fast track and synergic development plan.

Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2015, Eni’s production averaged 70 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block, located offshore North of Trinidad.

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

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

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

In 2015, Eni’s oil&gas production was 96 KBOE/d mainly from the Gulf of Mexico and Alaska fields.

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

Eni holds interests in 128 exploration and production blocks in the Gulf of Mexico, of which 73 are operated by Eni. The main operated fields are Allegheny and Appaloosa (Eni’s interest 100%), Pegasus (Eni’s interest 85%), Longhorn, Devils Towers and Triton (Eni’s interest 75%). Eni also holds interests in Europa (Eni’s interest 32%), Medusa (Eni’s interest 25%), Thunder Hawk (Eni’s interest 25%) and Frontrunner (Eni’s interest 37.5%) fields. As part of Eni’s portfolio rationalization process, the sale of certain minor assets in the Gulf of Mexico was finalized. During the year, production start-ups were achieved in the Gulf of Mexico at: (i) the Hadrian South field (Eni’s interest 30%), with an estimated daily production of approximately 300 mmCF of gas and 2,250 BOE (about 16 KBOE/d net to Eni); and (ii) the Lucius field (Eni’s interest 8.5%), with an estimated production of approximately 7 KBOE/d net to Eni. At the beginning of 2016 production start-up was achieved at the Heidelberg project (Eni’s interest 12.5%) in the deepwater Gulf of Mexico. Production plateau is expected to reach approximately 9 KBOE/d net to Eni. Planned development activities progressed. Other development activities concerned the drilling activities at the operated Devil’s Tower field as well as at non-operated fields Medusa, K2 (Eni’s interest 13.39%) and St. Malo (Eni’s interest 1.25%).

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 61 exploration and development blocks in Alaska, with interests ranging from 30 to 100%; Eni is the operator in 40 of these blocks.

Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) fields with a 2015 overall net production of approximately 25 KBBL/d.

Drilling activities progressed at the Nikaitchuq and Oooguruk fields.

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

Exploration activities yielded positive results with the Puckett Trust 1H well, within the agreement signed with Quicksilver Resources for joint evaluation, exploration and development of unconventional oil reservoirs (shale oil) in the southern part of the Delaware Basin, in West Texas. The discovery has already been connected to the existing production facilities.

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Venezuela. Eni has been present in Venezuela since 1998. In 2015, Eni’s production averaged 24 KBOE/d.

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

Exploration and production of oil fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP).

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.

In addition, in July 2015, production started at the gas giant Perla field, located in the Cardon IV block (Eni’s interest 50%) in the Gulf of Venezuela. The gas will be mainly used by PDVSA for the domestic market, under the Gas Sales Agreement running until 2036. The development of Perla has been planned in three phases with 21 wells and the installation of four offshore platforms linked via sealine to an onshore treatment plant. The production level at the year-end was approximately 500 mmCF/d at 100%. The second phase will ensure production ramp-up at approximately 800 mmCF/d. The development plan targets a long-term production plateau of approximately 1,200 mmCF/d through a third phase of development.

Drilling activities progressed at the giant Junin 5 oilfield. Possible optimization of development program is currently under evaluation.

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

Australia and Oceania

Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2015, the area of Australia and Oceania accounted for 1% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2001. In 2015, 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 100%) and NT/RL7 (Eni’s interest 32.5%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA.

In JPDA 03-13, the phase 3 of the Bayu Undan field was completed in order to increase liquids production and to sustain LNG production.

 

Capital expenditures

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

 

Transparency on payments made to Governments for the purpose of the commercial development of hydrocarbons

In the matter of transparency of payments made to Governments in the extraction of hydrocarbons, Eni has been working to voluntarily achieve a higher degree of disclosure on payments, alongside the Company’s continued support to the Extractive Industries Transparency Initiative (EITI), anticipating the reporting obligations on payments transparency established by EU Directive No. 2013/34 which the Italian legislator has enacted with Legislative Decree No. 139 of August 18, 2015 effective for payments made on or after January 1, 2016 to be reported in 2017. Therefore information provided below has been furnished on voluntary basis and does not constitute compliance with any reporting obligations. In particular, as Eni believes that the active involvement of governments is key to a sustainable use of revenues, the Company has reached out to all its counterparts in upstream contracts in order to share the Company’s commitment on transparency and request their consent on disclosing taxes, royalties and the other forms of payment foreseen by the EITI Standard and the EU Directives.

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Therefore, Eni voluntarily discloses payments (“on a cash basis”) to governments (including to local authorities and other governmental authorities) for the year 2015. Payments refer to those countries whose governments/local authorities/governmental counterparts provided consent to this disclosure. Data in the following table correspond to the Company’s accounting records and include data for the parent company and consolidated subsidiaries. Payments to governments referring to petroleum activities operated by Eni are disclosed on a 100% basis, when Eni paid on behalf of the Joint Venture partners. Payments made by Joint Venture partners on behalf of Eni in those activities where Eni is not the operator are not reported. We believe that those payment categories are in line with EITI Standard and EU Directives’ payment categories. The following disclosure represents approximately 75% of Eni’s 2015 production (80% when including the two countries adhering to EITI listed below).

(euro thousands)

Year

Host government’s entitlement

National Oil Companies entitlement

Profit taxes

Royalties

Bonus

Fees

Other significant payments and benefits

Capital expenditure (*)

Revenues from sales of equity hydrocarbons (*)

Angola		2015				46,335		193,814			80,202				33		1,447			1,354,317		1,585,505
Australia		2015						4,390							520					14,620		91,657
China		2015						1,484							136					11,248		62,060
Croatia		2015						4,607												2,597		36,958
Cyprus		2015															600			112,189
Denmark		2015
Ecuador		2015						41,106	(a)								8,757			21,960		124,851
Gabon		2015													21		1,416			80,089
Ghana		2015													1,388					203,428
Indonesia		2015						27,669					39							732,705		165,603
Iraq		2015						15,843									11,647			481,312		576,265
Ireland		2015																		2,057
Italy		2015									301,871				2,202		1,868			726,832		2,123,516
Kenya		2015													161					3,825
Libya		2015				1,554,740		1,983,759			222,621						45,065			444,061		3,840,949
Myanmar		2015													901					5,529
Nigeria		2015				11,277		163,789			168,537				9,681		28,664			451,078		1,559,178
Norway		2015						41,411							8,565					1,115,747		1,383,956
Pakistan		2015						27,122			30,584				724					55,443		279,963
Portugal		2015													523		160			3,589
Republic of Congo		2015		40,098		9,433		173,989			162,855				3,780					888,754		1,284,200
Russia		2015						1,439												55
The Netherlands		2015						275
The United Kingdom		2015						126,713							926					200,746		907,974
Timor Leste		2015		47,965				21,735			1,693				509					16,909		163,479
Ukraine		2015						98												13
United States		2015						9,401			40,290				4,126					660,009		1,092,182
Vietnam		2015											451				563			16,080
EITI data (**)
Kazakhstan		2014						343,922									(94,344	) (b)
Mozambique		2013-2014						53,280	(c)								301,132	)(d)

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(*)		Accrual basis.
(**)		The reported data refer to the last EITI disclosure issued in relation to EITI countries.
(a)		The data include the payment of $33,136 thousand for previous years taxes subject to tax dispute.
(b)		Mainly refers to VAT reimbursement of 23,226,728 thousands of tenge relating to Agip Caspian Sea BV Branch.
(c)		Including taxes on employees and withholding taxes on suppliers.
(d)		Payment of $400,000 thousand to fiscal Authority of Mozambique relating to taxes on the disposal of 28.57% shares of Eni East Africa SpA.

 

Royalties paid in Italy in the 2013-2015 period		2013		2014		2015

(euro thousands)

Royalties paid (a)		298,383		327,187		301,871
- of which to State		138,302		149,454		126,172
- of which to Regions		125,596		130,611		122,684
- of which to Basilicata		91,862		94,925		86,652
- of which to municipalities		34,486		47,123		53,015

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(a)

The data include Eni SpA (Exploration & Production), EniMed, Società Adriatica Idrocarburi and Società Ionica Gas.

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

The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. In 2015, Eni’s production in Iran averaged 22 KBBL/d, approximately 1% of Eni Group’s total production for the year, in connection with the recognition of its past investment during the

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year mainly pertaining to the Darquain project. As of December 31, 2015, Eni had outstanding trade receivables amounting to $339 million towards National Iranian National Oil Co (NIOC) which were recorded in connection with revenues recognized of during the year for $263 million. Eni had no payables towards NIOC as of December 31, 2015. Eni made payments in the region of $1 million to the Iranian Social Security Organization in connection to health and social security insurance for which Eni retains at the balance sheet date a residual payable amounting to $11 million date which will be settled upon termination of our presence in the country.

 

 

Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply and marketing. This segment also includes the activities of electricity generation. In 2015, Eni’s worldwide sales of natural gas amounted to 90.88 BCM, including 3.16 BCM of gas sales made directly by Eni’s Exploration & Production segment. Sales in Italy amounted to 38.44 BCM, while sales in European markets were 42.89 BCM that included 4.61 BCM of gas sold to certain importers to Italy.

 

Supply of natural gas

In 2015, Eni’s consolidated subsidiaries supplied 85.39 BCM of natural gas, up by 2.48 BCM, or 3% from 2014. Gas volumes supplied outside Italy (78.66 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 92% of total supplies, up by 2.67 BCM, or 3.5% compared to the previous year, due to higher volumes purchased in Russia (up 3.65 BCM) and Libya (up 0.59 BCM), partly offset by lower volumes purchased in the Netherlands (down 1.73 BCM), Algeria (down 1.46 BCM) and the United Kingdom (down 0.29 BCM). Supplies in Italy (6.73 BCM) registered a slight decrease from 2014 (down 0.19 BCM) due to mature fields’ decline. In 2015, main gas volumes from equity production derived from: (i) Italian gas fields (5.2 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.2 BCM); (iii) Libyan fields (2.2 BCM); (iv) the United States (1.4 BCM); and (v) other European areas (Croatia with 0.2 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 17 BCM representing 19% 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		2013		2014		2015

(BCM)

Italy		7.15			6.92			6.73
Outside Italy		78.52			75.99			78.66
Russia		29.59			26.68			30.33
Algeria (including LNG)		9.31			7.51			6.05
Libya		5.78			6.66			7.25
the Netherlands		13.06			13.46			11.73
Norway		9.16			8.43			8.40
the United Kingdom		3.04			2.64			2.35
Hungary		0.48			0.38			0.21
Qatar (LNG)		2.89			2.98			3.11
Other supplies of natural gas		3.63			5.56			7.21
Other supplies of LNG		1.58			1.69			2.02
Total supplies of subsidiaries		85.67			82.91			85.39
Withdrawals from (input to) storage		(0.58	)		(0.20	)
Network losses, measurement differences and other changes		(0.31	)		(0.25	)		(0.34	)
Volumes available for sale of Eni’s subsidiaries		84.78			82.46			85.05
Volumes available for sale of Eni’s affiliates		5.78			3.65			2.67
E&P volumes		2.61			3.06			3.16
Total volumes available for sale		93.17			89.17			90.88

 

Sales of natural gas

In 2015, natural gas sales amounted to 90.88 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 an increase of 1.71

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BCM, or 1.9% from the previous year. Sales in Italy increased to 38.44 BCM, up by 12.9% due to higher spot volumes and more severe weather conditions compared to 2014. These effects were partially offset by a lower volumes marketed to the thermoelectric segment due to the competition from other energy sources (in particular, from renewables), a contraction in electricity demand registered in particular in the first part of the year as well as lower sales to the industrial segment due to increasing competitive pressure. Sales in European markets were 38.28 BCM, down by 9.3% from last year. This can be attributable to lower spot sales in Benelux and in Germany/Austria due to competitive pressure and due to divestment of GVS joint venture occurred in 2014, as well as the United Kingdom due to competitive pressure, partially offset by higher sales in Turkey reflecting higher sales to Botas. Direct sales of Exploration & Production in Northern Europe and the United State (3.16 BCM) increased by 0.10 BCM due to higher volumes marketed in the North Sea. Sales to long-term buyers were up by 15% compared to the previous year, due to larger availability of Libyan output and higher sales to Extra European markets (up 9.2%) driven by higher spot sales in the United States.

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

Natural gas sales by entities		2013		2014		2015

(BCM)

Total sales of subsidiaries		83.60		81.73		84.94
Italy (including own consumption)		35.76		34.04		38.44
Rest of Europe		42.30		43.07		41.14
Outside Europe		5.54		4.62		5.36
Total sales of Eni’s affiliates (Eni’s share)		6.96		4.38		2.78
Italy		0.10
Rest of Europe		5.05		3.15		1.75
Outside Europe		1.81		1.23		1.03
Total sales of G&P		90.56		86.11		87.72
E&P in Europe and in the Gulf of Mexico (a)		2.61		3.06		3.16
Worldwide gas sales		93.17		89.17		90.88

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(a)

E&P sales include volumes marketed by the Exploration & Production division in Europe (2.08, 2.60 and 2.75 BCM in 2013, 2014 and 2015, respectively) and in the Gulf of Mexico (0.53, 0.46 and 0.41 BCM in 2013, 2014 and 2015, respectively).

 

Natural gas sales by market		2013		2014		2015

(BCM)

ITALY		35.86		34.04		38.44
Wholesalers		4.58		4.05		4.19
Italian gas exchange and spot markets		10.68		11.96		16.35
Industries		6.07		4.93		4.66
Medium-sized enterprises and services		1.12		1.60		1.58
Power generation		2.11		1.42		0.88
Residential		5.37		4.46		4.90
Own consumption		5.93		5.62		5.88
INTERNATIONAL SALES		57.31		55.13		52.44
Rest of Europe		47.35		46.22		42.89
Importers in Italy		4.67		4.01		4.61
European markets		42.68		42.21		38.28
Iberian Peninsula		4.90		5.31		5.40
Germany/Austria		8.31		7.44		5.82
Benelux		8.68		10.36		7.94
Hungary		1.84		1.55		1.58
United Kingdom/Northern Europe		3.51		2.94		1.96
Turkey		6.73		7.12		7.76
France		7.73		7.05		7.11
Other		0.98		0.44		0.71
Extra European markets		7.35		5.85		6.39
E&P in Europe and in the Gulf of Mexico		2.61		3.06		3.16
WORLDWIDE GAS SALES		93.17		89.17		90.88

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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, by the Belgium Gas & Power branch and by its subsidiaries, in the retail and middle market and its significant exposure to spot markets in Western Europe. In 2015, sales in Benelux were mainly directed to industrial companies, power generation and wholesalers and amounted to 7.94 BCM (10.36 BCM in 2014), down by 2.42 BCM, or 23.4%, due to lower spot sales.

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 subsidiaries. In 2015, sales in France amounted to 7.11 BCM (7.05 BCM in 2014), a decrease of 0.06 BCM, or 0.9%, 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, regasification 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 2015, 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 2015.

LNG sales		2013		2014		2015

(BCM)

G&P sales		8.4		8.9		9.0
Rest of Europe		4.6		5.0		4.8
Extra European markets		3.8		3.9		4.2
E&P sales		4.0		4.4		4.5
Liquefaction plants:
- Soyo (Angola)		0.1		0.1
- Bontang (Indonesia)		0.5		0.5		0.5
- Point Fortin (Trinidad & Tobago)		0.6		0.6		0.7
- Bonny (Nigeria)		2.4		2.8		2.8
- Darwin (Australia)		0.4		0.4		0.5
		12.4		13.3		13.5

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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 2015, power sales (34.88 TWh) were directed to the free market (74%), the Italian Power Exchange (15%), industrial sites (9%) and others (2%). Compared with 2014, electricity sales were up by 3.9%, due to higher sales to wholesalers and residential segment, partially offset by lower volumes traded to small and medium-sized enterprises and to large clients.

Power availability		2013		2014		2015

(TWh)

Power generation sold		21.38		19.55		20.69
Trading of electricity (a)		13.67		14.03		14.19
		35.05		33.58		34.88
Power sales by market
Free market (a)		28.73		24.86		25.90
Italian Exchange for electricity		1.96		4.71		5.09
Industrial plants		3.31		3.17		3.23
Other (a)		1.05		0.84		0.66
		35.05		33.58		34.88

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(a)

Include positive and negative imbalances (differences between power introduced in the grid and the one planned).

 

Power generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Mantova, Brindisi, Ferrara and Bolgiano. In 2015, power generation was 20.69 TWh, up by 1.14 TWh, or 5.8% from 2014, mainly due to higher production at Ferrara Erbognone, Ravenna and Brindisi plants following increasing demand. As of December 31, 2015, installed operational capacity was 4.9 GW (4.9 GW as of December 31, 2014). Electricity trading reported a slight increase to 14.19 TWh (up 1.1%), due to higher purchases on the spot market reflecting mainly higher spot sales.

Site		Total installed capacity in 2015 (GW)		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 (a)		0.4		CCGT		gas
Bolgiano		0.1		Power station		gas
		4.9

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(a)

Eni’s share of capacity.

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Power generation		2013		2014		2015

Purchases
Natural gas		(mmCM)		4,295		4,074		4,270
Other fuels		(ktoe)		449		338		313
- of which steam cracking				99		104		87
Production
Electricity		(TWh)		21.38		19.55		20.69
Steam		(ktonnes)		9,907		9,010		9,318
Installed generation capacity		(GW)		4.8		4.9		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

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(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.

 

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.

 

Capital expenditures

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

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Refining & Marketing

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

For the next four years, the Company priority in its Refining & Marketing business is to strengthen profitability and cash generation in a depressed downstream oil environment. Refining margins in 2016 and in the following years are expected to remain under pressure. We believe that the European refining industry will continue to suffer from structural weakness as a consequence of surplus capacity and rising competition from new refineries in the Middle East.

Since 2012, Eni has reduced its exposure to refining capacity by one third through the shut down of Venice and Gela, the sale of its stake in Ceská Rafinérská and the closure of a production line in Taranto. Venice has been converted into a green refinery, the first example of such transformation in the world; Gela will also be converted into a green refinery, and the project is ongoing.

Looking forward, management plans to improve the resilience to scenario in refining leveraging on:
•		optimizations in existing plants, exploiting the capabilities of EST technology in Sannazzaro to fully convert the barrel into light products, increasing specialties production and higher flexibility in crude oil slate;
•		ramp-up of Venice green refinery and start-up of a new green refinery in Gela; and
•		efficiency, mainly through energy savings, logistics rationalizations and fixed cost reductions.
In Marketing, where we expect competitive pressure to continue due to weak demand, we are planning to achieve a gradual improvement in results of operations mainly focusing on:
•		innovation of products ("Eni green diesel+" was launched in January 2016) and services (contactless and mobile payment), anticipating customer needs;
•		dynamic pricing, tailored on the specific local market conditions; and
•		efficiency in marketing and distribution activities.

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 2015, a total of 24.80 mmtonnes of crude were purchased (compared with 23.02 mmtonnes in 2014), of which 5 mmtonnes equity crude oil. The breakdown by geographic area was the following: approximately 47% of purchased crude came from ex USSR, 20% from the Middle East, 16% from Italy, 12% from North Africa, 2% from West Africa, 1% from North Sea and 2% from other areas.

 

Refining

In 2015, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 KBBL/d), with a conversion index of 49%. 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 versus the benchmark. Eni’s 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 KBBL/d), with a 48% conversion index. In 2015, Eni’s refineries throughputs in Italy and outside Italy were 26.41 mmtonnes.

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Refining system in 2015

Ownership

Balanced refining capacity (Eni’s share)

Utilization rate (Eni’s share)

Conversion index (1)

Fluid catalytic cracking (FCC) (2)

Residue conversion (2)

Hydro-cracking (2)

Visbreaking/ Thermal Cracking (2)

(%)

(KBBL/d)

(%)

(%)

(KBBL/d)

(KBBL/d)

(KBBL/d)

(KBBL/d)

Wholly owned refineries				388		95		48		34		14		90		29
Italy
Sannazzaro		100		200		95		70		34		14		51		29
Taranto		100		104		86		38						39
Livorno		100		84		105		11
Partially owned refineries				160		96		52		143		25		75		27
Italy
Milazzo		50		100		95		60		45		25		32
Germany
Vohburg/Neustadt (Bayernoil)		20		41		96		36		49				43
Schwedt (PCK)		8.33		19		104		42		49						27
Total				548		95		49		177		39		165		56

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(1)		Conversion index: catalytic cracking equivalent capacity/topping capacity (% weight).
(2)		Conversion unit capacities are 100%.

 

Italy

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

Sannazzaro refinery has a balanced capacity of 200 KBBL/d and a conversion index of 70%. Located in the Po Valley, in the center of the North Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.

Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 37.6%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni 70%) through a pipeline. The main equipments are a topping-vacuum unit, an hydrocracking, a platforming and two desulphurization units.

Livorno refinery, with a balanced refining capacity of 84 KBBL/d and a conversion index of 11.4%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a topping-vacuum unit, a platforming, two desulphurization units and a dearomatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and dewaxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.

 

Outside Italy

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

In the second quarter of 2015, Eni divested its interest of 32.445% in the Ceská Rafinérská (CRC) and the marketing activities of fuels in Czech Republic, Slovakia and Romania, maintaining the marketing of lubricants those countries.

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Green refineries

		Ownership share		Capacity (2015)		Capacity (at regime)		Throughput (2015)
Wholly owned		(%)		(ktonnes/y)		(ktonnes/y)		(ktonnes/y)

Venezia		100		350		560		204
Gela		100				750
Total green refineries				350		1,310		204

 

Green Refining

Eni fully owns the green refinery of Venice and the site of Gela, where another green refinery will be realized.

Venice green refinery entered into production in June 2014, with a production capacity of 350 ktonnes/y. The refinery exploits the proprietary Ecofining^TM technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At regime, the production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing the CO₂ emission.

Gela refinery is located on the Southern coast of Sicily. The refinery was shut-down in March 2014 and in November 2014, Eni defined with the Ministry for Economic Development, the Region of Sicily and interested stakeholders a plan for, among other, the reconversion into a bio-refinery. The front end engineering design is ongoing. The local crude oil production is exported via the facilities of the refinery. A Safety Competence Center (SCC), a center of excellence in the security field, has been created on site. Environmental remediation activities will be also carried out.

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

Availability of refined products		2013		2014		2015

(mmtonnes)

ITALY
Refinery throughputs
At wholly-owned refineries		18.99			16.24			18.37
Less input on account of third parties		(0.57	)		(0.58	)		(0.38	)
At affiliated refineries		4.14			4.26			4.73
Refinery throughputs on own account		22.56			19.92			22.72
Consumption and losses		(1.23	)		(1.33	)		(1.52	)
Products available for sale		21.33			18.59			21.20
Purchases of refined products and change in inventories		5.73			7.19			6.22
Products transferred to operations outside Italy		(0.83	)		(0.73	)		(0.48	)
Consumption for power generation		(0.55	)		(0.57	)		(0.41	)
Sales of products		25.68			24.48			26.53
OUTSIDE ITALY
Refinery throughputs on own account		4.82			5.11			3.69
Consumption and losses		(0.22	)		(0.21	)		(0.23	)
Products available for sale		4.60			4.90			3.46
Purchases of finished products and change in inventories		4.30			4.48			4.77
Products transferred from Italian operations		0.83			0.73			0.48
Sales of products		9.73			10.11			8.71
Refinery throughputs on own account		27.38			25.03			26.41
of which: refinery throughputs of equity crude on own account		5.93			5.81			5.04
Total sales of refined products		35.41			34.59			35.24
Crude oil sales		0.18			0.33			0.27
TOTAL SALES		35.59			34.92			35.51

In 2015, refining throughputs were 26.41 mmtonnes, up 1.38 mmtonnes, or 5.5% from 2014. In Italy, refinery throughputs increased by 14.1% from 2014, reflecting a favorable refining scenario. The selection of crude oil for refinery runs has been biased towards a sour-heavy quality, privileging spot purchases versus long-term contracts. On an homogeneous structure, excluding the effect of the shutdown for the conversion of the Gela refinery volumes processed increased by 16.4% compared with 2014.

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Outside Italy, Eni’s refining throughputs were 3.69 mmtonnes, down by 1.42 mmtonnes, or 27.8% from previous reporting period, mainly due to divestment in the Czech Republic in the second quarter of 2015. Excluding this effect, refining throughputs were up 5%.

Total throughputs in wholly-owned refineries were 18.37 mmtonnes, down by 2.13 mmtonnes, or 13.1% compared with 2014, determining a refinery utilization rate (ratio between throughputs and balanced capacity) of 95%.

Approximately 20% of processed crude was equity, down 4.8% from 2014 (25.2%).

 

Logistics

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

It owns an integrated infrastructure consisting of 17 directly managed depots and a network of oil and refined products pipelines. Eni logistic model is organized in three hubs (North, Central and South Italy). These hubs manage the product flows in order to guarantee high safety and technical standards, as well as cost effectiveness. Eni is also in joint venture with other Italian operators to optimize its logistic footprint and increase efficiency. Nine depots are currently operated by seven different joint ventures (Sigemi, Petrolig, Petroven, Petra, Seram, Disma, Toscopetrol). Eni transports oil and refined products: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through a proprietary pipeline network extending approximately 1,462 kilometers.

Secondary distribution to retail and wholesale markets is outsourced to independent tanker trucks owners.

 

Marketing

Eni markets a wide range of refined petroleum products, primarily in Italy, through an widespread network of service stations, dealers 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		2013		2014		2015

(mmtonnes)

Italy
Retail		6.64		6.14		5.96
Wholesale		8.37		7.57		7.84
		15.01		13.71		13.8
Petrochemicals		1.24		0.89		1.17
Other sales		9.43		9.89		11.56
		25.68		24.49		26.53
Outside Italy
Retail		3.05		3.07		2.93
Wholesale		4.66		5.03		4.25
		7.71		8.10		7.18
Other sales		2.02		2.00		1.53
		9.73		10.1		8.71
TOTAL SALES		35.41		34.59		35.24

In 2015, sales volumes of refined products (35.24 mmtonnes) increased by 0.64 mmtonnes from 2014, up 1.9%, due mainly to higher volumes sold to oil companies.

 

Retail sales in Italy

In 2015, retail sales in Italy of 5.96 mmtonnes decreased by approximately 0.18 mmtonnes, or by 2.9% compared to 2014, mainly due to competitive pressures; the decrease in sales is referred mainly to the motorway and dealer owned service stations. Average throughput per site (1,569 kliters) decreased by approximately 35 kliters from 2014. Eni’s retail market share was 24.5% in 2015, down by one percentage point from 2014, but stable on the level of the fourth quarter of 2014.

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At December 31, 2015, Eni’s retail network in Italy consisted of 4,420 service stations, 172 stations less compared to December 31, 2014 (4,592 service stations) due to the closing of service stations with low throughput.

 

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, Austria, Switzerland and France, leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities and finalizing the disposal of assets in Eastern Europe, with weaker growth perspectives.

In 2015, retail sales of refined products marketed in the rest of Europe (2.93 mmtonnes) were lower (down by 4.6%) compared to 2014. This is due mainly to the sale of Eni subsidiaries in Czech Republic, Slovakia and Romania, as well as of the interest in Ceská Rafinérská (CRC), partially offset by higher volumes marketed in Germany, Switzerland and Austria.

At December 31, 2015, Eni’s retail network in the Rest of Europe consisted of 1,426 service stations, 202 units less compared with December 31, 2014 mainly due to the disposals in Eastern Europe. Average throughput per site (2,272 kliters) was substantially stable compared to the previous reporting period.

The key markets of Eni’s presence are: Austria (with a 12.6% market share), Switzerland (8.3%) and Germany (3.3%). These market shares were calculated by Eni based on public data on national consumption and Eni’s sales volumes.

 

Other businesses

Wholesale

Eni markets fuels on the wholesale market in Europe, mainly LPG, naphtha, gasoline, diesel, jet, lubricants, fuel oil and bitumen. Major customers are resellers, manufacturing industries, utilities, as well as final users (transporters, residential, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Customer care and product distribution is supported by a widespread commercial and logistical organization presence throughout Italy and articulated in local marketing offices and a network of agents and concessionaires.

In 2015, sales volumes on wholesale markets in Italy (7.84 mmtonnes) increased by approximately 0.27 mmtonnes, or 3.6% compared to the previous year, due to higher sales of bunkering fuel oil, gasoil and minor products, partially offset by lower sales of LPG and lubricants. Sales to petrochemical were 1.17 mmtonnes, up by 31.5% compared to the previous reporting period. This reflected higher naphtha supply following partial recovery of demand in the industrial segment. Wholesale sales in the Rest of Europe were approximately 3.82 mmtonnes, down by 17% from 2014, due to lower sales in the market of Eastern Europe following the above mentioned divestments. Other sales in Italy and outside Italy include volumes sold to other oil companies and export (cargo market); other sales were 13.09 mmtonnes in 2015, up 1.20 mmtonnes, or 10.1%, mainly due to higher volumes sold to oil companies.

 

LPG

The marketing of LPG in Italy is supported by the refining production and a logistic network made of five bottling plants, 1 owned storage site and coastal storage sites located in Livorno, Naples and Ravenna.

LPG is used as heating and automotive fuel. In 2015, Eni share of LPG market in Italy was 17.9%.

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

 

Lubricants

Eni operates five (owned and co-owned) blending plants, in Italy, Europe, North America, Africa and in the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of the art know how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture

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and sale of lubricant bases, manufactured at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero.

In 2015, Eni share of lubricants market in Italy was 19%.

 

Oxygenates

Eni, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 1 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 75% of oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 25% is purchased.

 

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.

 

 

Discontinued operations

Saipem

Saipem supplies turnkey and infrastructure plants for the oil, refining and petrochemical industry, and provides engineering, procurement, construction, installation and commissioning services under EPC (Engineering, Procurement, Construction) and EPCI (Engineering, Procurement, Construction, Installation) contracts. In addition, Saipem is one of the leading worldwide providers of offshore drilling services, due to its technologically advanced fleet of vessels and rigs. Saipem also operates in the onshore drilling business. Saipem is well positioned in the market for services to the oil industry, in both the construction of offshore and onshore projects, focusing on the toughest and most

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technologically challenging projects, which are conducted in remote areas, in deep water and which involve complex hydrocarbon extraction, in which it leverages its distinctive competences and execution skills.

Saipem has a large and diversified orders portfolio, consisting in many ultra-deep water projects, extreme condition pipeline laying, as well as relevant and complex onshore projects, in which it leverages the competitive advantage it has acquired from its technologically advanced fleet and its distinctive know-how.

Saipem is a global contractor, with a strong local presence in strategic and emerging markets such as West Africa, North Africa, the Middle East, and South East Asia.

In 2015, new contracts awarded to Saipem amounted to euro 6,515 million. The most significant contracts related to: (i) an Engineering & Construction contract on behalf of North Caspian Operating Company for the Kashagan field project, which includes the construction of two 95-kilometer pipelines, which will connect the island D located in the Caspian Sea to the Karabatan in Kazakhstan; and (ii) a contract on behalf of Fermaca Pipeline El Encino, for the EPC project that encompasses engineering, procurement, construction and support with commissioning of a new compression station in El Encino, located in Mexico.

As of December 31, 2015, order backlog was euro 15,846 million (euro 22,147 million at December 31, 2014). The order backlog was negatively impacted by the cancellation of outstanding orders for the South Stream project (euro 1,232 million), which was terminated by the client under a termination for convenience provision received on July 8, 2015.

		2012		2013		2014

(euro million)

Orders acquired		10,062		17,971		6,515
Offshore Engineering & Construction		5,581		10,043		4,479
Onshore Engineering & Construction		2,193		6,354		1,386
Offshore Drilling		1,401		722		234
Onshore Drilling		887		852		416
Order backlog and breakdown by business		17,065		22,147		15,846
Offshore Engineering & Construction		8,320		11,161		7,518
Onshore Engineering & Construction		4,114		6,703		5,301
Offshore Drilling		3,390		2,920		2,010
Onshore Drilling		1,241		1,363		1,017

 

Versalis

At December 31, 2015, negotiations were underway to define an agreement for the purchase of the Chemical business managed by Eni’s wholly-owned subsidiary Versalis SpA with an industrial partner, which by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business.

Therefore, effective for the full year, like Saipem, Versalis revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition, Eni’s net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the transaction that is underway. See "Item 5 – Discontinued operations".

Eni, through Versalis, performs activities of production and marketing of petrochemical products (basic petrochemicals and polymers), leveraging on a wide range of proprietary technologies, advanced production facilities, as well as a large and efficient retail network present in 17 European countries.

Versalis’ portfolio of patents and proprietary technologies covers the whole field of basic petrochemicals and polymers: phenol and its derivatives, polyethylene, styrenes and elastomers as well as catalysts and special chemical products. As a producer of intermediates, all types of polyethylene and a wide range of elastomers/lattices and of the complete line of styrenic products, Versalis continues in the development of its proprietary technologies supported by the experience it gained in production and R&D. This approach favored the optimization of the design of equipment and plants, of their performance, of proprietary catalysts and other products that allowed it to achieve excellence in all technologies in the specific business areas in order to compete in markets worldwide. A key role is played by the most innovative proprietary catalysts, particularly those based on zeolites developed by Versalis as building blocks of some of its most advanced technologies and available worldwide.

The principal objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) covering the needs of further production processes: in particular olefins production is strictly

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linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibers and polystyrene.

In polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular, in the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

In 2015, production of petrochemical products amounted to 5,700 ktonnes, increasing by 417 ktonnes compared to the previous year, thanks to the recovery in products demand.

	Year ended December 31,

		2013		2014		2015

(ktonnes)

Intermediates		3,462		2,972		3,334
Polymers		2,355		2,311		2,366
Total production		5,817		5,283		5,700

 

 

Research and development

Technology research and development (R&D) and continuous innovation are key factors in successfully implementing Eni’s business strategies and in supporting mid and long-term performances.

The Company believes that the oil&gas industry will have to face several challenges:
•		uncertainty about oil&gas prices and demand;
•		limited access to new low-cost hydrocarbon resources, with increasing role of unexplored oil&gas basins;
•		need of a more efficient exploitation of conventional fossil sources;
•		strong request of stakeholders for a reduction of GHG emissions; and
•		safety of operations as a crucial point for business success.
In order to address the above challenges, Eni will pursue the following technological targets in the next future:
•		reducing operational risk and maximizing operational efficiency by development of new tools for prevention and response to blow outs (mechanical barriers and equipment for the capture of subsea oil eruption) and development of tools for vessel maintenance and restoring clogged pipes;
•		strengthening technological leadership in exploration by continuously development of proprietary tools;
•		maximizing the recovery factor of reservoirs aiming at innovative enhanced oil recovery techniques sustainable also in low oil price scenarios;
•		focusing on conversion and processing of stranded gas resources and the development of proprietary technologies in the sector of renewable energies;
•		further development of Eni’s Green Refinery processes with innovative solution for the conversion of conventional refineries into bio-refineries;
•		formulations of innovative fuels, lubricants and bitumen that comply with European regulations and new motor specifications;
•		commitment to transfer quickly the relevant results achieved by research and development to business units, also to the new appointed energy solution one; and
•		development of innovative environmental technologies for in situ monitoring and remediation.

In 2015, Eni filed 22 patent applications (50 in 2014).

In 2015, Eni’s overall expenditure in R&D amounted to euro 139 million which were almost entirely expensed as incurred (euro 134 million in 2014 and euro 142 million in 2013).

At December 31, 2015, 513 persons were employed in research and development activities on full time equivalent base.

 

Exploration & Production

• Clean Sea. The proprietary robotic technology, based on AUVs (Autonomous Underwater Vehicles), is designed for environmental monitoring and asset integrity inspection. Clean Sea is able to move around installations

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without physical connection with the surface. After the demonstration tests carried out in 2014, during 2015 two industrial asset integrity campaigns were performed in Mediterranean Sea, generating relevant savings in time and costs leveraging on its advanced characteristics.

• Rapid CUBE. This technology is a proprietary no seal containment system, developed for subsea oil spills in case of not applicability of traditional capping stack and other containment systems. In 2015, the Rapid Cube system was successfully tested and is currently available and it extends the capability of the Eni Emergency Response Kit.

• Dual ROV assisted well killing system. This technology is a quick response tool for a vertical intervention, able to perform a semi-automatic, powerful and precise guidance for the re-entry of a killing string in a flowing well during a subsea blow out. This technology is available to Eni extending its Emergency Response Kit.

• Chemical EOR. In 2015, in Egypt a second polymer EOR pilot plant was started in giant Belayim field, with injection capacity of 1,000 BBL/d. During the tests planned up to 2017 the pilot plant has to confirm the recovery factor increase in line with expected values provided by reservoir simulation.

• e-smart™ W33. Eni in collaboration with Politecnico of Milan and Versalis developed a product based on microgel technology. This product has been specifically designed to selectively shut off water flowing into reservoir fractures. In 2015, 4 applications in 3 wells were successfully performed in Gela field (Italy) which showed a water cut reduction and increase in oil production.

• 3D virtual and augmented reality display. This technology allows to conduct simulations on real plants both on stream or still in phase of design to perform training of plant operators and to increase safety and efficiency of operations. The new 3D room was set-up in the R&D laboratories in San Donato Milanese in 2014. In 2015, it supported critical reservoir simulation studies and was applied as operator training system by production, HSE and drilling & completion departments.

 

Refining & Marketing

• Eni Green Diesel+. A new premium diesel containing 15% bio-mass derived fuel – Hydrogened Vegetable Oil (HVO), produced in Venice refinery using Eni/UOP’s Ecofining process – was formulated and tested to evaluate performance and emissions. The product is commercialized since January 18, 2016.

• Motor lubricant. Developed and qualified a new lube oil packages for motorcycle with improved performance that expand Eni i-ride line of products.

 

Renewable Energy & Environment

• Smart windows. Eni developed the concept of a Smart Window based on luminescent solar concentrators containing original fluorescent dyes. The Smart Window allows building energy savings up to 40%, providing a strong contribution to fulfill the nearly Zero Energy Building (nZEB) laws. Prototype was installed in December 2015.

• Advanced PV. Development of a technology to produce photovoltaic modules based on organic semiconductors on flexible substrates. New generation organic photovoltaic modules aims at competing with silicon in terms of production costs, energy consumption and consequently shortest payback periods thanks to easy and low energy consuming production technology based on roll to roll printing processes. Flexible and lightweight devices, that can be easily fitted on curved surfaces too and that can work also in indirect light will allow to expand the scope of the new photovoltaic commercial sectors.

• Energy Storage: new redox flow batteries. Vanadium Redox Flow Batteries store electric energy in chemicals dissolved in liquid using an electrochemical cell. Research, development and testing of energy storage devices of medium-large scale (up to 100 MW) with high discharge times (hours to days) for load balancing in grid-connected power stations, storage for communities and off-grid systems in remotes sites.

• Automatic device for oil removal from contaminated groundwater, based on the use of a selective hydrophobic filter. The device allows the recovery of oil and organic compounds from contaminated underground water. The idea is based on the selective permeation of the oil phase by a proprietary hydrophobic filter. The polluting organic phase can be removed from the piezometric well, while water remains in the aquifer, without the need for expensive disposal post-treatments. The device is completely automatic and can work continuously with the recovery of big volumes without operator monitoring.

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• Bioremediation of soils and groundwater. Bioremediation technologies based on the biodegradation of organic contaminants (chlorinated compounds and hydrocarbons) are a cheap alternative to more invasive technologies. Determination of the biodegradation potential in polluted water or soil is essential for choosing the type of intervention applicable. Over the last few years, knowledge of the main degradative microbial species has progressed rapidly thanks to the uncovering of the entire genomes of dehalogenating bacteria. Our experience refers to the screening and application of a in-situ remediation process wholly based on biological degradation using an integrated system based on synergic and stimulated activity of plants and microorganisms.

 

 

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 could have a material impact on our results, liquidity prospects, share price and reputation. See "Item 3 – Risk factors –Risk associated with the exploration and production of oil and natural gas".

 

 

Environmental matters

Environmental regulation

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

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We believe that the Company will continue incurring significant amounts of expenses to comply with pending regulations in the matter of environmental, health and safety protection and safeguard, particularly to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere and cope with climate change and water quality of discharges, as well as availability.

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 February 2, 2016, the law "Environmental provisions for the promotion of green economy and the control of excessive use of natural resources" entered into force. The bill covers a wide range of policy areas, such as natural capital and environmental accounting, environmental liability, spatial planning, soil protection, energy, marine conservation, environmental impact assessment and waste management.

On June 16, 2015, the National Strategy on Adaptation to Climate Change has been adopted by Decree of the Directorate General for Climate and Energy. The National Strategy is a cross-sectorial strategic document adopted by the Ministry of the Environment to respond to the broader goals set out in the adaptation strategy package approved by the European Commission in 2013, with the aim of making Europe better prepared to withstand existing and future climate impacts.

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 operate and adopt Best Available Technologies as indicated in the specific "BAT Conclusions reference document" in order to obtain an environmental permit (ex-IPPC).

On December 30, 2015, the Legislative Decree No. 210 (so-called Milleproroghe 2016), postpones up to January 1, 2017, the terms of adaptation to the limits of emissions for Large Combustion Plants (LCP) decided by the Legislative Decree No. 152/2006. The terms of emissions are regarding the LCP up to 2013 and the operators of those plants can act under the same permit for one more year.

On March 23, 2015, was published the Decree of the Environment Ministry No. 31 that simplifies the implementation of safety measures and the remediation of gas stations; the new procedures will allow for a rapid implementation of remediation measures on the distribution network.

On May 22, 2015, the Law No. 68/2015 was issued, introducing environmental crimes into the Italian Criminal Code. 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,

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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.

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 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. 221/2015 and Law No. 21/2016, shall be applied only from January 1, 2017, except the ones for obligations about signing up and payment of annual contributions, which entered in force on 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.

On September 11, 2015, the decree of June 24, 2015 of the Ministry of the Environment and Protection of Natural Resources on landfill waste criteria admission was published. The decree is a response of Italian government to the controversy with the European Commission and introduces a numerous news on the landfill waste criteria.

The Ministry of the Environment and Protection of Natural Resources issued a note dated September 28, 2015, No. 11845, on the application of the new European rules in the waste classification.

On September 4, 2015, the new operative rules for permits release in research and exploration of hydrocarbons entered into force. The decree of the Ministry for Economic Development (DGRME Department) regulates the conditions and modes of hydrocarbons permitting system accordingly to the Legislative Decree No. 133/2014 (converted in Law No. 164/2014).

On December 28, 2015, the Law No. 221 introduces regulations on several environmental issues regarding marine areas protection, nature conservation, sustainable development, Green public procurement, Environmental & Health impact assessment introducing more stringent requirements for the presentation of new projects. For instance, the law introduces a new procedure, which allows the private party to propose a settlement on compensation for environmental damage and restoration of SIN (National Priority Sites). In addition, regarding health and environmental assessment of plants impacts.

Eni is involved in an internal multidisciplinary project on:
•		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 boarders scope of the EIA covering new issues such as climate change, biodiversity, resource efficiency and risks prevention.

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On September 15, 2015, the revised ISO 14001:2015 Environmental Management System was published. A revised version is designed to respond to latest trends and ensure it is compatible with other management system standards. The key changes are related to the increased prominence of environmental management within the organization’s strategic planning processes, proactive initiatives to protect the environment from harm and degradation, such as sustainable resource use and climate change mitigation, lifecycle considering environmental aspects and additional communication strategy required.

On September 9, 2015, the Directive No. 2015/1513/EU was issued, amending Directive No. 1998/70/EC relating to the quality of petrol and diesel fuels and amending Directive No. 2009/28/EC on the promotion of the use of energy from renewable sources. The Directive (so-called ILUC Directive) introduces new rules into force to reduce the risk of indirect land use change and to prepare the transition towards advanced biofuels. The European Union limits the share of bio-fuels from crops grown on agricultural land that can be counted towards the 2020 renewable energy targets to 7% (conventional bio-fuel), sets an indicative 0.5% target for advanced bio-fuels as a reference for national targets, which will be set by EU countries in 2017. Moreover, it harmonizes the list of feedstock for bio-fuels across the EU whose contribution would count double towards the 2020 target of 10% for renewable energy in transport and requires that biofuels produced in new installations emit at least 60% fewer GHG than fossil fuels. Finally, the Directive introduces stronger incentives for the use of renewable electricity in transport (by counting it more towards the 2020 target of 10% for renewable energy use in transport) and includes a number of additional reporting obligations for the fuel providers, EU countries and the European Commission. Member States are obliged to transpose the Directive into national legislation by September 10, 2017 and should establish the level of their national indicative sub-targets for advanced bio-fuels by April 6, 2017.

On March 19, 2014, was launched in Europe the "Mayors Initiative on Adaptation to Climate Change", a program aimed to cut GHG emissions with a focus on adaptation measures. In 2015, 20 Member States have developed a national adaptation strategy and several more are under preparation. By March 2015, Member States provided reports on their adaptation activities within an EU climate monitoring and reporting system, including information on Member States national adaptation planning and strategies, outlining their implemented or planned actions to facilitate adaptation to climate change. Information reported will be made publicly available in Climate-ADAPT. In 2017, the European Commission will report to the European Parliament and the Council on the state of implementation of the EU Adaptation Strategy and it will assess whether action being taken in the Member States is sufficient and consider whether additional measures would be needed.

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 GHG 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.

The original F-gas Regulation (Regulation No. 842/2006) was replaced by a new Regulation (No. 517/2014) adopted in 2014 that 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 GHG emissions by 80-95% of 1990 levels by 2050.

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.

On October 6, 2015, as a more structural reform of the European Emission Trading Scheme, following the debate started in January 2014, the European Parliament and the Council established with Decision (EU) 2015/1814 a Market Stability Reserve as of 2018. Starting from 2019, the reserve will address the surplus of allowances and will improve the system’s resilience to major shocks by adjusting the supply of allowances to be auctioned.

On July 15, 2015, the European Commission presented a legislative proposal to revise the EU emissions trading system for the period after 2020. This is the first step in delivering on the EU’s target to reduce GHG emissions by at least 40% domestically by 2030 in line with the 2030 climate and energy policy framework.

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On June 1, 2007, the REACH Regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed caused by chemicals, while enhancing the competitiveness of the EU chemical industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to European Chemicals Agency (ECHA) how the substance can be safely used and they must communicate the risk management measures to the users. If the risks cannot be managed, Authorities can restrict the use of substances in different ways. Over time, the hazardous substances should be substituted with less dangerous ones. The deadline of REACH registration depends on the tonnage band of a substance and the classification of a substance; next and last deadline is 2018. Eni recognizes the importance of the Regulation EC No. 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA 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&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. 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 NO_X 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 NO_X and SO₂ from several process and combustion units.

On December 18, 2015, the Directive No. 2015/2193/EU on the limitation of emissions of certain pollutants into the air from medium combustion plants entered into force. The Medium Combustion Plant Directive (MCP Directive) regulates pollutant emissions from the combustion of fuels in plants with a rated thermal input equal to or greater than 1 megawatt (MWth) and less than 50 MWth. The Directive is a part of the Clean Air Policy Package adopted on December 18, 2013 and it regulates emissions of SO₂, NO_X and dust into the air with the aim of reducing those emissions and the risks to human health and the environment they may cause. The MCB Directive will have to be transposed by Member States by December 19, 2017. The MCP Directive also ensures implementation of the obligations arising from the Gothenburg Protocol under the UNECE Convention on Long-Range Transboundary Air Pollution.

On September 18, 2015, the Directive No. 2015/1480/EU focused on the new regulation for the air quality ambient assessment entered in force. The Directive is amending several annexes to Directives 2004/107/EC and 2008/50/EC of the European Parliament and of the Council laying down the rules concerning reference methods, data validation and location of sampling points for the assessment of ambient air quality.

European Union Regulation 2015/757 on the monitoring, reporting and verification of carbon dioxide emissions from maritime transport has entered into force on July 1, 2015.

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

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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&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.
•		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 hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will likely increase in future years.

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

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

The main changes in comparison to the previous Seveso Directive are:
•		technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures;
•		expanded public information about risks resulting from Company activities;
•		modified rules in participation by the public in land-use planning projects related to Seveso plants; and
•		stricter standards for inspections of Seveso establishments.

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

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HSE activity for the year 2015

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 2015, 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 247 (244 in 2014 and 234 in 2013, of which 87 certifications according to the ISO 14001 standard, 8 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union), 10 certifications according to the ISO 50001 standard (certification for an energy management system) and 92 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

In 2015, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to euro 853.02 million, down 9.3% from 2014.

Environment. In 2015, Eni incurred total expenditures of euro 512.35 million for the protection of the environment (with a reduction of 20.6% with respect to 2014). Current environmental expenses amounted to euro 401.64 million, down 18.2% from 2014, and are mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure decreased by 28.2% and are mainly related to, spill prevention, air protection and water management. Eni expects to continue incurring amount of capital environmental expenditures and current expenses in line with 2015 levels in future years.

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 2015, 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 2015. 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. In 2016 the development of a second phase is foreseen. Moreover, in 2015, 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 is progressively involving all the operating sites.

Results of efforts to achieve a better safety in all activities has brought an improvement of Eni workforce lost time injury frequency rate to 0.19 and of the severity rate to 0.009, decreasing by 41.9% and by 38% from 2014, respectively. The total recordable injury rate (0.40) decreased by 36.4% compared to 2014.

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 2015 to support the safety levels of operations and to comply with applicable rules and regulations were euro 239.04 million, increasing by 67.5% from 2014.

Health. Eni’s activities for protecting health aim to continuously improve the psychophysical wellbeing of people in the workplace. 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.

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To protect the health and safety of its employees, Eni relies on a network of 179 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 2015, Eni incurred total expenses of euro 19.3 million, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health which will be in line with 2015 levels in future years.

 

Managing GHG emissions

2015 was a significant year for the climate change debate. The adoption on December 12, 2015, by the COP21 of the Paris Agreement was an historic event as it pursues ambitious goals and is supported by a global political consensus (196 Parties agree on the text of the Agreement, equal to 95% of global GHG emissions). The Paris Agreement represented for Eni a very positive step toward a low carbon energy transition as a major international energy company Eni is actively involved to play its role in this challenging debate. In 2015, Eni has contributed to further develop the "Oil and Gas Climate Initiative" (OGCI), a voluntary CEO led initiative launched in 2014 along with other companies in the oil&gas sector (currently, OGCI members represent about 25% of global HC production). In particular, on October 6, 2015, OGCI organized in Paris a high-level event where CEOs signed a Joint Collaborative Declaration, announcing their partnership on climate change and launching a report to present concrete measures in order to improve the management of GHG emissions and contain climate impacts of the oil&gas sector in the long term.

On June 1, 2015, Eni, together with other majors (BG Group, BP, Royal Dutch Shell, Statoil and Total), has sent a public letter to the United Nations to advocate a global action on carbon pricing and promote natural gas as a bridge solution to the climate challenge. On carbon pricing Eni has confirmed its commitment with the participation in the activities of Carbon Pricing Leadership coalition of the World Bank and joining the Carbon Pricing workstream of the UN Global Compact Caring for Climate initiative.

In 2015, Eni has continued its efforts in two international Public-Private Initiatives focused on operational efficiency: the "Clean Air and Climate initiative - Oil & Gas Methane Partnership", aimed at reducing methane emissions in the oil&gas value chain, and the "zero routine gas flaring at 2030" program of the World Bank’s "Global Gas Flaring reduction partnership". About this important topic, in 2015, Eni has been awarded by the World Bank for the flaring down project of M’Boundi, in Congo. 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 GHG emissions (GHG Accounting and Reporting Protocol), integrated in 2013 by a procedure on reporting and accounting methodologies on indirect emissions scope 3 types. This procedure was update in 2015. According to the Eni methodology for accounting and reporting Scope 3 GHG, Eni estimates the indirect GHG emissions generated by several emission categories (e.g. purchased goods and services, use of sold hydrocarbon products, business travel, franchising, etc.) in line with the WBCSD-WRI Protocol "Corporate Value Chain (Scope 3) Accounting and Reporting Standard".

Eni documents are an essential requirement for emissions certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to GHG, the definition of objectives and the assessment of progress. Eni GHG Protocol has been updated in 2015 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 2014 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, since early 2000s, Eni has been implementing a climate strategy aimed at reducing GHG emissions while fulfilling energy demand, with energy models that integrate efficiency, advanced technologies, low carbon fuels and renewables. Thanks to these progressive efforts, in 2015, Eni has achieved a reduction by more than 23% (compared to 2010) of the GHG emission performance index in the Upstream business.

Main pillars of this strategy are flaring down, energy efficiency and the reduction of methane fugitive emissions. Regarding flaring, Eni, began since 2007 massive investments for the progressive reduction of the gas flared, using the

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natural gas to produce electricity for local populations, for domestic consumption or for export. As per efficiency, Eni has a long tradition of energy efficiency in the refining sector and this commitment, combined with recent projects in the Upstream business, prevented cumulative emissions of over 1 mmtonnes CO₂/y. Regarding methane fugitive emissions, this is a new challenge for oil&gas companies, but in the first year (2015) of reduction campaigns, Upstream has achieved savings of 0.6 mmtonnes CO₂ eq.

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

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.

Currently, Eni participates in the ETS with 26 plants in Italy and 5 outside Italy, which collectively represent 43% 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 (2016-2019), 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.

 

Regulation of exploration and production activities

Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See "Regulation of the Italian hydrocarbons industry" and "Environmental matters" for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities. Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any royalties that are payable in-kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in-kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. In production sharing agreements, entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies 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&gas production profits and activities may be substantially higher than those imposed on other businesses.

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Regulation of the Italian hydrocarbons industry

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

 

Exploration & Production

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

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

Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with fixed amount of exemption. Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties are equal to 20% for oil and gas, with no exemptions).

 

Gas & Power

Natural gas market in Italy

Legislative Decree No. 130 of August 13, 2010 containing measures for increasing competition in the natural gas market and transferring the ensuing benefits to final customers and Law Decree of December 23, 2013 containing measures to promote gas market liquidity

In 2011, Legislative Decree No. 130 of August 13, 2010 titled "New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers" became effective. This new regulation replaced the previous system of gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 by introducing a 40% ceiling to the wholesale market share of each Italian gas operator who inputs gas into the Italian backbone network. In the frame of Legislative Decree No. 130/2010 Eni 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.

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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, regasification 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.

 

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. In November 2015, the Authority updated the index of procurement cost for thermal year 2015 and resolved that Eni’s supply costs have evolved coherently to the Authority projections made in 2013. Under this scenario, the Authority confirmed the initial amount of

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the compensation of euro 160 million and Eni recognized a second tranche equal to 40% of that amount (approximately euro 60 million) in the 2015 financial statements. However, in the current market scenario it is still possible 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. 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 that required that any refining activity be handled under a concession from the state. Today an authorization is required to set up new processing and storage plants and for any change in the capacity of mineral processing plants, while all other changes that do not affect capacity can be freely implemented. Another simplification measure 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 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012, principals will be allowed to supply freely up to 50% of their requirements. In such case the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing Eni’s market share in Italy.

Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) upon the closure of at least 7,000 service stations, the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third party access to unused storage capacity for petroleum products. With the same goal of renewing the Italian distribution network, Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities. After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012 all service stations must be provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations which might prejudice the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the

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obligation to undertake non-oil activities and the liberalization of opening hours. Management believes that those measures will favor competition in the Italian retail market and support efficient operators.

Petroleum product prices. Petroleum product prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Productive Activities; such recommendations are considered by service station operators in establishing retail prices for petroleum products.

Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 ("Decree 22/2001") enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain. As of December 31, 2015, Eni owned 5.1 mmtonnes of oil products inventories, of which 3.6 mmtonnes as "compulsory stocks", 1.3 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 (38%), light and medium distillates (33%), refinery feedstock (20%), fuel oil (6%) and other products (3%) were located throughout the Italian territory both in refineries (88%) and in storage sites (12%).

 

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 ("Article 101" and "Article 102", respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self assessment by the undertakings that such conducts does not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:
•		requiring that an infringement be brought to an end;
•		ordering interim measures;
•		accepting commitments; and
•		imposing fines, periodic penalty payments or any other penalty provided for in their national law.

National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by

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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&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, 2015, there were 245 fully-consolidated subsidiaries and 53 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 2015".

 

 

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.

 

Discontinued operations

Eni’s results of operations and cash flow as at and for the twelve months ended December 31, 2015 have been prepared: (i) on a consolidated basis; and (ii) presenting separately continuing operations from discontinued operations, in accordance with IFRS 5. Discontinued operations comprise:
•		The E&C operating segment which is managed by Eni’s subsidiary Saipem SpA (Eni’s share 42.9%). On January 22, 2016, there was the closing of the agreements signed on October 27, 2015 with the Fondo Strategico Italiano (FSI). Those include the sale of a 12.503% stake of the share capital of Saipem to FSI. Simultaneously, a shareholder agreement between Eni and FSI became effective, which was intended to establish joint control over the former Eni subsidiary. Therefore effective for the 2015 full year, Saipem revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition as provided by IFRS 5, Eni’s net assets in Saipem have been aligned to the lower of their carrying amount and fair value given by the share price at the reporting date.
•		The Chemical business managed by Eni’s wholly-owned subsidiary Versalis SpA. As of the reporting date, negotiations were underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business. Therefore, effective for the full year, likewise Saipem, Versalis revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition, Eni’s net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the proposed transaction.
•		Comparative results of operations and cash flow for the year 2014 and 2013 have been restated accordingly as provided by IFRS 5.

Consequently, the discussion of Eni’s financial performance for 2015 and outlook mainly focuses on the results of the continuing operations. In accordance with IFRS 5, gains and losses pertaining to the discontinued operations include only those resulting from transactions with third parties. Therefore, the results of the continuing operations do not fully illustrate the underlying performance given the elimination of gains and losses on intercompany transactions with the discontinued operations due to consolidation procedures. The same is true for the performance of the discontinued operations. The bigger the intercompany transactions, the larger that sort of distortion.

In particular, the accounting of the E&C segment as discontinued operations according to IFRS 5 yielded a benefit to the continuing operations due to the elimination of the costs incurred towards Saipem for the execution of contract works commissioned by Eni’s Group companies for maintenance and construction of assets (plants and other infrastructures). On the other hand, the accounting of the Chemical business as discontinued operations negatively affected the results of the continuing operations due to the elimination of revenues relating to the supply of oil-based petrochemical feedstock and other plant utilities to Versalis, mainly from the Group’s R&M segment.

Because of this, in order to obtain a better comparison of base Group performance across reporting periods and to understand in a better way underlying industrial trends, management has assessed the underlying performance of the continuing operations also by calculating Non-GAAP performance measures that: (i) excludes certain gain and changes; and (ii) reinstates the effects of the elimination of intercompany transactions (see below for further information).

 

Executive summary

In 2015, Eni reported a net loss pertaining to continuing operations of euro 7,680 million, which was a sharp deterioration compared to 2014 when Eni reported a profit of euro 101 million. A prolonged slide in crude oil prices has negatively affected the Group’s performance, impacting results from operations and the value of assets.

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Operating results from continuing operations were a loss of euro 2,781 million in 2015. These negative results were driven by lower E&P revenues reflecting reduced oil&gas realizations negatively impacted by sharply lower Brent prices (down by 47%), the alignment of the carrying amounts of oil and product inventories to current market prices and the recognition of material impairment losses mainly taken at the Group oil&gas CGUs (euro 4,502 million). In performing the impairment review, Eni’s management assumed a reduced long-term price outlook for the Brent crude oil down to 65 $/BBL compared to the previous 90 $/BBL scenario adopted for valuating asset recoverability in the 2014 financial statements. Furthermore, the operating loss was impacted by an estimate revision of euro 484 million taken at revenues accrued on the sale of natural gas and electricity to retail customers in Italy dating back to past reporting periods and the establishment of a provision of euro 226 million for those accruals.

Eni’s management has implemented certain initiatives to mitigate the negative effect of low oil prices on profitability and cash flow. These initiatives include the reduction of E&P operating expenses and the curtailment of capital expenditure by carefully selecting exploration plays, rescheduling and re-phasing large development activities and renegotiating supply contracts for plants and other E&P infrastructures, as well as leveraging oilfield services rates on the deflationary pressure induced by the decline in crude oil prices. This reduction in capital expenditure only had a modest impact on hydrocarbon production, which grew by 11.3% to 1,688 KBOE/d. The production plateau was the highest since 2010, on yearly basis. The Refining & Marketing segment returned to underlying profitability supported by plant optimizations and an ongoing margin recovery. The G&P segment almost achieved an operating profit break-even, net of a charge related to the unfavorable outcome of a commercial arbitration and in spite of the fact that the Company did not yet benefit from a renegotiation of certain long-term supply contracts, which was expected to be finalized before year end. Finally, G&A expenses were reduced across all businesses and at headquarter level.

Overall management estimated that the reduction in the Group operating earnings of approximately euro 10.4 billion (from operating profit of euro 7.59 billion in 2014 to loss of euro 2.78 billion in 2015) was due to the following factors:
•		a negative euro 8.8 billion impact due to lower commodity prices, net of favorable exchange differences in translating dollar-denominated operating earnings into euros;
•		a negative euro 4.2 billion impact due to increased impairment losses and other extraordinary charges, which were primarily reflective of a deteriorated commodity price outlook; and
•		a negative euro 0.7 billion effect in the Gas & Power segment associated with lower one-off gains related to the renegotiations of gas contracts.
These negatives were partly offset by:
•		a positive euro 2.2 billion gain associated with production growth, efficiency initiatives, cost reductions and a decreased exploration expenditure;
•		a positive euro 0.5 billion reduction in the inventory holding loss (see page 100 for a definition of this item) due to a lower valuation allowance to align the carrying amounts of inventories to their lower net realizable values at year end; and
•		a positive euro 0.6 billion effect due the elimination of profit and loss on intercompany transactions with the discontinued operations.

Net loss for 2015 was significantly affected by tax expenses incurred despite negative pre-tax earnings, which was negatively affected by a deteriorated price scenario in the E&P segment. The main drivers of this were three. First, the segment’s taxable profit was mainly earned in PSA contracts, which, although more resilient in a low-price environment due to the cost recovery mechanism, bear higher-than-average rates of tax. Secondly, there was higher incidence of certain non-deductible expenses on the pre-tax profit lowered by the scenario. Finally, a lowered recognition of deferred tax assets relating to operating losses due to a reduced profitability outlook (euro 1,058 million). The Group tax rate was also impacted by the write-off of Italian deferred tax assets and other changes of euro 885 million in the full year due to projections of lower future taxable profit at Italian subsidiaries and the reduction of the statutory tax rate from 27.5% to 24%, which was considered as substantially enacted at the reporting date.

 

 

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Key consolidated financial data

		2013		2014		2015

(euro million)

Net sales from operations from continuing operations				98,547			93,187			67,740	)
Operating profit (loss) from continuing operations				7,867			7,585			(2,781	)
Net profit (loss) attributable to Eni from continuing operations				3,472			101			(7,680	)
Net profit (loss) attributable to Eni from discontinued operations				1,688			1,190			(1,103	)
Net profit (loss) attributable to Eni				5,160			1,291			(8,783	)
Net cash provided by operating activities - continuing operations				9,132			13,162			11,181
Capital expenditures - continuing operations				11,584			11,264			10,775
Acquisitions of investments and businesses				317			408			228
Shareholders’ equity including non-controlling interest at year end				61,049			62,209			53,669
Net borrowings at year end (1)				14,963			13,685			16,863
Net profit (loss) attributable to Eni basic and diluted from continuing operations		(euro per share)		0.96			0.03			(2.13	)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		(euro per share)		0.46			0.33			(0.31	)
Net profit (loss) attributable to Eni basic and diluted		(euro per share)		1.42			0.36			(2.44	)
Dividend per share		(euro per share)		1.10			1.12			0.80
Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) (1)				0.25			0.22			0.31

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(1)

For a discussion of the usefulness of these non-GAAP financial measures and a reconciliation to the most directly comparable GAAP financial measures see - "Liquidity and capital resources - Financial conditions" below.

The table below sets forth for the reported periods details of certain, identified gains and charges included in net loss. These gains and charges mainly related to inventory holding gains and losses, asset impairments, estimate revisions, 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,

		2013		2014		2015

(euro million)

Profit (loss) on stock		(503	)		(1,290	)		(814	)
Environmental provisions		(144	)		(152	)		(204	)
Impairment losses		(2,356	)		(1,015	)		(4,826	)
Net gains on disposal of assets		294			75			415
Risk provisions		(330	)		35			(223	)
Provision for redundancy incentives		(245	)		(4	)		(27	)
Fair value gains/losses on commodity derivatives		(315	)		16			(164	)
Reclassification of currency derivatives and translation effects to management measure of business performance		199			(236	)		60
Other		(13	)		(291	)		(793	)
Net (charges) gains in operating profit		(3,413	)		(2,862	)		(6,576	)
Capital gain on 28.75% of Eni East Africa		3,359
Revaluation gain on Artic Russia		1,682
Capital gain on South Stream					54
Write downs of investments and financing receivables/capital gains		98			134			(456	)
Write down of deferred tax assets/recognition of deferred tax liabilities		(1,444	)		(1,045	)		(1,711	)
Tax gain on the tax dispute on Libyan Tax					824
Tax effects on the above listed items		786			716			1,833
Other		(94	)		(372	)		(124	)
Net (charges) gains in net profit		974			(2,551	)		(7,034	)
Net (charges) gains attributable to non-controlling interest		1			(452	)		(52	)
Net (charges) gains attributable to Eni		973			(2,099	)		(6,982	)

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In evaluating the Company’s underlying performance and with the purpose of better explaining year-on-year changes in the Group base performance, management has assessed to separate from the other drivers of the Group performance the impact of the following items:
•		the above listed gains and charges amounting to pre-tax loss and post-tax loss of euro 6,576 and euro 6,982 million, respectively, which amounts include an inventory holding pre-tax loss of euro 814 million and post-tax loss of euro 561 million, respectively; and
•		profit and loss on intercompany transactions with the discontinued operations for euro 309 million in operating profit and euro 1,032 million in net profit which are eliminated upon consolidation.

On that basis, management has calculated a Non-GAAP measure of operating profit that would amount to euro 4,104 million for 2015, down by euro 7,338 million from 2014. The main drivers of this decline were lowered commodity prices of euro 8.8 billion (net of exchange rate gains) and reduced one-off items in the G&P segment for euro 0.7 billion, partly offset by efficiency and cost reduction gains of euro 2.2 billion. The corresponding Non-GAAP measure of net profit would amount to euro 334 million, down by euro 3,520 million from 2014 due to a lowered operating performance and a higher Group tax rate mainly driven by the E&P segment.

The table below provide a reconciliation of those Non-GAAP measure to the most comparable performance measures calculated in accordance with IFRS.

		2013		2014		2015

(euro million)

Non-GAAP measure of operating profitability of continuing operations		13,136			11,442			4,104
Identified net charges and inventory holding gains and losses		(3,413	)		(2,862	)		(6,576	)
Elimination upon consolidation of intercompany transactions with discontinued operations		(1,856	)		(995	)		(309	)
GAAP measure of operating profitability of continuing operations		7,867			7,585			(2,781	)
Non-GAAP measure of net profitability of continuing operations		3,854			3,854			334
Identified net charges and inventory holding gains and losses		973			(2,099	)		(6,982	)
Elimination upon consolidation of intercompany transactions with discontinued operations		(1,355	)		(1,654	)		(1,032	)
GAAP measure of net profitability of continuing operations		3,472			101			(7,680	)
Non-GAAP measure of net cash provided by operating activities from continuing operations		10,818			14,387			12,189
Elimination upon consolidation of intercompany transactions with discontinued operations		(1,686	)		(1,225	)		(1,008	)
GAAP measure of net cash provided by operating activities from continuing operations		9,132			13,162			11,181

Management also evaluated the Group tax rate by excluding the impact of the higher incidence on pre-tax profit of certain non-deductible expenses in E&P, where this incidence is expected to prospectively come down due to the effect of lower amortization charges going forward because of the impairment losses recorded in 2015. In addition, the Group tax rate was negatively affected by the fact that certain exploration expenses related to successful initiatives could not be deducted from pre-tax earnings as the Group fully amortized all exploration expenses incurred in the reporting period. On those bases, the Group tax rate would be better than the reported amount.

In 2015, net cash provided by operating activities from continuing operations amounted to euro 11,181 million and was impacted by the eliminations of intercompany flows with discontinued operations due to consolidation. In evaluating the Company’s underlying cash flow performance and with the purpose of better explaining year-on-year changes in the Group base performance, management has assessed to separate the impact of intercompany flow with discontinued operations from the other drivers of the Group cash flow performance. When reinstating these intercompany flows, net cash provided by operating activities from continuing operations adds up to euro 12,189 million. Proceeds from disposals were euro 2,258 million and mainly related to an interest in Snam due to exercise of the conversion right by bondholders (euro 911 million), an interest in Galp (euro 658 million) and the divestment of non-strategic assets mainly in the Exploration & Production business. These inflows funded part of capital expenditure (euro 10,775 million), other changes relating to capital expenditure and the payment of Eni’s dividend (balance dividend for fiscal year 2014 and the 2015 interim dividend totaling euro 3,457 million). When considering the cash flow of discontinued operations, the Group’s net debt increased by euro 3,178 million to euro 16,863 million, net of negative exchange rate differences and the reclassification of Saipem net cash in the discontinued operations.

Management calculated that the net cash flow provided by operating activities from continuing operations was down by 15% year-on-year, while crude oil prices were down by approximately 50%. The Group was able to cover entirely its capital expenditures with funds from operations. Capital expenditures for the year were reduced by 17% at

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constant exchange rates (the reported amount was down by 4%) and it was better than initially planned (management was planning at the beginning of the year for a reduction of 14%) and reflected re-phasing and rescheduling of longer term projects, contract renegotiations and other efficiencies which did not affect production growth for the year. Net cash provided by operating activities were supported by optimization initiatives and non-recurring effects in working capital. We estimated that non-recurring effects of the working capital positively influenced cash flow by approximately euro 2.2 billion. These included a net positive inflow in the Gas & Power segment for euro 0.9 billion 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; the reimbursement and the disposal to financing institutions of certain tax receivables due to the parent company (approximately euro 0.9 billion) and inventory other optimizations in the Refining & Marketing business for euro 0.4 billion.

As of December 31, 2015, the ratio of net borrowings to shareholders’ equity including non-controlling interest – leverage⁶ – increased to 0.31, compared to 0.22 as of December 31, 2014. This increase was due to greater net borrowings and a reduction in total equity, which was impacted by the result of the year and dividend payments, partly offset by a sizable appreciation of the U.S. dollar against the euro in the translation of the financial statements of Eni’s subsidiaries that use the U.S. dollar as functional currency, ultimately resulting in an equity gain. The U.S. dollar was up by 10.3% compared to the closing of the previous reporting period at December 31, 2014 and December 31, 2015. Assuming the closing of the Saipem transactions at the balance sheet date, management estimated that the leverage would be significantly lower than the reported amount.

In 2016, we are projecting a capital budget of approximately euro 9.4 billion, 20% lower than in 2015 at constant exchange rates, while confirming the production plateau achieved in 2015.

We also plan to preserve our liquidity by leveraging on the timely development of capital projects in the Exploration & Production in order to achieve the scheduled time-to-market of our reserves, on cost efficiencies across all businesses and on strengthening profitability at our Gas & Power and Refining & Marketing segments. We plan to generate additional funds through our asset disposal program, which will mainly comprise the dilution of our working interests in certain of our exploration discoveries.

Finally, in spite of a depressed commodity prices environment, we are planning to confirm our floor dividend of euro 0.8 per share for fiscal year 2016, targeting to maintain a balance between internally-generated funds, including disposals, and fund requirements for capital expenditures and shareholder remuneration at our price assumption of 40 $/BBL for the Brent benchmark in 2016.

 

Trading environment

		2013		2014		2015

Average price of Brent dated crude oil in U.S. dollars (1)		108.66		98.99		52.46
Average price of Brent dated crude oil in euro (2)		81.82		74.48		47.26
Average EUR/USD exchange rate (3)		1.328		1.329		1.110
Standard Eni Refining Margin (SERM) (4)		2.43		3.21		8.32
Euribor - three month euro rate % (3)		0.22		0.21		(0.02	)

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(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 $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.

When the term margin is used in the following discussion, it refers to the difference between the average selling 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 margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. See "Item 3 – Risk factors".

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In 2015, Eni faced a trading environment characterized by continuing weakness of Brent price (down 47% from 2014) due to oversupply on the reference market. Gas realization were affected by a weak commodity scenario (mainly in the United States and in Europe). Eni’s refining margins (Standard Eni Refining Margin - SERM) that gauge the profitability of Eni’s refineries, more than doubled from a year ago, due to lower marker Brent Prices and the relative strength in gasoline prices compared to the feedstock cost. However, the European refining business continued to be affected by structural headwinds from sluggish demand growth, overcapacity and increasing competitive pressure from streams of cheaper refined products imported from Russia, Asia and the United States. The European gas market continues to be adversely affected by weak demand and increasing competitive pressure. Price competition was tough taking into account minimum off-take obligations provided by gas purchase take-or-pay contracts and reduced sales opportunities. Results of the year benefited from the depreciation of the euro against the dollar (down 16.5%).

 

 

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 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 is provided in "Item 18 – note 6 – of the Notes on Consolidated Financial Statements".

 

 

2013-2015 Group results of operations

Resegmentation of Eni reportable segments

Eni’s segmental reporting is established on the basis of the Group’s operating segments that are evaluated regularly by the chief operating decision maker (the CEO) to allocate resources and assess performance. Effective January 1, 2015, Eni’s segment information was modified to align Eni’s reportable segments to certain changes in the organization and in profit accountability defined by Eni’s top management. The main changes are:
•		results of the oil and products trading activities and related risk management activities were transferred to the Gas & Power segment, consistently with the new organizational setup. In previous reporting periods, results of those activities were reported within the Refining & Marketing segment as part of a reporting structure which highlighted results for each stream of commodities; and
•		the previous reporting segments "Corporate and financial companies" and "Other activities" have been combined being residual components of the Group.

The comparative reporting periods included in the report have been restated consistently with the new segmental reporting adopted by the Group.

In the table below the key performance indicators of segmental reporting are furnished with reference to the full years 2013 and 2014 presented herein as restated in accordance with the new reportable segments adopted by Eni.

As reported

(euro million)

E&P

G&P

R&M

Versalis

E&C

Corporate and financial companies

Other activities

Impact of unrealized intragroup profit elimination

GROUP

Full year 2013
Net sales from operations		31,264		32,212			57,238			5,859			11,598			1,453			80			(25,007	)		114,697
Operating profit (loss)		14,868		(2,967	)		(1,492	)		(725	)		(98	)		(399	)		(337	)		38			8,888
Full year 2014
Net sales from operations		28,488		28,250			56,153			5,284			12,873			1,378			78			(22,657	)		109,847
Operating profit (loss)		10,766		186			(2,229	)		(704	)		18			(246	)		(272	)		398			7,917

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As restated

(euro million)

E&P

G&P

R&M

Corporate and Other activities

Chemical

E&C

Impact of unrealized intragroup profit elimination

GROUP

Discontinued operations

Continuing operations

Full year 2013
Net sales from operations		31,264		79,619			27,201			1,496			5,859			11,598			(42,340	)		114,697		16,150			98,547
Operating profit (loss)		14,868		(2,923	)		(1,534	)		(736	)		(727	)		(98	)		38			8,888		1,021			7,867
Full year 2014
Net sales from operations		28,488		73,434			24,330			1,429			5,284			12,873			(35,991	)		109,847		(16,660	)		93,187
Operating profit (loss)		10,766		64			(2,107	)		(518	)		(704	)		18			398			7,917		(332	)		7,585

 

Overview of the profit and loss account for three years ended December 31, 2013, 2014 and 2015

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,

		2013		2014		2015

(euro million)

Net sales from operations		98,547			93,187			67,740
Other income and revenues (1)		1,117			1,039			1,205
Total revenues		99,664			94,226			68,945
Operating expenses		(80,765	)		(76,639	)		(56,761	)
Other operating (expense) income		(71	)		145			(485	)
Depreciation, depletion, amortization and impairments		(10,961	)		(10,147	)		(14,480	)
OPERATING PROFIT (LOSS)		7,867			7,585			(2,781	)
Finance income (expense)		(999	)		(1,181	)		(1,323	)
Income (expense) from investments		6,083			469			124
PROFIT (LOSS) BEFORE INCOME TAXES		12,951			6,873			(3,980	)
Income taxes		(9,055	)		(6,681	)		(3,147	)
Net profit (loss) - continuing operations		3,896			192			(7,127	)
Net profit (loss) - discontinued operations		1,063			658			(2,251	)
Net profit (loss)		4,959			850			(9,378	)
Attributable to:
Eni’s shareholders:		5,160			1,291			(8,783	)
- continuing operations		3,472			101			(7,680	)
- discontinued operations		1,688			1,190			(1,103	)
Non-controlling interest:		(201	)		(441	)		(595	)
- continuing operations		424			91			553
- discontinued operations		(625	)		(532	)		(1,148	)

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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,

		2013		2014		2015

(%)

Operating expenses		82.0		82.2		83.8
Depreciation, depletion, amortization and impairments		11.1		10.9		21.4
OPERATING PROFIT (LOSS)		12.0		7.7		(4.1	)

2015 compared to 2014. See management discussion under paragraph "Executive summary" on page 87 for a discussion of the Group results from continuing operations.

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Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to euro 8,783 million for 2015. The loss of the discontinued operations pertaining to Eni’s shareholders was affected by the recognition of impairment losses on the disposal groups Saipem and Versalis, the net assets of which were aligned to the lower of their carrying amounts and fair value. Eni’s net assets in Saipem and Versalis were aligned respectively to the share price at the reporting date and the likely outcome of the industrial agreement, which is being evaluated in the negotiations currently underway, resulting in an overall impairment charge of euro 1,969 million. Partly offsetting, a fair-valued derivative gain of euro 49 million was recorded for Saipem due to the difference between the transaction price (euro 8.39 per share) and the market price at the reporting date (euro 7.49 per share) for the stake disposed of to FSI. On January 22, 2016, following the closing of the Saipem transaction, the residual interest in the former subsidiary was initially recognized as investment in a joint venture and was aligned at the market price at closing of euro 4.2 per share with a charge through profit and loss of euro 441 million. This charge will be recognized in the Company’s consolidated accounts for the first quarter 2016 among gains and losses pertaining to discontinued operations. Subsequently, in February 2016 Saipem’s market capitalization has fallen sharply and management believes that this trend will constitute an impairment indicator which management will review when evaluating the recoverability of the net book value of Eni’s interest in Saipem. Under the provisions of IAS 10 these negative developments do not constitute adjusting events of the Saipem valuation made in the 2015 accounts which aligned the Saipem carrying amount to the market price at December 31, 2015.

2014 compared to 2013. Net profit attributable to Eni’s shareholders from continuing operations in 2014 was euro 101 million, a decrease of euro 3,371 million from 2013, or 97%. The decrease is explained by several factors. First, 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 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 573 million, or 37.4%) 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
(ii)	a euro 280 million net loss on the fair-valued interests in Galp and Snam which were then 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 168 million in 2013 (down by euro 389 million), which was partially offset by the lower 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 segment operating performance (up euro 2,987 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 2,374 million) mainly due to a reduction of taxable profit in the Exploration & Production segment.

 

Discontinued operations

The table below sets forth net profit (loss) attributable to discontinued operations for the periods indicated.

	Year ended December 31,

		2013		2014		2015

(euro million)

Net profit - discontinued operations		1,063			658			(2,251	)
attributable to:
- Eni		1,688			1,190			(1,103	)
- non-controlling interest		(625	)		(532	)		(1,148	)

Eni’s share of the loss of the discontinued operation was euro 1,103 million. This was primarily due to impairment losses, which were recognized in order to align Eni’s net assets in Saipem and Versalis to fair value (euro 1,969 million

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in the operating profit). Furthermore in 2015, Saipem reported an operating loss of euro 694 million, down by euro 712 million from the operating profit of euro 18 million incurred in 2014. This was driven by the recognition in the first half of the year of write-down of accrued revenues on contracts under execution and trade receivables, reflecting the deteriorating competitive environment in the oil service sector, as well as the impairment loss on the alignment of its net assets to the share price at the reporting date. Eni’s Chemical segment reported an operating loss of euro 1,393 million, up by euro 689 million from the operating loss of euro 704 million incurred in 2014. The loss was affected by the recognition of an impairment loss to align the carrying amounts of Eni’s net assets in Versalis to the fair value estimated through the planned sale transaction, which is being evaluated in the negotiations currently underway, and other charges. Excluding gains and charges, Versalis underlying business trends improved from a year ago by euro 655 million to a profit of euro 308 million.

Based on the accounting of IFRS 5 for disposal groups, gains and losses pertaining to the discontinued operations include only those earned from transactions with third parties, while gains and losses on intercompany transactions have continued being eliminated because both Saipem and Versalis were fully consolidated subsidiaries at the 2015 reporting date. Regarding Saipem, revenues recorded by this entity for the supply of capital goods and maintenance services to Eni’s Group companies are eliminated upon consolidation, which has positively affected results of the continuing operations. Vice versa, revenues earned by the Group operating companies, mainly in the R&M segment, for the supply of oil-based chemical feedstock to Versalis are eliminated upon consolidation, thus negatively affecting results of the continuing operations. Considering that following the closing of the Saipem transaction, this entity is due to be derecognized from January 22, 2016, going forward results of the continuing operations will be negatively affected by the elimination of intercompany revenues towards the Chemical business, until loss of control over it and derecognition.

 

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 68,945 million, euro 94,226 million and euro 99,664 million for the years ended December 31, 2015, 2014 and 2013, 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 67,740 million, euro 93,187 million and euro 98,547 million for the year ended December 31, 2015, 2014 and 2013, respectively, and its other income and revenues totaled euro 1,205 million, euro 1,039 million and euro 1,117 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,

		2013		2014		2015

(euro million)

Exploration & Production		31,264			28,488			21,436
Gas & Power		79,619			73,434			52,096
Refining & Marketing		27,201			24,330			18,458
Corporate and Other activities		1,496			1,429			1,468
Impact of unrealized intragroup profit elimination (1)		18			54			-
Consolidation adjustment (2)		(41,051	)		(34,548	)		(25,718	)
NET SALES FROM OPERATIONS		98,547			93,187			67,740

---

2015 compared to 2014. Eni’s net sales from operations (revenues) from continuing operations for 2015 (euro 67,740 million) decreased by euro 25,447 million from 2014 (or down 27.3%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms due to significantly lower commodity prices. This negative trend was

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partially offset by a favorable exchange rate environment and increased sales volumes in the Exploration & Production segment, as well as higher Eni’s refining throughputs.

Revenues generated by the Exploration & Production segment (euro 21,436 million) decreased by euro 7,052 million (or down 24.8%) due to lower oil&gas realizations in dollar terms (down by 44.3% on average) reflecting the lower price for the marker Brent and lower gas prices in Europe and in the United States partially offset by higher production sold. Lowered hydrocarbons realizations in dollars reduced reported revenues by approximately euro 12 billion. This effect was partly offset by favorable exchange rate differences in translating dollar-denominated revenues into the euro representation currency for euro 3.3 billion and higher production volumes sold for euro 1.6 billion. The negative price impact was mainly recorded at concession contracts, while PSA contracts are insulated from the scenario due to the cost recovery mechanism.

Revenues generated by the Gas & Power segment (euro 52,096 million) decreased by euro 21,338 million (or down 29.1%). The reduction reflected lower commodity prices in the business of crude oil and refined products trading, which impact was however offset by a corresponding decrease in the supply costs of the commodities. Furthermore, gas selling prices continued to deteriorate reflecting, in addition to the commodity price environment, weak gas demand and increasing competitive pressure. Revenues were also impacted an estimate revision of revenues accrued on the sale of gas (euro 346 million) and power (euro 138 million) to retail customers in Italy dating back to the past reporting periods.

Revenues generated by the Refining & Marketing segment (euro 18,458 million) decreased by euro 5,872 million (or down 24.1%) mainly reflecting lower average sales prices products driven by lower commodity prices.

2014 compared to 2013. Eni’s net sales from operations (revenues) from continuing operations for 2014 (euro 93,187 million) decreased by euro 5,360 million from 2013 (or down 5.4%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms and decreased sales volumes in the Gas & Power and Refining & Marketing segments. Exchange rates movements did not impact reported revenues as the average euro vs. U.S. dollar exchange rate was unchanged year-on-year.

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&gas realizations in dollar terms (down by 8.9% on average).

Revenues generated by the Gas & Power segment (euro 73,434 million) decreased by euro 6,185 million (or down 7.8%) 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 24,330 million) decreased by euro 2,871 million (or down 10.6%) 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.

 

b) Operating expenses

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

	Year ended December 31,

		2013		2014		2015

(euro million)

Purchases, services and other		78,108		74,067		53,983
Payroll and related costs		2,657		2,572		2,778
Operating expenses		80,765		76,639		56,761

2015 compared to 2014. Operating expenses from continuing operations for 2015 (euro 56,761 million) decreased by euro 19,878 million from 2014, down 25.9%, primarily reflecting lower supply costs of raw materials (natural gas under long-term contracts, refinery feedstock and hydrocarbons purchased for resale) due to underlying trends in the energy scenario partially offset by negative exchange rate effects. Purchases, services and other costs included euro 427 million relating to environmental and other risk provisions, net of reversal of unused provisions. In addition an allowance to the provision for doubtful accounts was recognized in 2015 in the retail Gas & Power business to take in account an estimate revision of revenues accrued on the sale of natural gas and electricity (euro 226 million; euro 130 million for gas sale and euro 96 million for electricity) to retail customers in Italy dating back to past reporting periods. Payroll and related costs (euro 2,778

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million) increased by euro 206 million from 2014, up 8%, due to the appreciation of the U.S. dollar against the euro. These effects were partially offset by lower average number of employees.

2014 compared to 2013. Operating expenses from continuing operations for the year (euro 76,639 million) decreased by euro 4,126 million from 2013, down 5.1%, primarily reflecting lower supply costs of raw materials (gas and refinery 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 119 million. These charges were lower than in 2013. Payroll and related costs (euro 2,572 million) decreased by euro 85 million from 2013, down 3.2%, due to a lower provision for redundancy incentives.

 

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,

		2013		2014		2015

(euro million)

Exploration & Production (1)		7,810			8,473			8,902
Gas & Power		413			335			363
Refining & Marketing		345			282			346
Corporate and Other activities		62			70			71
Impact of unrealized intragroup profit elimination (2)		(25	)		(26	)		(28	)
Total depreciation, depletion and amortization		8,605			9,134			9,654
Impairments		2,356			1,013			4,826
		10,961			10,147			14,480

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2015 compared to 2014. In 2015, depreciation, depletion and amortization charges (euro 9,654 million) increased by euro 520 million from 2014, or 5.7%, mainly in the Exploration & Production segment (increasing by euro 429 million) reflecting the appreciation of the U.S. dollar against the euro and higher production volumes partially offset by lower exploration expenses.

In 2015, impairment charges of euro 4,826 million related to oil&gas properties (euro 4,502 million) driven by the projections of lower hydrocarbon prices in the medium to long-term, which affected their recoverable amounts. The most notable impairments refer to certain assets, which were acquired by the Group following business combinations in previous reporting periods (Algeria, Congo and Turkmenistan) and to CGUs which are currently operating in high-cost areas (United States, United Kingdom, Norway and Angola). Furthermore, investments made for compliance and stay-in-business purposes were written off at cash generating units previously written-off in the Refining & Marketing business, which were confirmed to lack any prospects of profitability. Finally, impairment losses were recorded at the Group power plants in the G&P segment due to a weak margins scenario.

2014 compared to 2013. In 2014, depreciation, depletion and amortization charges (euro 9,134 million) increased by euro 529 million from 2013, or 6.2%, 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 1,013 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); and (ii) 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 segment (euro 25 million) at certain marginal lines of business due to lack of profitability.

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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,

		2013		2014		2015

(euro million)

Exploration & Production		14,868			10,766			(144	)
Gas & Power		(2,923	)		64			(1,258	)
Refining & Marketing		(1,534	)		(2,107	)		(552	)
Corporate and Other activities		(736	)		(518	)		(497	)
Impact of unrealized intragroup profit elimination		(1,808	)		(620	)		(330	)
Operating profit (loss)		7,867			7,585			(2,781	)

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,

		2013		2014		2015

(%)

Exploration & Production		47.6			37.8			(0.7	)
Gas & Power		(3.7	)		0.1			(2.4	)
Refining & Marketing		(2.7	)		(8.7	)		(3.0	)
Corporate and Other activities		(49.2	)		(36.2	)		(33.9	)
Group		8.0			8.1			(4.1	)

Exploration & Production. In 2015, the Exploration & Production segment reported an operating loss of euro 144 million, with a decrease of euro 10,910 million from 2014. The decline was principally due to reduced oil&gas realizations in dollar terms (down 44.3% on average) and increased impairment charges (up by euro 3,812 million). The negative impacts were only partially offset by a favorable exchange rate environment, higher production volumes, reduced operating expenses and lower exploration expenses.

In 2015, the Company’s liquids and gas realizations decreased on average by 44.3% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude price decreased by 47%). Eni’s average oil realizations decreased on average by 47.8%. Eni’s average gas realizations decreased by 33.8%.

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&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%.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the E&P segment reported a Non-GAAP operating profit of euro 4,108 million, with a decrease of euro 7,443 million from 2014, or 64.4% (in 2014 operating profit amounted to euro 11,551 million). The decrease was driven by sharply lower commodity prices, the effects of which was partly counterbalanced by higher production volumes, cost efficiencies and lower exploration expenses.

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	Year ended December 31,

		2013		2014		2015

Exploration & Production

(euro million)

Non-GAAP operating profit (loss)		14,643			11,551			4,108
Impairment losses		(19	)		(692	)		(4,502	)
Risk provisions		(7	)		5			0
Net gains on disposal of assets		283			76			414
Provision for redundancy incentives		(52	)		(24	)		(15	)
Fair value on commodity derivatives		2			28			(12	)
Reclassification of currency derivatives and translation effects to management measure of business performance		2			(6	)		59
Other		16			(172	)		(196	)
Total gains and charges		225			(785	)		(4,252	)
GAAP operating profit (loss)		14,868			10,766			(144	)

Gas & Power. In 2015, the Gas & Power segment reported an operating loss of euro 1,258 million, down by euro 1,322 million from 2014 when the segment reported an operating profit of euro 64 million. The change reflected one-off gains associated to certain contracts renegotiation recorded in 2014 as well as the negative outcome of a commercial arbitration in 2015. Furthermore, the 2015 result was affected by an estimate revision of revenues accrued on the sale of gas and power (euro 484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (euro 226 million). Management estimates revenues accrued in the retail sales business utilizing data communicated by market operators that are responsible for verifying actual consumptions with the possibility to review their measurements until the fifth subsequent reporting period.

In 2014, the Gas & Power segment reported an operating profit of euro 64 million, with an improvement of euro 2,987 million from 2013 when this segment reported an operating loss of euro 2,923 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 2,301 million mainly driven by euro 1,685 million of impairment losses (euro 25 million in 2014).

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating loss of euro 126 million, with an increase of euro 294 million from 2014 (in 2014 this segment reported an operating profit of euro 168 million).

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 in 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 explaining year-on-year charges and in evaluating the business performance management believes that is appropriate to identify the fair value of commodity derivatives because they relate to transactions that will close in subsequent reporting periods or we estimate the portion of gains and losses on the settlement of certain commodity derivatives which underlying physical transaction has yet to be settled with the delivery of the underlying commodity. Furthermore, albeit the Group classifies within net financial expense those gains and losses on currency derivatives, as well as on the alignment of trade receivable and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and alignment differences of our trade payables and receivables as part of the underlying business performance.

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	Year ended December 31,

		2013		2014		2015

Gas & Power

(euro million)

Non-GAAP operating profit (loss)		(622	)		168			(126	)
Profit (loss) on stock		(192	)		119			(132	)
Impairment losses		(1,685	)		(25	)		(152	)
Risk provisions		(292	)		42
Allowance for doubtful accruals in the retail G&P								(226	)
Provision for redundancy incentives		(10	)		(9	)		(6	)
Fair value gains/losses on commodity derivatives		(317	)		38			(90	)
Reclassification of currency derivatives and translation effects to management measure of business performance		218			(205	)		9
Revision of estimated revenues accruals in the retail G&P								(484	)
Other		(23	)		(64	)		(51	)
Total gains and charges		(2,301	)		(104	)		(1,132	)
GAAP operating profit (loss)		(2,923	)		64			(1,258	)

Refining & Marketing. In 2015, the Refining & Marketing segment reported an operating loss of euro 552 million, thereby reducing operating losses by euro 1,555 million compared to 2014, when this segment reported an operating loss of euro 2,107 million.

The losses reported in 2014 and in 2015 were due to inventory write-down of euro 1,576 million (pre-tax) in 2014, and of euro 555 million in 2015, as a consequence of the fall in oil commodity prices.

Both of the losses included a charge to align the net book value of inventories to their net realizable value at the reporting date, as well as the difference between the current cost of supplies and the one used for IFRS inventory accounting based on the weighted average cost.

Results in 2015 improved compared to 2014 also for a positive refining scenario. The Eni benchmark for refining margins (Standard Eni Refining Margin - SERM) improved from 3.2 $/BBL to 8.3 $/BBL. Results benefited from initiatives to optimize operations, to reduce costs and to improve energy efficiency.

In 2014, the Refining & Marketing segment reported an operating loss of euro 2,107 million, down by euro 573 million, or 37.4%, from 2013 when a loss of euro 1,534 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 220 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 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

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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 reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the R&M segment reported a Non-GAAP operating profit of euro 387 million, with an improvement of euro 452 million from 2014 (in 2014 this segment reported an operating loss of euro 65 million).

We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies.

	Year ended December 31,

		2013		2014		2015

Refining & Marketing

(euro million)

Non-GAAP operating profit (loss)		(472	)		(65	)		387
Profit (loss) on stock		(220	)		(1,576	)		(555	)
Environmental provisions		(93	)		(111	)		(116	)
Impairment losses		(633	)		(284	)		(152	)
Net gains on disposal of assets		9			2			5
Risk provisions								(7	)
Provision for redundancy incentives		(91	)		4			(5	)
Fair value gains/losses on commodity derivatives		(1	)		(38	)		(72	)
Reclassification of currency derivatives and translation effects to management measure of business performance		(30	)		(14	)
Other		(3	)		(25	)		(37	)
Total gains and charges		(1,062	)		(2,042	)		(939	)
GAAP operating profit (loss)		(1,534	)		(2,107	)		(552	)

Corporate and Other activities. These activities are mainly cost centers comprising holdings and treasury, headquarters, central functions like information technology, human resources, self-insurance activities, as well as the Group environmental clean-up and remediation activities performed by the subsidiary Syndial.

The aggregate Corporate and Other activities reported an operating loss of euro 497 million in 2015 representing a decrease of euro 21 million from 2014, or 4.1%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures.

The aggregate Corporate and Other activities reported an operating loss of euro 518 million in 2014 representing a decrease of euro 218 million, compared to the loss recorded in 2013 (euro 736 million), mainly reflected the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures.

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e) Net finance expenses

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

	Year ended December 31,

		2013		2014		2015

(euro million)

Gain (loss) on derivative financial instruments		(92	)		165			160
Exchange differences, net		24			(408	)		(351	)
Net income from financial activities held for trading		4			24			3
Interest income		39			19			19
Finance expense on short and long-term debt		(887	)		(871	)		(838	)
Finance expense due to the passage of time		(240	)		(292	)		(291	)
Other finance income and expense, net		(13	)		25			(184	)
		(1,165	)		(1,338	)		(1,482	)
Finance expense capitalized		166			157			159
		(999	)		(1,181	)		(1,323	)

2015 compared to 2014. In 2015, net finance expenses were euro 1,323 million, up by euro 142 million compared to 2014. The higher gains on derivatives on exchange rate (up euro 45 million) which did not meet the formal criteria to be designated as hedges under IFRS were more than offset by the negative effect of the impairment of receivables and securities for financing operating activities related to a Nigerian project following the revision of the commodity price scenario. The balance of net expenses was helped by a reduction in the liability relating to the fair-valued options (euro 33 million) embedded in the convertible bond relating to Snam shares. The reduction reflected the exercise of the option to convert the bond in Snam shares for approximately 6% of the share capital of the investee, with the remaining portion of the bond corresponding to approximately 2% of the share capital closer to maturity.

2014 compared to 2013. In 2014, net finance expenses were euro 1,181 million, up by euro 182 million compared to 2013 reflecting negative change in exchange rate differences amounting to euro 384 million, partly offset by gains on the fair value evaluation on certain derivative instruments (euro 165 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 142 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.

 

f) Net income from investments

2015 compared to 2014. Net income from investments in 2015 was a net gain of euro 124 million and mainly related to: (i) dividends received from entities accounted for at cost (euro 402 million), relating to Nigeria LNG Ltd (euro 222 million) and Snam SpA (euro 72 million); (ii) gains on disposal of investments (euro 164 million) which related to a gain recorded on the sale of an 8% interest in Galp (euro 98 million), gains on the divestment of a 6.03% interest in Snam (euro 46 million), gains on the divestment of refining infrastructures in Eastern Europe (euro 70 million), as well as the loss (euro 47 million) related to the divestment of minor assets in the Gas & Power business in Argentina; and (iii) other net gains including the alignment to stock price at December 31, 2015 of the Snam stock prices pertaining to Eni after the exercise of the conversion right by the bondholders (euro 49 million calculated on the 2.22% interest owned by Eni at the closing date). Those gains were partly offset by impairment losses registered in the business: (i) E&P relating to Angola LNG Ltd amounting to euro 469 million, including production and operating costs related to the start up of liquefaction plant due to the revision of commodity scenario; and (ii) Gas & Power related to the interest on Union Fenosa Gas SA (euro 49 million).

2014 compared to 2013. Net income from investments in 2014 was a net gain of euro 469 million and mainly related to: (i) gains on disposal of investments (euro 160 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 104 million), mainly in the Exploration & Production and Gas & Power segments; and (iii) dividends received from entities accounted for at cost (euro 384 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".

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g) Taxes

2015 compared to 2014. In 2015, income taxes amounted to euro 3,147 million, down by euro 3,534 million compared to 2014, or 52.9%, mainly reflecting lower income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to a declining taxable profit. In spite of the fact that in 2015 Eni’s group pre-tax earnings were a loss, the Group incurred a net tax expense. This negative development was influenced by a higher tax rate in E&P. The main drivers of this were three. First, the segment’s taxable profit was mainly earned in PSA contracts, which, although more resilient in a low-price environment due to the cost recovery mechanism, nonetheless bear higher-than-average rates of tax. Secondly, there was higher incidence of certain non-deductible expenses on the pre-tax profit lowered by the scenario. In addition, the tax rate was impacted by lower recognition of deferred tax assets relating operating losses due to a reduced profitability outlook (euro 1,058 million). The Group tax rate was also impacted by the write-off of Italian deferred tax assets and other changes of euro 885 million in the full year due to projections of lower future taxable profit at Italian subsidiaries and the reduction of the statutory tax rate from 27.5% to 24%, which was considered as substantially enacted at the reporting date. Management expects that these structural factors of the Group tax rate will continue to negatively affect the Company’s results of operations in 2016. Going forward, due to expected changes in the Group’s contract portfolio, management projects a progressive improvement in the Group tax rate.

2014 compared to 2013. In 2014, income taxes amounted to euro 6,681 million, down by euro 2,374 million compared to 2013, or 26.2%, 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.

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 97.2% in 2014 compared to 69.9% in 2013, up 27.3 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 97.2% 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.

 

 

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.

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

	Year ended December 31,

		2013		2014		2015

(euro million)

Net profit (loss) - continuing operations		3,896			192			(7,127	)
Adjustments to reconcile net profit to net cash provided by operating activities:
- amortization and depreciation charges, impairment losses and other non monetary items		8,917			10,919			15,521
- net gains on disposal of assets		(3,877	)		(99	)		(559	)
- dividends, interest, taxes and other changes		9,203			6,822			3,259
Changes in working capital related to operations		121			2,148			4,450
Dividends received, taxes paid, interest (paid) received during the period		(9,128	)		(6,820	)		(4,363	)
Net cash provided by operating activities - continuing operations		9,132			13,162			11,181
Net cash provided by operating activities - discontinued operations		1,894			1,948			722
Net cash provided by operating activities		11,026			15,110			11,903
Capital expenditures - continuing operations		(11,584	)		(11,264	)		(10,775	)
Capital expenditures - discontinued operations		(1,216	)		(976	)		(781	)
Capital expenditures		(12,800	)		(12,240	)		(11,556	)
Investments and purchases of consolidated subsidiaries and businesses		(317	)		(408	)		(228	)
Disposals		6,360			3,684			2,258
Other cash flow related to investing activities (*)		(4,224	)		21			(1,651	)
Changes in short and long-term finance debt		1,715			(628	)		2,126
Dividends paid and changes in non-controlling interests and reserves		(4,225	)		(4,434	)		(3,477	)
Effect of changes in consolidation, exchange differences and cash and cash equivalents related to discontinued operations		(40	)		78			(789	)
Change in cash and cash equivalent for the year		(2,505	)		1,183			(1,414	)
Cash and cash equivalent at the beginning of the year		7,936			5,431			6,614
Cash and cash equivalent at year end		5,431			6,614			5,200

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		(euro million)		2013		2014		2015

		Financing investments:
		- securities		(5,029	)		(19	)		(140	)
		- financing receivables		(105	)		(519	)		(343	)
				(5,134	)		(538	)		(483	)
		Disposal of financing investments:
		- securities		28			32			1
		- financing receivables		1,125			92			182
				1,153			124			183
		Net cash flows from financing activities		(3,981	)		(414	)		(300	)

 

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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,

		2013		2014		2015

(euro million)

Net cash provided by operating activities		11,026			15,110			11,903
Capital expenditures		(12,800	)		(12,240	)		(11,556	)
Acquisitions of investments and businesses		(317	)		(408	)		(228	)
Disposals		6,360			3,684			2,258
Other cash flow related to capital expenditures, investments and divestments		(243	)		435			(1,351	)
Net borrowings (1) of acquired companies		(21	)		(19	)
Net borrowings (1) of divested companies		(23	)					83
Exchange differences on net borrowings and other changes		349			(850	)		(810	)
Dividends paid and changes in non-controlling interest and reserves		(4,225	)		(4,434	)		(3,477	)
Change in net borrowings (1)		106			1,278			(3,178	)
Net borrowings (1) at the beginning of the year		15,069			14,963			13,685
Net borrowings (1) at year end		14,963			13,685			16,863

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Analysis of certain components of Eni’s change in net borrowings

In 2015, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization and impairment charges of tangible and intangible assets (euro 14,480 million). Adjustments to net profit also included gains on disposals (euro 559 million) relating mainly to the sale of a number of oil&gas properties in Nigeria, accrued income taxes (euro 3,147 million) and interest expense (euro 667 million) more than offset by amounts actually paid (euro 4,294 million and euro 692 million, respectively). Cash-outs for income taxes were partly offset by the reimbursement and the disposal to financing institutions of certain tax receivables due to the parent company (approximately euro 900 million).

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 10,147 million). Adjustments to net profit also included gains on disposals (euro 99 million) relating mainly to the divestment of Eni’s stake in Galp and the South Stream project, income taxes (euro 6,681 million) and interest expense (euro 687 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 2015, changes in working capital were positive for euro 4,450 million as a result of: (i) a positive balance between trade receivables collected and trade payables paid (a net inflow of euro 2,662 million), which was mainly driven by a positive performance in the Gas & Power segment; (ii) decreasing inventories (a positive euro 1,228 million) as a result of the alignment of the book value of crude oil and products to market prices (this item being an adjustment of the inventory loss recorded in net profit and as such is not a cash item), as well as reduced inventory levels in R&M due to optimizations measures; and (iii) a positive inflow related to other current assets and liabilities (up by euro 490 million) which mainly reflected a net positive inflow in the Gas & Power segment due to the collection of pre-paid volumes of gas under take-or-pay contracts and the collection of receivables from supplied long-term customers. These inflows were partly offset by a greater exposure of the E&P segment towards joint venture partners.

In 2014, changes in working capital generated cash flows amounting to a positive euro 2,148 million as a result of: (i) decreasing inventories (a positive euro 1,557 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 449 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; and (iii) a positive inflow related to other current assets and liabilities (up by euro 360 million) which

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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.

 

b) Investing activities

	Year ended December 31,

		2013		2014		2015

(euro million)

Exploration & Production		10,475			10,524			10,234
Gas & Power		229			172			154
Refining & Marketing		672			537			408
Corporate and Other activities		211			113			64
Impact of unrealized intragroup profit elimination		(3	)		(82	)		(85	)
Capital expenditures - continuing operations		11,584			11,264			10,775
Capital expenditures - discontinued operations		1,216			976			781
Capital expenditures		12,800			12,240			11,556
Acquisition of investments and businesses		317			408			228
		13,117			12,648			11,784
Disposals		(6,360	)		(3,684	)		(2,258	)

Capital expenditures totaled euro 11,556 million and euro 12,240 million, respectively in 2015 and in 2014.

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 228 million in 2015 and euro 408 million in 2014. In 2015, they comprised loans made to certain Eni’s joint ventures and associates (in particular Angola LNG Ltd for euro 123 million) which are executing oil&gas projects participated by Eni.

In 2015, disposals amounted to euro 2,258 million and mainly related to: (i) the divestment of an available-for-sale interest in Snam due to exercise of the conversion right by bondholders (euro 911 million); (ii) an available-for-sale interest in Galp Energia (euro 658 million) in order to reimburse an out-of-the-money convertible bond which was due in 2015; and (iii) the divestment of non-strategic assets in the Exploration & Production and in the R&M segments.

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.

 

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

In 2015, dividends paid and changes in non-controlling interests and reserves (euro 3,477 million) mainly related to: (i) cash dividends to Eni shareholders (euro 3,457 million, of which euro 1,440 million relating to 2015 interim dividend and euro 2,017 million to the balance dividend for fiscal year 2014); and (ii) the distribution of dividends to non-controlling interests by other consolidated subsidiaries (euro 21 million).

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).

 

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

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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 5,028 million as of end of 2015 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,

		2013		2014		2015

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)		4,685			20,875		25,560			6,575			19,316		25,891			8,383			19,393		27,776
Cash and cash equivalents		(5,431	)				(5,431	)		(6,614	)				(6,614	)		(5,200	)				(5,200	)
Securities held for trading and other securities held for non-operating purposes		(5,037	)				(5,037	)		(5,037	)				(5,037	)		(5,028	)				(5,028	)
Non-operating financing receivables		(129	)				(129	)		(555	)				(555	)		(685	)				(685	)
Net borrowings		(5,912	)		20,875		14,963			(5,631	)		19,316		13,685			(2,530	)		19,393		16,863

 

	As of December 31,

		2013		2014		2015

Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS		(euro million)		61,049			62,209			53,669
Ratio of total debt to total shareholders’ equity including non-controlling interest				0.42			0.42			0.52
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest				(0.17	)		(0.20	)		(0.20	)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage)				0.25			0.22			0.31

In 2015, net borrowings amounted to euro 16,863 million, representing a euro 3,178 million increase from 2014 as a result of net cash provided by operating activities of continuing operations (euro 11,181 million) and proceeds from disposals of euro 2,258 million which funded part of the cash outflows relating to capital expenditures from continuing operations totaling euro 10,775 million, investments (euro 228 million) and other cash-out associated with investing activities (euro 1,351 million), dividend payments amounting to euro 3,477 million and negative exchange rate differences and the reclassification of Saipem net cash in the discontinued operations.

The Group leverage was 0.31 at December 31, 2015 reporting an increase from 0.22 as of the end of 2014.

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Total equity decreased by euro 8,540 million from December 31, 2014. This was due to comprehensive income for the year (euro 5,032 million) as a result of net loss (euro 9,378 million), partially offset by positive foreign currency translation differences (euro 4,534 million) in translating to euros the net equity of subsidiaries whose functional currency is the U.S. dollar due to the depreciation in the EUR/USD exchange rates recorded at year end (down by 10.3% due to the exchange rate recorded on December 31, 2015 at 1.089 euro compared to 1 euro = 1.214 US$ at December 31, 2014). Total equity was also negatively affected by dividend payments to Eni’s shareholders and other changes for euro 3,478 million.

Total debt of euro 27,776 million consisted of euro 8,383 million of short-term debt (including the portion of long-term debt due within twelve months equal to euro 2,671 million) and euro 19,393 million of long-term debt.

Total debt included unsecured bonds for euro 17,608 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 1,569 million (including accrued interest and discount). Bonds issued in 2015 amounted to euro 1,752 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (89%), U.S. dollar (6%), british pound (4%) and 1% in other currencies.

 

Capital expenditures by segment

Exploration & Production. In 2015, capital expenditures of the Exploration & Production segment amounted to euro 10,234 million, mainly related to the development of oil and gas reserves (euro 9,341 million). Significant expenditures were directed mainly outside Italy, in particular Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia and the United States. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri, as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to euro 820 million were directed outside Italy, in particular in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia.

In 2014, capital expenditures of the Exploration & Production segment amounted to euro 10,524 million, mainly related to the development of oil&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.

Gas & Power. In 2015, capital expenditures in the Gas & Power segment totaled euro 154 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (euro 69 million) and to develop the gas marketing activity (euro 69 million).

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).

Refining & Marketing. In 2015, capital expenditures in the Refining & Marketing segment amounted to euro 408 million and regarded mainly: (i) refining activities in Italy and outside Italy (euro 282 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; and (ii) upgrading and rebranding of the refined product retail network in Italy (euro 75 million) and in the Rest of Europe (euro 51 million).

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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Recent developments

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

		Three months ended Dec. 31,		Three months ended March 31,

		2015		2015		2016

Average price of Brent dated crude oil in U.S. dollars (1)		43.69			53.97		33.89
Average price of Brent dated crude oil in euro (2)		39.90			47.93		30.75
Average EUR/USD exchange rate (3)		1.095			1.126		1.102
Standard Eni Refining Margin (4)		6.56			7.56		4.18
Euribor – three month euro rate % (3)		(0.1	)		0.1		(0.2	)

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(1)		Price per barrel. Source: Platt’s Oilgram.
(2)		Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).
(3)		Source: ECB.
(4)		In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.

In the first quarter of 2016 Brent crude oil price was approximately 34 $/BBL on average, 37% lower than in the first quarter of 2015 and 22% lower than in the fourth quarter 2015. This trend will negatively affect reported revenues, profitability and cash flow of our Exploration & Production segment.

 

Significant transactions

On January 22, 2016, Eni closed the transaction to divest a 12.503% stake in Saipem share capital to FSI. Concurrently, a shareholder agreement between Eni and FSI entered into force which established joint control over the former Eni’s subsidiary. Effective January 1, 2016, Saipem assets and liabilities, revenues and expenses will be derecognized from the Group consolidated accounts. By the end of February 2016, Saipem has reimbursed the financing receivables due to Eni and the Group net borrowings has improved by approximately euro 4.8 billion. That amount includes the proceeds on the disposal of the interest in Saipem to FSI for euro 0.46 billion and Eni’s pro-quota subscription of Saipem’s share capital increase for euro 1.07 billion.

The Company’s Annual General Shareholders Meeting scheduled on May 12, 2016, has been convened to approve the full year dividend proposal of euro 0.80 per share. Eni expects to pay the balance of the dividend for fiscal year 2015 amounting to euro 0.40 per share in May 2016. The total cash out is estimated at approximately euro 1.5 billion.

 

 

Management’s expectations of operations

The Company expects the global macroeconomic outlook for 2016 to be characterized by a number of risks and uncertainties, mainly due to the continued slowdown in China’s industrial activity, in the Eurozone and in other commodity-exporting countries. After hitting multi-year lows of below 30 $/BBL in January 2016, the price of crude oil is expected on a weak trend due to structural imbalances in the marketplace driven by oversupply and renewed uncertainties surrounding the pace of future energy demand growth in the medium and long term.

Based on this macroeconomic outlook, Eni’s management has revised downwards its pricing assumptions of the Brent crude oil marker utilized in each of the periods in the Company’s strategic plan 2016-2019: particularly the long-term reference price has been reduced to 65 $/BBL, down from the 90-dollar case utilized in the previous planning assumptions.

In the Gas & Power segment, management anticipates a challenging environment pressured by weak demand growth and oversupplies. The Company confirms its strategy to renegotiate long-term supply contracts in order to align the supply terms with market conditions, as well as boost profitability in its high-value businesses (LNG, gas retail and trading). In R&M, management expects still profitable refining margin, although lower than in 2015. In this context,

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business strategies will be focused on the optimization of refinery processes at the existing plants, the ramp up of Venice green refinery, cost efficiency, as well as the enhancement of marketing results.

 

Exploration & Production

In order to cope with the anticipated negative impact of a depressed oil scenario on the Exploration & Production segment results of operations and cash flow, management is planning to increase efforts to optimize capital expenditure and reduce operating costs by exploiting the deflationary pressure induced by the fall in crude oil prices, as well as to grow production profitably. Furthermore, in order to meet our priority of preserving cash generation, we are planning to divest a few stakes in our main discoveries achieved in the latest years, in line with our "dual exploration model", and to dispose of non-strategic assets.

We expect the outlook for the production of liquids and natural gas to be favorable in 2016 and across the plan period. In 2016, we expect production to be flat year-on-year due to new fields start-ups, particularly in Norway, Egypt, Angola, Kazakhstan and the United States, and the ramp-up of fields started in 2015 which will offset decline at mature fields and one-off production increases recorded in 2015. Overall, we plan to grow production at an average rate in excess of 3% across the plan period 2016-2019, driven by the start-ups of new fields and production ramp ups that will add more than 800 KBOE/d in 2019. The main start-ups include the Zohr gas field offshore Egypt, Goliat in the Barents Sea, the re-start of the Kashagan field late in 2016, the oil&gas project of Offshore Cape Three Points in Ghana, the East Hub in Block 15/06 off Angola and the Jangkrik project in Indonesia in 2017. We believe that those production targets have good visibility because they related to already-sanctioned projects where we are operator. This forecast includes assumptions relating to production levels in Libya and Nigeria which are exposed to risks of disruptions and political instability. In 2015, our production in Libya represented approximately 20% of the Group total hydrocarbons productions for the year and going forward the contribution of Libya to our future production levels albeit slowing down will still remain significant. To factor in possible risks of unfavorable geopolitical developments mainly in Libya but also elsewhere in other countries of Eni presence, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, social unrest, clashes and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. However, this contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shut down. Our production plans are incorporating our Brent price scenario of 40 $/BBL in 2016 and a gradual recovery in the subsequent years up to our long-term case of 65 $/BBL in 2019 and going forwards (on constant monetary term compared to 2019, i.e. from 2020 onwards crude oil prices will grow in line with a projected inflationary rate). See "Item 4 – Exploration & Production". Our recovery assumptions are based on a progressive market rebalancing due to the expected cuts in the capital plans of the international oil companies, the exit of marginal producers and a moderate strengthening of global economy.

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 vary on average by approximately 1,500 BBL/d for each $1 change 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.

In order to mitigate the expected negative impact of lower oil prices in the short to medium term and to achieve an appropriate balance between cash inflows and outflows, the Company is planning to implement a number of initiatives intended to rationalize and optimize our capital expenditures and to lower the segment operating costs. We are targeting to reduce the capital budget without hampering production growth and to improve the breakeven price of our development projects. The first course action will be adoption of 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. Secondly, we plan to renegotiate contracts for the supply of upstream plants, equipment, productions vessels and other infrastructures as well as the supply of oilfield services and drilling rates to align input costs to the changed market conditions, leveraging on the deflationary pressure induced by falling oil prices. Finally, we will be more selective in exploration initiatives by prioritizing projects near fields, in proven areas, and in appraisal activities in order to ensure fast reserve replacement and quick contribution to cash generation. In the 2016-2019 four-year plan, we target a decrease of 18% of capital expenditures in Exploration & Production from the previous plan at constant exchange rates, due to a reduction in exploration expenditures, project re-phasing and contract renegotiations and in spite of the inclusion of the planned expenditures to develop the big Zohr gas field offshore Egypt. In addition, Eni intend to reduce unitary operating costs by 11% in 2016 compared to 2015.

Management will focus on delivering the planned projects on time and on budget. Some of our projects are complex due to scale and reach of operations, environmentally-sensitive 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

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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 90% 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 these wells will represent approximately 20% of the planned wells to be drilled in 2016.

 

Gas & Power

We expect a weak outlook for natural gas sales and prices due to structural headwinds in the industry as we forecast sluggish demand growth, oversupplies and strong competition across all of our main markets in Europe, including Italy. 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 remain at depressed levels.

One of the main weaknesses in the gas sector will continue to be the thermoelectric sector, which we believe will show limited improvements in the future, absent a clear and harmonized supranational system of tariffs on CO₂ emissions. 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) will negatively influence gas consumption in the production of power. Furthermore, the evolution of the industrial sector towards low energy-intensity setups and energy efficiency and preservation will limit the recovery in gas demand. We estimated that gas consumption in Europe have decreased by 4% on average in the 2010-2015 timeframe and we forecast an average growth rate lower than 1% from 2016 to 2025. On the supply side, the growing importance of liquid hubs and large availability of LNG will drive continuing competition and pricing pressure. Going forward LNG supplies will be fuelled by the come on stream of several export terminals in the United States which will monetize the Country’s large reserves of shale gas and the start-up of important LNG projects in the Pacific area. These trends are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses whereby 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 and dynamics, the development of our portfolio of highly profitable businesses and cost efficiencies and operational streamlining.

Our take-or-pay, long-term supply contracts include revisions clauses whereby each counterpart has right to renegotiate the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Our portfolio of supply contracts is indexed to hub benchmarks for around 70% of the underlying volumes. We expect to realize the alignment of our supply portfolio to market conditions by 2017. 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. The renegotiation strategy is subject to the constraints dictated by availability of the contractual windows. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will ultimately be achieved and the timing of recognition in profit. In case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration procedure could be 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. The expected termination of certain long term gas supply contracts with take-or-pay clause will reduce Eni’s contractual minimum take and will add flexibility to Eni’s

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portfolio and renegotiation strategy. Lastly we plan to substantially complete the recovery of the take-or-pay cash advances along the plan period leveraging on contract renegotiations, which may improve the competitiveness of our gas, and optimization of our sales programs. Cash advances outstanding at the end of fiscal year 2015 amounted to approximately euro 0.4 billion and they were more than halved in the course of 2015 (the amount outstanding as of December 31, 2014 was euro 0.9 billion).

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. We expect margins in the LNG business to normalize going forward with respect to the strong level recorded in 2015 and will be influenced by the projected lower supply costs of gas imports in the Far East, which are oil-linked. We will seek to preserve margins on sales to large accounts by leveraging on the Company’s multiple presence across various markets and expertise in delivering innovative and tailor-made offering structures to best suit customers’ needs by providing complex pricing formulas, hedging against the commodity risk and flexibility in volumes collection (see "Item 4 – Gas & Power"). The Company’s marketing effort will address retail customers across Europe with a view to enhancing the existing customer base against the backdrop of escalating competitive pressures. 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, general and administrative costs. Management intends to dedicate a strong focus on rationalizing logistic costs by increasing the trade of underused transport capacity and reselling it to other operators and by exploiting expected liberalization measures in the European gas system where we expect a reducing fee to entry new markets. Finally, the termination of certain contractual commitments will enable Eni to gain flexibility and improve its competitive position.

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, unutilized power capacity). This can be achieved through strategies of asset-backed trading by entering into derivative contracts to leverage on commodity price volatility, the risks of which might be absorbed in part or entirely by the natural hedge granted by the asset availability. Asset-backed activities may lead to gains, as well as losses the amount of which could be significant. For further information on the market risk and how the Company manages it see "Item 11 – Quantitative and Qualitative Disclosures about Market Risk".

Based on the above outlined trends and industrial actions, management expects that we will retain profitable, cash-positive operations in the Company’s gas marketing business over the plan period. Our profitability outlook factors in the expected benefits of ongoing renegotiations of the Company long-term supply contracts which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3. 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".

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 refining margins in 2016 and in the following will decline toward a mid-cycle level lower than the exceptionally strong value recorded in 2015. We believe that the European refining industry will continue to suffer from structural weaknesses due to a persistent refining overcapacity related to economic stagnation, increasing efficiency in final uses and rising competitive pressure from new refineries in the Middle East.

In view of this scenario, the Company priority is to strengthen profitability and cash flow even in a depressed downstream oil environment further reducing the breakeven margin of Eni refineries which currently stands at about 5 $/BBL. The refining business has undergone a restructuring process resulting in a reduction of the installed capacity by 33% versus the 2012 baseline. This process has comprised the conversion of the Venice refinery into a green refinery for the production of bio-fuels based on a proprietary technology, the shutdown of Gela refinery, which is undergoing a restructuring to be upgraded to a green refinery like the Venice site, the disposal of a 32.445% interest in

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Ceská Rafinérská (CRC) and the closure of a producing line in Taranto (visbreaking-thermal cracking). We believe that the restructuring initiatives implemented so far have contributed to reduce the refining break-even margin. Looking ahead, our priority is now to further lower our break-even refining margin, maintaining the current refining capacity and leveraging on increasing the conversion capacity of our refineries, completing the ramp up of Venice green refinery and the conversion of the Gela refinery, improving product quality and flexibility and maintaining a strong focus on cost efficiency and process optimization. We intend to make selective capital expenditures expecting to invest approximately euro 1.1 billion mainly related to maintenance (stay-in-business, compliance, security and environmental purposes) and conversion projects to complete the bio refineries at Venice and Gela sites.

In Marketing activities, where we expect competitive pressure to continue due to weak demand trends, we are planning to achieve a gradual improvement in results of operations mainly by focusing on innovation of products and services anticipating customer needs, dynamic pricing tailored on the specific local market conditions, efficiency in the marketing and distribution activities.

Retail operations abroad will be focused on the core markets of Germany, Austria, Switzerland and France, exploiting synergies along the value chain, a significant market share, an effective non oil and the brand awareness. We plan to complete the divestiture of our presence in East Europe, where we already exited from Czech Republic, Romania and Slovakia in 2015 (maintaining the lubricants marketing activities).

 

Capital expenditure plans

Over the next four years, the Company plans to invest euro 37 billion, excluding capex associated with the disposal plan, to support continued organic growth in oil&gas production as more than 90% of planned capital expenditures is expected to be directed to the Exploration & Production segment.

Development of oil&gas reserves will attract some euro 33 billion. Project start-ups and plateau enhancement at existing fields will be geographically diversified and executed mainly in Egypt with the development of the very important Zohr gas discovery, Italy, Angola, Kazakhstan Congo, Nigeria, Norway, Libya and Ghana and the start of development activities in Mozambique which will target production growth beyond the plan period.

Exploration capex will amount to approximately euro 3.5 billion, intended to pursue finding projects in well established basins, proven areas and in near-field activities to ensure fast reserve replacement and a quick contribution to the cash flow.

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, by re-phasing certain large oil&gas projects which are planned to be developed along a number of stages and by renegotiating contracts for the supply of capital goods and other services in Exploration & Production. These optimizations and curtailments will drive a 21% reduction in capital expenditure compared to the previous plan at constant exchange rates. For the year 2016, we are planning euro 9.4 billion of capital expenditure, down by 20% at constant exchange rates.

Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 65 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2020 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 2015, management assessed that the cost of capital to the Group increased from the previous year mainly reflecting higher volatility of the Eni share and the planned higher weight of the equity in financing the capital employed as a result of the Saipem transaction, with a target reduction of the ratio of net borrowings to equity. These increases have been partially offset by a reduced premium for the sovereign risk incorporated into the yields on Italian ten-year bonds, and, to a lower extent, a reduced 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; (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 consensus outlook; in 2015, our average premium for the country risk was higher than in 2014 due to a deteriorated political and financial outlook of certain countries where we are conducting upstream operations; and (iii) a premium for the business risk.

 

Liquidity and leverage

In the current depressed oil price environment, management’s priority remains to preserve a solid balance sheet, to seek equilibrium between cash inflows and outflows and to avoid deterioration in the Company’s financial structure. Our target is to maintain the Company’s key ratio of net borrowings to equity – leverage – within the ceiling of 0.3. At

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the end of 2015, our leverage stood at 0.31 which was impacted by the decline in crude oil prices. However, considering that the Saipem transaction has been already fully finalized as of the date of this filing, management has estimated that the Company’s leverage at December 31, 2015 including the transaction effects, particularly the reimbursement of the intercompany financing receivables due by Saipem and other transaction effects resulting in a net borrowings reduction of approximately euro 4.8 billion, would be significantly lower than the amount reported at year end. Management believes that the target ceiling leverage is consistent with the Company’s business profile, which features an increasing exposure to the Exploration & Production segment. See "Item 4 – Business developments".

For 2016, we estimate that at 50 $/BBL our cash flow from operations would cover the Company’s funding requirements for the planned capital expenditure. In addition, considering both cash flow from operations and the expected proceeds from our planned disposals, in 2016 we estimate to be able to cover both the projected capex and the payment of the dividend at 50 $/BBL. In 2017, we expect that at 60 $/BBL we will able to fully cover with our cash flow from operations our planned capital expenditure and the dividend. These targets are reflective of the Company’s initiatives in lowering its cost base and in optimizing its capital plan without impairing its ability to pursue its growth objectives and have been lowered compared to previous assumptions by approximately 10-15 $/BBL. Finally, we expects to cover our requirements for capital expenditures and the dividend at a price lower than 60 $/BBL in 2018 and 2019, with any possible upside in crude oil prices leading us to generate additional cash flows.

During the plan period, management expects to deliver approximately euro 7 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of excess stakes in our exploration assets.

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 0.2 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, 2016 was 34 $/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 40% of the planned 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 a EUR/USD exchange rate in the range of 1.06-1.15 U.S. dollars per euro in the 2016-2019 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty, as well as a potential positive driver of the Group results of operations, cash flow and balance sheet in case the U.S. dollar appreciates against the euro. We note that in the first quarter of 2016 the EUR/USD exchange rate was 1.1 and appreciated year-on-year. 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

Considering the current weak oil price scenario, in 2015 the Company decided to rebase the annual dividend at euro 0.80 per share, which is our floor dividend with a progressive distribution policy in line with our underlying earnings growth and scenario upside. Consistently with this policy, management expects to pay a dividend of euro 0.80 per share for fiscal year 2015 subject to approval from the General Shareholders’ Meeting scheduled in May 2016. Of this, euro 0.40 per share was paid in September 2015 as an interim dividend with the balance of euro 0.40 per share expected to be paid by end of May 2016.

Currently, in spite of a deteriorated oil price environment compared to one year ago, we confirm our commitment to pay a full cash dividend for fiscal year 2016 of euro 0.80 per share thanks to the results achieved in implementing our strategy, including the disposals of non-core assets.

In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year.

The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, political instability in Libya and other countries, crude oil and natural gas prices; demand for oil&gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves;

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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 37 – 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 37 – 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		2016		2017		2018		2019		2020		2021 and thereafter

(euro million)

Total debt		31,876		12,305		3,066		2,039		3,859		2,599		8,008
Long-term finance debt		21,805		2,332		3,010		2,038		3,826		2,599		8,000
Short-term finance debt		5,712		5,712
Fair value of derivative instruments		4,359		4,261		56		1		33				8
Interest on finance debt		4,396		737		654		525		453		354		1,673
Guarantees to banks		169		169
Operating lease obligations (1)		2,353		493		397		279		203		174		807
Decommissioning liabilities (2)		17,056		423		423		408		372		351		15,079
Environmental liabilities (3)		1,545		241		238		207		179		37		643
Purchase obligations (4)		156,090		11,938		10,391		10,579		10,040		8,793		104,349
Natural gas to be purchased in connection with take-or-pay contracts (5)		144,625		9,426		8,810		9,282		8,837		8,031		100,239
Natural gas to be transported in connection with ship-or-pay contracts (5)		8,733		1,706		1,324		1,118		1,034		593		2,958
Other take-or-pay and ship-or-pay obligations		756		111		101		94		87		86		277
Other purchase obligations (6)		1,976		695		156		85		82		83		875
Other obligations (7)		133		6		4		3		2		2		116
of which:
- Memorandum of intent relating to Val d’Agri		133		6		4		3		2		2		116
Total		213,618		26,312		15,173		14,040		15,108		12,310		130,675

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(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 regasification facilities in the United States of euro 1,325 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, 2015. 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		2016		2017		2018		2019		2020 and thereafter

Committed projects

33,981

8,675

8,040

6,101

5,125

6,040

 

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 37 of the Notes on Consolidated Financial Statements".

As of December 31, 2015, Eni maintained short-term unused borrowing facilities of euro 12,748 million, of which euro 40 million committed. Long-term committed borrowing facilities amounted to euro 6,576 million, of which euro 1,000 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 20 billion, of which about euro 14.9 billion were drawn as of December 31, 2015.

 

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 37 of the Notes on Consolidated Financial Statements".

For information about credit losses in 2015 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 37 of the Notes on Consolidated Financial Statements".

 

Research and development

For a description of Eni’s research and development operations in 2015, 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 2016:

Name			Position			Year elected or appointed			Age
Emma Marcegaglia			Chairman			2014			50
Claudio Descalzi			CEO			2014			61
Andrea Gemma			Director			2014			42
Pietro A. Guindani			Director			2014			58
Karina A. Litvack			Director			2014			53
Alessandro Lorenzi			Director			2011			67
Diva Moriani			Director			2014			47
Fabrizio Pagani			Director			2014			49
Alessandro Profumo7			Director			20158			59

In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members.

The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on May 8, 2014⁹ 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 aforementioned elections. Three Directors out of nine, including the Chairman, were drawn from the less represented gender, thereby already reaching the ratio of one-third of the Directors, instead of the ratio of one-fifth as provided by the law for the first relevant election of the Board. The ratio of one-third of the Directors belonging to the less represented gender shall also apply to the next two subsequent terms of the Board of Directors.

The following provides details on the personal and professional profiles of the Directors.

Emma Marcegaglia 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. Chairman and CEO of Marcegaglia Holding SpA and Deputy Chairman and CEO of the subsidiary companies operating in the processing of steel. Chairman and CEO of Marcegaglia Investments Srl, the holding company of diversified activities of the group. She is President of Businesseurope and Luiss Guido Carli University, 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. She was Chairman of Fondazione Aretè Onlus. She was Confindustria Vice President for infrastructures, energy, transport and environment from May 2004 until May 2008 and Italian Representative in the High Level Group for energy, competitiveness and environment created by the European Commission. 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.

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Claudio Descalzi has been CEO of Eni since May 2014. Born in Milan in 1955, he graduated in physics in 1979 from the University of Milan. He is currently Member of the General Board of Confindustria 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 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 Member 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. Claudio Descalzi is a Visiting Fellow at the University of Oxford. In December 2015, he was made a member of the "Global Board of Advisors of the Council on Foreign Relations".

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 Member of the Studies Centre of the Chamber of Arbitration of Rome, Arbitrator at the Chamber of Arbitration of Public Works, Deputy Chairman of Serenissima SGR SpA and Chairman of the Watch Structure of Sorgente SpA. He is member of the Board of Directors of Banca UBAE SpA. He is member of the Board of Directors of Global Capital Plc. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA, Sequoia Partecipazioni SpA, Liquidator of Corit SpA and Sigrec SpA (Unicredit Group).

Pietro A. Guindani has been Director of Eni since May 2014. He was born in Milan in 1958. He graduated in Business at the Università Luigi Bocconi of Milan. From 1982 to 1986, he was Relationship Banker of Citibank NA 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 Italy. Currently, he is Chairman of the Board of Directors of Vodafone Italia SpA, Board Member of FINECOBank SpA, of Salini-Impregilo SpA, of Cefriel Scarl and of the Italian Institute of Technology, Board Member of Civita Foundation, Assonime and Confindustria, Member of the Executive Board of Assotelecomunicazioni, Member of the Executive Board of Confindustria Digitale, 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, and Finance and International Business from the Columbia University Graduate School of Business. 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 Incorporated. From 1991 to 1993, she was a Project Manager of the New York City Economic Development Corporation. In 1998, she joined F&C Asset Management Plc where she held the position of Analyst Ethical Research, Director Ethical Research and Director Head of Governance and Sustainable Investments (2001-2012). She was also a Member of the Board of the Extractive Industries Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012).

Alessandro Lorenzi has been 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. He began his career at SAIAG SpA, in the Administration and Control area. In 1975, he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983, he joined GFT Group where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995, he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998, he was appointed 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.

 

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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 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.

Alessandro Profumo has been Director of Eni since July 2015. He was born in Genoa in 1957. He graduated in Business Administration at the Università Luigi Bocconi of Milan. He is currently Chairman of Equita SIM, of Appeal Strategy & Finance Srl and member of the Supervisory Board of Sberbank. He is also member of the Board of Directors of TOG "Together To Go". Since February 2012 he has been appointed Member of the International Advisory Board of Itau-UniBanco. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987, he joined McKinsey where he was Project Manager in the strategy area for the finance sector. In 1989, he was appointed Head of relations with financial institutions and integrated development and organization projects at Bain, Cuneo e Associati firm (now Bain & Company). In 1991, he left the field of company consultancy to join RAS, Riunione Adriatica di Sicurtà, where he was given responsibility, as General Manager, for the banking and parabanking sectors. He was also in charge of the yield increase of that company’s bank and of the other group companies operating in the field of asset management. In 1994, he joined Credito Italiano as Joint Central Manager, with responsibility for Programming and Control, becoming General Manager in 1995. In 1997, he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On a international level he was Chairman of the European Banking Federation and Chairman of the IMC Washington. In May 2004, he was decorated as Cavaliere del Merito del Lavoro. From 2006 to 2014, he was Director of the Università Bocconi in Milan, from 2011 to 2014, he was Director of Eni and from 2012 to 2015, he was Chairman of Banca Monte dei Paschi di Siena. From 2014 to 2015, he was Chairman of CASL (Comitato per gli Affari Sindacali e del Lavoro dell’ABI). In February 2012, he was nominated member of the "High-level Expert Group" on reforming the structure of the EU banking sector; he left the Group when he was appointed Chairman of Banca Monte dei Paschi di Siena.

On July 2, 2015, Luigi Zingales resigned from the Board of Directors. The following provides information on the personal and professional profile of Luigi Zingales available to the Company as at July 2, 2015.

Luigi Zingales was Director of Eni from May 2014 to July 2, 2015. 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 Institute of Technology in Cambridge. "Robert C. McCormack Professor of Entrepreneurship and Finance" at the University of Chicago Booth School of Business. 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, 2015. 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.

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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
Luca Bertelli		Chief Exploration Officer		2014		31		57
Roberto Casula		Chief Development, Operations & Technology Officer		2014		27		53
Claudio Granata		Chief Services and Stakeholder Relations Officer		2014		32		55
Massimo Mantovani		Chief Legal & Regulatory Affairs		2014 (1)		22		52
Massimo Mondazzi		Chief Financial and Risk Management Officer		2014 (2)		23		52
Salvatore Sardo		Chief Refining & Marketing and Chemical Officer		2015 (3)		10		63
Antonio Vella		Chief Upstream Officer		2014		32		58
Umberto Vergine		Chief Midstream Gas & Power Officer		2015		31		58
Angelo Zaccari		Chief Retail Market Gas & Power Officer		2015 (4)		7		62
Marco Petracchini		Internal Audit Department Senior Executive Vice President		2011 (5)		16		51
Roberto Ulissi		Corporate Affairs and Governance Department Senior Executive Vice President Board Secretary and Corporate Governance Counsel		2006 (6)		9		53
Marco Bardazzi		External Communication Department Executive Vice President		2015		1		48
Luca Cosentino		Energy Solutions Department Executive Vice President		2015		12		54
Rita Marino		Procurement Department Executive Vice President		2014 (7)		10		51
Pasquale Salzano		Government Affairs Department Executive Vice President		2015 (8)		4		42

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(1)		Prior to July 1, 2014, he was General Counsel Legal Affairs Senior Executive Vice President.
(2)		Prior to July 1, 2014, he was Chief Financial Officer.
(3)		Prior to February 19, 2015, he was Chief Downstream & Industrial Operations Officer.
(4)		Prior to September 30, 2015, he was Retail Market G&P Department Senior Executive Vice President.
(5)		Since 2014 the Senior Executive Vice President of the Internal Audit Department reports hierarchically to the Board of Directors and, on its behalf, to the Chairman, without prejudice to its functional dependence on the Control and Risk Committee and on the Chief Executive Officer (in his capacity as Director in charge of the Internal Control and Risk Management System).
(6)		Since 2014, the Board Secretary has also served as Corporate Governance Counsel. The Board Secretary reports hierarchically and functionally to the Board of Directors and, on its behalf, to the Chairman.
(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)		Prior to February 19, 2015, he was Senior Vice President Government Affairs.

The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief Midstream Gas & Power Officer, the Chief Refining & Marketing and Chemical Officer, the Chief Retail Market Gas & Power Officer, 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 Energy Solutions Department, the Executive Vice President Procurement Department, the Executive Vice President External Communication Department, the Executive Vice President Government Affairs Department 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 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.

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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

Umberto Vergine was born in Milan in 1957 and graduated as civil engineer from the Politecnico di Milano. He began his career at Agip in 1984 as a petroleum engineer, working in the period 1985-1991 on the Ekofisk field in Norway, in Cabinda-Angola and in Tripoli, Libya. After this, in Italy he was appointed Head of Production for Agip at the Crema Operating District. From 1993 to 2001, he held a series of managerial positions abroad, in particular as head of different foreign companies and branches of Eni E&P: District Manager of Agip UK in Aberdeen, District General Manager NAOC in Port Harcourt-Nigeria, and General Manager and MD of Petrobel in Cairo. In March 2001, he was appointed Managing Director of Lasmo Venezuela in Caracas and at the end of 2002 Managing Director of IEOC in Cairo. On his return to Italy in 2004, he held the following positions at the E&P Division:
•		Regional Vice President, West Africa and Egypt;
•		Senior Vice President North Europe, North and South America, Russia and the Far East;
•		Senior Vice President of Technical Services & Technology; and
•		Executive Vice President South Europe, Central Asia and the Far East.
In 2010, he was appointed Senior Executive Vice President Eni SpA, heading the Study and Research Department. He has been a director of Saipem SpA, Eni Trading & Shipping, and Eni Foundation and the Eni representative on the board of the Fondazione Politecnico di Milano. He was Chief Operating Officer of the Gas & Power Division of Eni from January 1, 2012 until December 5, 2012, when he was appointed Chief Executive Officer of Saipem SpA, a position that he held until April 30, 2015. Since June 8, 2015, he has been Midstream Gas & Power Chief Officer of Eni. Since November 2015, he has been Member of the Eurogas Board.

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&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 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.

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Luca Cosentino was born in Venice on August 1, 1961. He graduated cum laude in geology in 1985 from the University of Padua and joined Eni in 1986. He spent the first years of his professional life in the Reservoir Department, within the reservoir modeling group. Between 1992 and 1996, he worked in different operational positions in Italy and abroad. From 1996 to 2003, he worked as Project Manager with IFP (Institut Français du Petrol, France), in Venezuela and in the Persian Gulf. In this period, he also taught at the IFP School and published several technical papers, including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to 2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From 2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed Senior Vice President Non Operated Business Performance and Stranded Resources Valorization. Since November 1, 2015, he has been Executive Vice President Energy Solutions Department.

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 E&P Division, where he oversaw the Planning, Management, Development and Compensation processes for the human resources and organization activities. He also collaborated with the top management in the reorganization of macro processes for the Division and promoted Change Management initiatives. From 2006, he has been a Board Member of Eni International Resources Ltd, and from 2012 to 2013, he has been appointed as Chairman of the Board of Eni International Resources Ltd. From 2012 to March 2015, he has been a board member of Eni UK Ltd. Since 2013, he has been Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, with responsibility for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in time to market and efficiency. 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 (avvocato) and England (solicitor) and for around five years worked as a legal practitioner in Milan and London. In October 2005, he was appointed head of Legal Affairs and Senior Executive Vice President for Legal Affairs at Eni and since that date he has been a Member of the Supervisory Committee of Eni which is set up pursuant to Law No. 231/2001. Since July 1, 2014, he has been Eni’s Chief of Legal and Regulatory Affairs. He is a member of the anticorruption commission of the International Chamber of Commerce of Paris and since 2011 of the anticorruption working group for the B20, coordinator for activities relating to the development of an international regulatory framework for the B20 held in Russia in 2013 and lead expert for the 2014 B20 in Australia. Since 2012, he has participated as international legal expert in various UNDOC projects concerning anticorruption and compliance. He was a Member of the Board of Directors of Snam Rete Gas SpA from 2005 to 2012 and of the University of Bologna from 2011 to 2012. He is the author of numerous publications and teaches a number of post-graduate courses.

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 and 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 Director of Planning and Control for the Eni group, before returning to E&P as Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration & 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 a company’s financial reports pursuant to Article 154-bis of 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

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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 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. Versalis, Syndial and EniPower report to the Chief Downstream & Industrial Operations Officer. Since February 19, 2015, he has been Chief Refining & Marketing and Chemical Officer.

Antonio Vella was born in 1957. He graduated in engineering from the Turin Polytechnic in 1982 and joined the Eni Group in 1983. He began his career as an oil engineer at Agip in Libya, where he was involved in upstream onshore and offshore operations. From 1988 to 1991, he was project manager for EniChem’s petrochemical plants and refineries in Italy. In 1991, he was appointed project manager for the development of Libyan oil fields and in 1993, he moved to Egypt, initially as Operations Manager and subsequently as General Manager and Managing Director of Petrobel, where he was responsible for all of Eni’s upstream operations in Egypt. In 1999, he was appointed District General Manager of Nigerian Agip Oil Co (NAOC), and in 2000, became Vice Chairman and Managing Director of the Eni companies in Nigeria NAOC, NAE (Nigerian Agip Exploration) and AENR (Agip Energy). In 2002, he became regional Vice President for Australasia, Russia, Azerbaijan and then, in 2005, a Member of the Board of Directors and Managing Director of Eni Algeria. From 2006 to 2009, he was regional Senior Vice President for North Africa and the Middle East (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) for Eni’s Exploration & Production Division. In 2009, he was appointed Executive Vice President operations for the Exploration & Production Division. In December 2012, he was appointed Executive Vice President for Central Asia, the Far East and the Pacific Area. Since July 2014, he has been a Board Member of Eni Foundation. Since July 1, 2014, he has been Upstream Officer.

Marco 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 has also been a member of numerous Italian and European committees representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law (Commission "Vietti") and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board Member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel.

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

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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 G&P Department. Since October 1, 2015, he has been Chief Retail Market Gas & Power Officer.

Rita Marino was born in Salerno in 1964. She 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.

Marco Bardazzi was born in Prato in 1967. A journalist by trade, he worked in the media business for 28 years, before joining Eni in 2015. He has achieved an extensive experience in foreign policy and digital communications, particularly related to European and American realities (he has lived and worked in the United States for nine years). Between 2009 and 2015, he has been Managing Editor and Digital Editor at "La Stampa", a leading European newspaper based in Turin, Italy. He has been a key member of the "La Stampa" team that has worked on its transformation from a traditional newspaper founded in 1867 to an integrated digital news organization, thus creating an innovative "concentric circle" multiplatform newsroom. He has also been a co-founder of the "Europa" partnership between La Stampa, Le Monde, El País, The Guardian, Gazeta Wyborcza and Suddeutsche Zeitung. Before joining "La Stampa", he was U.S. Correspondent for the Italian news agency ANSA, covering every aspect of American life for the Italian media. Among other things, he has covered the 2000 Bush-Gore electoral race for the White House; the first international Al Qaeda trial in Manhattan; the September 11, 2001 attack on America; the war in Afghanistan; the war in Iraq; the 2004 and 2008 presidential campaigns; he has visited and reported on the Guantanamo detention camp at U.S. Navy Guantanamo Bay base, Cuba; he has covered the 2008 financial crisis, and he has extensively reported on the American digital, energy and manufacturing businesses. He teaches a class on "Journalism innovation" in the Master on Journalism program at ALMED-Università Cattolica del Sacro Cuore, Milan. He holds an Associate of Arts degree in History from American Public University. His latest book is "L’Ultima Notizia" (with Massimo Gaggi, Rizzoli 2010), an essay on digital transformation in the media business. Since February, 16, 2015, he has been External Communication Department Executive Vice President.

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.

 

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Compensation

Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of Directors, which considers relevant proposals made by the Compensation Committee after consultation with the Board of Statutory Auditors.

Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter of Legislative Decree No. 58 of February 24, 1998 and Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications) and in line with the Corporate Governance Code recommendations for Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy Guidelines adopted for Directors and other Managers with strategic responsibilities¹⁰.

The main elements of the 2016 remuneration policy and of the compensation paid in 2015 to the Chairman, CEO, other Board members, Eni’s Chief Operating Officer and of other Managers with strategic responsibilities, are described below.

 

2016 Remuneration Policy Guidelines

The guidelines for the 2016 Remuneration Policy for the Directors with delegated powers reflect the decisions made by the Board of Directors on May 28, 2014, following the renewal of the corporate bodies, and 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 2016 Guidelines provide for the same instruments used in 2015 and in particular the short and long-term incentive plans are strictly in line with those for the Chief Executive Officer and General Manager, in order to better guide and align managerial actions with the targets defined in the Company’s Strategic Plan.

 

Market references

For the Chairman, Non-executive Directors and the Chief Executive Officer and General Manager, the remuneration positioning is assessed by comparing similar roles in the following main panels:
(i)		Oil & Gas Panel: main listed companies in the Oil&Gas sector, Eni’s competitors at international level and of comparable median sizes (Exxon, Shell, Chevron, Total, BP, Conoco Phillips, Anadarko, Repsol, Marathon Petroleum, Maraton Oil, Tullow Oil).
(ii)		Top Europe Panel: main listed European companies, of median sizes comparable to Eni, excluding companies in the financial, insurance and luxury sectors (Shell, BHP Billiton, Total, BP, Bayer, Volkswagen, GlaxoSmithKline, British American Tobacco, Siemens, Vodafone, AstraZeneca, Daimler, Rio Tinto, BASF, Deutsche Telekom, BMW, Telefonica, Glencore, Reckitt Benckiser, National Grid, British Telecom, British Gas).
(iii)		Top Italy Panel: main companies listed on the FTSE MIB, excluding companies in the financial, insurance and luxury sectors (Enel, Telecom Italia, FCA, Pirelli, Finmeccanica, Snam, Terna, Prysmian, Luxottica, Atlantia, Mediaset).

For Managers with strategic responsibilities, their remuneration positioning is assessed by comparing roles with the same degree of responsibility and managerial complexity in the national, international and Oil & Gas market, applying the same methods employed for the CEO.

 

General principle of clawback

Clawback mechanisms will be adopted, through a specific regulation proposed by the Compensation Committee and approved by the Board of Directors, allowing the variable remuneration components already paid to be reclaimed, or those subject to deferral to be withheld, where their achievement was based on data that was subsequently proven to be manifestly misstated, or allowing the recoupment of all the incentives for the year (or years) in which subsequent

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checks confirm the fraudulent alteration of the results data used to obtain the right to incentives, and/or the commission of serious and deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to the employment and trust relationship, without prejudice to any other action permitted by law and regulations to protect the interests of the Company. The regulation provides that the activation of recoupment claims (or revocation of incentives awarded but not yet paid) must take place, once the checks have been completed, within three years of payment (or award) in the case of error, and within five years in the case of fraud.

 

CHAIRMAN OF THE BOARD OF DIRECTORS 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.

 

Non-executive Directors

Remuneration for participation in Board Committees
The Policy Guidelines for Non-executive and/or Independent Directors provide for the maintenance of an additional annual remuneration11 for participating in Board Committees, as follows:
•		for the Control and Risk Committee, the remuneration amounts to euro 60,000 for the Chairman and euro 40,000 for the other members;
•		for the Compensation Committee, the Sustainability and Scenario Committee and the Appointment Committee the remunerations amount to euro 30,000 for the Chairman and euro 20,000 for the other members.

 

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 Policy Guidelines reflect the resolutions passed by the Board of Directors on May 28, 2014, taking into account the specific delegated powers granted in accordance with the Articles of Association, the instructions contained in the chapter "Principles and general purposes of Eni Remuneration Policy", as well as the 25% reduction of the maximum payable overall remuneration of the previous mandate, in accordance with the Shareholders’ resolution of May 8, 2014. The remuneration envisaged by the Board in relation to the delegated powers includes both the compensation for Directors determined by the Shareholders’ Meeting on May 8, 2014, as well as any compensation that may be due for participating on the Board of Directors of Eni’s subsidiaries or associated companies.

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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 2016 annual variable incentive plan is linked to the achievement of the predefined targets for 2015 as described in the 2015 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 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 2016 targets approved by the Board Meeting of March 17, 2016 for the 2017 Annual Variable Incentive Plan provide for a structure focused on the essential goals, consistent with the guidelines outlined in the Strategic Plan 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%). The value of each objective, in terms of performance target, is aligned with the budgeted value.

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). In particular the conditions of the plan include in particular: (i) that incentive to be given each year is 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) that the incentive to be paid at the end of the three-year vesting period is based on 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 EBT, the performance is considered to be zero. The value of EBT, in terms of performance target, is aligned with the budgeted value.
•		Long-Term Monetary Incentive Plan (LTMI), 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 Total Shareholder Return12 and Net Present Value ("NPV")13 of proved reserves 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 and a more sustainable value creation in the medium to long term. The conditions of the plan include, in particular: (i) that the incentive to be given every year is equal to 100% of the overall fixed remuneration; (ii) that the incentive to be paid at the end of the three-year vesting period is determined in relation to the results achieved in terms of variation of the TSR (with a weighting of 60%) and of the NPV of proved reserves (with a weighting of 40%) 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 multipliers calculated during the vesting period in relation to the placement achieved compared with the peer group companies, 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.

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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:
•		indemnity supplementing the severance pay, with mutual exemption from notice, payable 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. This indemnity is equal to 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 to protect the Company’s interests that can be activated at the sole discretion of 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 specific 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 activities potentially in competition with Eni in key markets in Europe, America, Asia and Africa. This amount will be set by the Board of Directors as the sum of two components: (i) a fixed component of euro 1,500,000; and (ii) a linearly determined variable component based on the average annual performance of the previous three years (equal to 0 for performance below or equal to the target and to euro 750,000 for maximum performance), and will be paid at the expiry of the term of the agreement. The variable component is calculated by taking into consideration the annual performance related to the annual Variable Incentive Plan. Any violation of the non competition agreement will involve the non-payment of the consideration (or its restitution, where the violation is identified by Eni after the payment), and the obligation to pay damages set by mutual agreement 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.

 

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.

 

Pay mix
The remuneration package for the Chief Executive Officer and General Manager includes a fixed component, a short-term variable component and a long-term variable component. The pay mix is significantly focused on the variable components, with a definite prevalence of the long-term component.

 

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 2016 Guidelines, given the reference context 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.

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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 Chief Executive Officer and General Manager 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 General Manager, participate in the 2015-2017 Deferred Monetary Incentive Plan (DMI) approved by the Board of Directors on March 12, 2015 and in the 2014-2016 Long-Term Monetary Incentive Plan (LTMI) 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 DMI, designed solely for the managerial resources that have delivered the performance results established in the Annual Variable Incentive Plan (threshold target). The DMI 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 LTMI 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 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 which the individual in question is an employee during the course of the vesting period, and 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, according to the criteria established by Eni for cases of early resolution, within the protection limits envisaged by the relevant national collective labor agreement. These criteria take into account the position held, 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, agreements containing non competition clauses 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.

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Pay mix
The average pay mix of the remuneration package for Managers with strategic responsibilities highlights the balance between the fixed and variable components and, as regards to the latter, the greater focus on medium-long term variable incentives, in line with the reference market’s best practices.

 

COMPENSATION AND OTHER INFORMATION

Implementation of the 2015 remuneration policies

The following is a description of the remuneration decisions taken in 2015 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, and other Managers with strategic responsibilities, in relation to their time in office.

The implementation of the 2015 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 2015 Remuneration Policy, approved by the Board of Directors on March 12, 2015, taking into account 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 Directors with delegated powers, in accordance with the resolutions passed at the Shareholders’ Meeting in accordance with Law No. 98/2013.

 

Chairman of the Board of Directors - Emma Marcegaglia

Fixed remuneration
The Chairman was paid the fixed remuneration approved for the office by the Shareholders’ Meeting of May 8, 2014 of euro 90,000 gross and the remuneration approved by the Board of Directors Meeting of May 28, 2014, in relation to the delegated powers, amounting to euro 148,000 gross.

Benefits
The Chairman was given insurance coverage against the risk of death and permanent disability, in accordance with the resolutions of the Board of Directors Meeting of May 28, 2014.

 

Non-executive Directors

The Directors were paid fixed remuneration approved by the Shareholders’ Meeting of May 8, 2014 of euro 80,000 gross. The additional remunerations payable for participation in the Board Committees, as resolved by the Board of Directors Meeting of March 12, 2015, were also paid. These are detailed in Table 1 under the item "Remuneration for participation in the Committees".

 

Chief Executive Officer and General Manager - Claudio Descalzi

Claudio Descalzi has held the office of Chief Executive Officer and General Manager since May 9, 2014, and before then he held the office of Chief Operating Officer (COO) of the E&P Division. Therefore, during 2015, Claudio Descalzi received the remuneration related to his current role of Chief Executive Officer and General Manager and the variable incentives accrued for his previous office, as detailed below.

 

Fixed remuneration
The Chief Executive Officer and General Manager was paid the fixed remunerations approved by the Board of Directors Meeting of May 28, 2014, which also include the remunerations approved by the Shareholders’ Meeting for all the Directors, equal to a total gross annual amount of euro 1,350,000.

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Annual variable incentives
In line with the Remuneration Policy 2015, the Chief Executive Officer and General Manager was paid a gross annual variable incentive of euro 1,070,000 associated with the performance achieved during 2014 (123 points), determined on a pro-rata basis for the period in which he held office (from May 9, 2014 to December 31, 2014).

Furthermore, for Claudio Descalzi, solely in relation to the his role as COO of the Exploration & Production Division held from January 1, 2014 to May 8, 2014, the Company paid a gross annual monetary incentive of euro 366,000 associated with the performance achieved by the E&P Division in 2014, determined on a pro-rata basis for the period in which he held office, in accordance with the Remuneration Policy defined for Chief Operating Officers and other Managers with strategic responsibilities.

 

Deferred Monetary Incentive Plan
For the Chief Executive Officer and General Manager, the Board of Directors as its meeting of March 12, 2015, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2015, approved the assignment of the deferred monetary incentive of euro 864,000 gross, calculated based on the EBT 2014 results approved by the Board of Directors. Furthermore, in 2015 the Deferred Monetary Incentive assigned in 2012 to Claudio Descalzi, as COO of the Exploration & Production Division, reached maturity and the gross amount paid equaled euro 476,000.

 

Long-Term Monetary Incentive Plan
For the Chief Executive Officer and General Manager, the Board of Directors at its meeting of September 17, 2015, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2015, approved the assignment of the 2015 Long-Term Monetary Incentive of euro 1,350,000 gross. Furthermore, in 2015, the Long Term Monetary Incentive assigned in 2012 to Claudio Descalzi as COO of the Exploration & Production Division, reached maturity and the gross amount paid equaled euro 221,000.

 

Benefits
For the Chief Executive Officer and General Manager, 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.

In 2015, Claudio Descalzi, for his role as Chief Executive Officer and General Manager, received a total of euro 2,435,000 and, for his previous role as COO of the E&P Division (held until May 8, 2014), euro 1,063,000 for the variable incentives accrued.

 

Managers with strategic responsibilities

Fixed remuneration
For the current Managers with strategic responsibilities, within the context of the annual salary review process envisaged for all managers, in 2015 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. The total gross value of the fixed remuneration paid in 2015 to Managers with strategic responsibilities is shown in table 1 in the chapter "Compensation paid in 2015", under the item "Fixed compensation".

 

Annual variable incentives
In March 2015, annual variable incentives were paid to the Managers with strategic responsibilities as determined in accordance with the defined Remuneration Policy, with reference to the actual performance of 2014. In particular, the incentive is linked to business performance and a number of business, sustainability (safety, environmental protection, and stakeholder relations) and individual targets in relation to the scope of responsibilities of the role, consistent with the provisions of the 2014 Eni Performance Plan.

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Deferred Monetary Incentive Plan
Managers with strategic responsibilities were assigned the 2015 deferred monetary incentive, determined in accordance with the defined Remuneration Policy, as well as on the basis of the 2014 EBITDA results resolved by the Board of Directors on March 12, 2015, as proposed by Compensation Committee. In 2015, the Deferred Monetary Incentive assigned in 2012 also reached maturity.

 

Long-Term Monetary Incentive Plan
Managers with strategic responsibilities were assigned the 2015 long-term monetary incentive, determined in accordance with the defined Remuneration Policy. In 2015, the Long-Term Monetary Incentive assigned in 2012 also reached maturity.

 

Severance indemnity for end of office or termination of employment
During 2015, 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 2015

The table below lists the individual remunerations to the Directors, Statutory Auditors, General Managers and, in aggregate, to the other Managers with strategic responsibilities. The remunerations received from subsidiaries and/or affiliates, except those waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year.

In particular:
•		based on the criteria of competence, the column "Fixed remuneration" reports the fixed remuneration and fixed salary from employment due for the year, gross of the social security contribution and tax expenses to be paid by the employee; it excludes attendance fees, as these are not provided for. Details of the compensation are provided in the notes, and any indemnities or payments with reference to the employment relationship are indicated separately;
•		based on the criteria of competence, the "Remuneration for participation in the Committees" column reports the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately;
•		the column "Variable non-equity remuneration" under the item "Bonuses and other incentives" shows the incentives paid during the year due to rights vested following the assessment and approval of the related performance results by the relevant corporate bodies, 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 "Benefits in kind" column reports the value of the fringe benefits awarded;
•		based on the criteria of competence, the "Other remuneration" column reports any other remuneration deriving from other services provided;
•		the "Total" column details the sum of the amounts of all the previous items;
•		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, General Managers and other Managers with strategic responsibilities

(euro thousand)

Name

Notes

Position

Period for which the position was held

Expiration of office (*)

Fixed remuneration

Remuneration for participation in the Committees

Bonuses and other incentives

Variable non-equity remuneration

Other remuneration

Total

Fair value of equity remuneration

Severance indemnity for end of office or termination of employment

Profit sharing

Benefits in kind

Board of Directors
Emma Marcegaglia	(1)		Chairman		01.01-12.31		05.2017		238	(a)															238
Claudio Descalzi	(2)		CEO and General Manager		01.01-12.31		05.2017		1,350	(a)					1,070	(b)				15					2,435
Andrea Gemma	(3)		Director		01.01-12.31		05.2017		80	(a)		90	(b)												170
Pietro Angelo Guindani	(4)		Director		01.01-12.31		05.2017		80	(a)		50	(b)												130
Karina A. Litvack	(5)		Director		01.01-12.31		05.2017		80	(a)		80	(b)												160
Alessandro Lorenzi	(6)		Director		01.01-12.31		05.2017		80	(a)		80	(b)												160
Diva Moriani	(7)		Director		01.01-12.31		05.2017		80	(a)		40	(b)												120
Fabrizio Pagani	(8)		Director		01.01-12.31		05.2017		80	(a)		50	(b)												130
Alessandro Profumo	(9)		Director		07.29-12.31		05.2017		34	(a)		17	(b)												51
Luigi Zingales	(10)		Director		01.01-07.02				40	(a)		30	(b)												70

Board of Statutory Auditors

Matteo Caratozzolo	(11)		Chairman		01.01-12.31		05.2017		80	(a)												46	(b)		126
Paola Camagni	(12)		Statutory Auditor		01.01-12.31		05.2017		70	(a)												30	(b)		100
Alberto Falini	(13)		Statutory Auditor		01.01-12.31		05.2017		70	(a)												34	(b)		104
Marco Lacchini	(14)		Statutory Auditor		01.01-12.31		05.2017		70	(a)												32	(b)		102
Marco Seracini	(15)		Statutory Auditor		01.01-12.31		05.2017		70	(a)												27	(b)		97

Other Managers with strategic responsibilities (**)	(16)		Remuneration in the company that prepares the Financial Statements		7,306						7,756					178		120			15,360				2,414
			Remuneration from subsidiaries and associates		2,030						1,382					804					4,216
			Total		9,336	(a)					9,138	(b)				982	(c)	120	(d)		19,576				2,414	(e)

11,838

437

10,208

997

289

23,769

2,414

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Notes

(*)		The term of office expires with the Shareholders’ Meeting approving the Financial Statements for the year ending December 31, 2016.
(**)		Managers who were permanent members of the Company's Management Committee during the course of the year together with the Chief Executive Officer, or who reported directly to the Chief Executive Officer (eighteen managers).
(1)		Emma Marcegaglia - Chairman of the Board of Directors
		(a) The amount includes the fixed remuneration of euro 90 thousand set by the Shareholders' Meeting on May 8, 2014 and the fixed remuneration for the delegated powers of euro 148 thousand approved by the Board on May 28, 2014.
(2)		Claudio Descalzi - Chief Executive Officer and General Manager
		(a) The amount includes the fixed remuneration of euro 550 thousand for the position of Chief Executive Officer, which incorporates the remuneration set by the Shareholders’ Meeting on May 8, 2014 for the position of Director, and the fixed remuneration of euro 800 thousand for the position of General Manager; 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 are added to this amount for a total of euro 18 thousand.
		(b) The amount relating to the variable annual incentive paid in 2015, determined on a pro-rata basis for the performance period from May 9, 2014 to December 31, 2014 when he held the position of Chief Executive Officer and Chief Operating Officer. The incentives paid in 2015 for the position of COO of the E&P Division, held until May 8, 2014, for a total of euro 1,063 thousand, are added to this amount and include: (i) euro 366 thousand relating to the annual variable incentive calculated on a pro-rata basis for the performance period from January 1, 2014 to May 8, 2014; (ii) euro 476 thousand relating to the deferred monetary incentive assigned in 2012, calculated in relation to the performance targets achieved during the 2012-2014 vesting period; and (iii) euro 221 thousand relating to the long-term monetary incentive assigned in 2012, calculated in relation to the performance targets achieved in the 2012-2014 vesting period.
(3)		Andrea Gemma - Director
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the euro 40 thousand for participating in the Control and Risk Committee and euro 20 thousand for the Sustainability and Scenario Committee and euro 30 thousand for the Appointment Committee.
(4)		Pietro Angelo Guindani - Director
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the euro 30 thousand for participating in the Compensation Committee and euro 20 thousand for the Sustainability and Scenario Committee.
(5)		Karina A. Litvack - Director
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the euro 40 thousand for participating in the Control and Risk Committee, euro 20 thousand for participating in the Compensation Committee and euro 20 thousand for the Sustainability and Scenario Committee.
(6)		Alessandro Lorenzi - Director
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the euro 60 thousand for participating in the Control and Risk Committee and euro 20 thousand for the Compensation Committee.
(7)		Diva Moriani - Director
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the euro 20 thousand for participating in the Compensation Committee and euro 20 thousand for the Appointment Committee.
(8)		Fabrizio Pagani - Director
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the euro 30 thousand for participating in the Sustainability and Scenario Committee and euro 20 thousand for the Appointment Committee.
(9)		Alessandro Profumo - Director
		(a) The amount corresponds to the pro-rata amount from July 29, 2015 to December 31, 2015 of the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the pro-rata amount from July 29, 2015 to December 31, 2015 respectively of euro 8.4 thousand for the Sustainability and Scenario Committee and euro 8.4 thousand for the Appointment Committee.
(10)		Luigi Zingales - Director
		(a) The amount corresponds to the pro-rata amount until July 2, 2015 of the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount includes the pro-rata amount until July 2, 2015 of euro 20.2 thousand for participating in the Control and Risk Committee and euro 10.1 thousand for the Appointment Committee.

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(11)		Matteo Caratozzolo - Chairman of the Board of Statutory Auditors
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of TTPC (euro 32.1 thousand) and of Eni Adfin (euro 13.9 thousand).
(12)		Paola Camagni - Statutory Auditor
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni East Africa (euro 18 thousand) and Auditor of Syndial (euro 12 thousand).

(13)		Alberto Falini - Statutory Auditor
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni Timor Leste (euro 12.9 thousand) and Auditor of TTPC (euro 21.2 thousand).
(14)		Marco Lacchini - Statutory Auditor
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of SOM (euro 20.3 thousand) and Auditor of Eni East Africa (euro 12 thousand).
(15)		Marco Seracini - Statutory Auditor
		(a) The amount corresponds to the fixed annual remuneration set by the Shareholders' Meeting of May 8, 2014.
		(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Ing. Luigi Conti Vecchi (euro 18.2 thousand) and Auditor of Eni Adfin (euro 9.2 thousand).
(16)		Other Managers with strategic responsibilities
		(a) The amount of euro 9,336 thousand for Gross Annual Salary is supplemented by the indemnities owed for the transfers performed, in Italy and abroad, in line with the provisions of the relevant national collective 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 208 thousand.
		(b) The amount includes the payment of euro 3,591 thousand relating to the deferred and long-term monetary incentives assigned in 2012 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 assigned to managers in international mobility.
		(d) Amounts due for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231 and the Manager responsible for the preparation of the Company’s financial statements and other 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, to which euro 550 thousand is added for the non-competition clauses payable by 2016 at the expiry of the related validity period, subject to the obligations being fulfilled.

 

OTHER INFORMATION

Accrued compensation
Total compensation accrued in the year 2015 pertaining to all the Board members amounted to euro 6.7 million; it amounted to euro 0.55 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, 2015, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2015 period, filled said roles, even if only for a fraction of the year) amounted to euro 42 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2015. The breakdown is as follow:

	2015
	(euro million)

Fees and salaries		26
Post-employment benefits		2
Other long-term benefits		12
Indemnity upon termination of the office		2
		42

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, 2015, 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 2015 period, filled said roles, even if only for a fraction of the year), was euro 1,254,000.

Name				(euro thousand)
Claudio Descalzi		Chief Executive Officer		348
Senior Managers (a)				906
				1,254

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Board practices

Corporate Governance
The Corporate Governance structure of Eni follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. Eni complies with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) approved by Italian Corporate Governance Committee (hereinafter "Corporate Governance Code" or "Code"). On July 9, 2015, the Italian Corporate Governance Committee approved a few amendments to the Corporate Governance Code. At its Meeting held on February 25, 2016, the Board adopted the new recommendations of the Code, acknowledging that Eni’s Corporate Governance model was already broadly compliant with the new recommendations.

The names of Eni’s Directors, their positions, the year in which each of them was initially appointed as a Director and their ages are reported in the related table above.

 

Board of Directors’ duties and responsibilities
The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated May 9, 2014, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, in addition to those that cannot be delegated by law, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board.

In the same resolution, the Board of Directors resolved to attribute to the Chairman a major role in internal controls and not operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code, the Head of the Internal Audit Department reports to the Board, and on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system. The Chairman is also involved in the appointment of the primary Eni officers in charge of internal controls and risk management, as well as in approving internal rules governing the Internal Audit process. In addition, the Chairman carries out her statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer.

Finally, the Board of Directors entrusted the Board Secretary with the role of Corporate Governance Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He lends assistance and independent legal advice to the Board and the Directors and 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. It

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		examines and approves the plan for the Company’s non-profit activities and approves operations not included in the plan whose cost exceeds euro 500,000;
•		examines and approves the annual financial report (which includes Eni’s draft Financial Statements and the Consolidated Financial Statements) and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report;
•		receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers;
•		receives a report from the Board’s internal committees on at least a semi-annual basis;
•		assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts;
•		evaluates and approves transactions of the Company and its subsidiaries with related parties provided for in the procedure approved by the Board14, as well as transactions in which the CEO has an interest;
•		evaluates and approves any transaction executed by the Company and its subsidiaries that has a significant strategic, economic, financial or asset impact on the Company;
•		appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the Senior Executive Vice President of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of a manager responsible for shareholder relations;
•		examines and approves the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting. It also defines the criteria for remunerating the senior executives of the Company and of the Group and takes steps to implement compensation plans based on shares or other financial instruments approved by the Shareholders’ Meeting;
•		resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries;
•		formulates the proposals to present to the Shareholders’ Meeting; and
•		examines and resolves on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity.

In accordance with Article 23.2 of the By-laws, the Board also resolves on mergers and proportional spin-offs of companies in which Eni’s shareholding is at least 90%; the establishment and closing of branches; and the amendment of the By-laws to comply with the provisions of law.

In accordance with the By-laws, the Chairman and the Chief Executive Officer retain representative powers for the Company.

 

Directors’ independence
On the basis of statements made by the Directors and other information available to the Company, during its meeting of May 9, 2014 and, after an investigation by the Nomination Committee, at its meeting of February 17, 2015, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales¹⁵ satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code. Chairman Marcegaglia, in compliance with the Corporate Governance Code, could not be deemed independent as she is a significant representative of the Company.

On July 29, 2015, the Eni Board of Directors appointed Alessandro Profumo to replace Luigi Zingales, who resigned on July 2, 2015. The Board of Directors, following an investigation performed by the Nomination Committee, on the basis of declarations made by Profumo and information available to the Company, ascertained that Profumo was independent according to law and the Corporate Governance Code. With reference to the marital relationship of Profumo with an employee of the Company, the Board resolved that this relationship does not compromise the independence requirements requested by the Corporate Governance Code, on account of Profumo’s ethical and professional integrity and his international reputation and taking into account the fact that his spouse is employed at a foundation, which is independent of Eni SpA.

Finally, on the basis of statements made by the Directors and other information available to the Company, after an investigation by the Nomination Committee, at its meeting of February 25, 2016, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Profumo satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Profumo have been deemed independent by the Board pursuant to the criteria

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and parameters recommended by the Corporate Governance Code. The Board confirmed the independence requirements of Director Profumo on the basis of the aforementioned reasons.

The Board of Statutory Auditors ascertained that the Board of Directors correctly applied the assessment criteria and procedures for evaluating the independence of its members.

The independence criteria may not be equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company.

 

Board Committees
The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the Compensation Committee; (c) the Nomination Committee; and (d) the Sustainability and Scenarios Committee. Committees under letters (a), (b) and (c) are recommended by the Corporate Governance Code. The composition, duties and operational procedures of these committees are governed by their own rules, which are approved by the Board, in compliance with the criteria outlined in the Corporate Governance Code.

The Committees recommended by the Corporate Governance Code are composed of no fewer than three members and, in any case, less than a majority of members of the Board. The composition is described in the following sections pertaining each Committee.

All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. In addition, the Chairmen of the Committees report to the Board at each meeting of the Board on the key issues examined by the Committees in their previous meetings.

In the exercise of their functions, the Committees have the right to access any information and Company functions necessary to perform their duties. They are also provided with adequate financial resources, in accordance with the terms established by the Board of Directors, and can avail themselves of external advisers.

The Chairman of the Board of Statutory Auditors or a Statutory Auditor designated by him, participates in Control and Risk Committee meetings and may participate in other Committees’ meetings. Furthermore, Committees may invite other persons to attend the meetings in relation to individual items on the agenda.

The CEO and the Chairman may attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they may attend Control and Risk Committee meetings, unless matters relating to them are discussed. Finally, they may attend Compensation Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their remuneration.

The Board Secretary and Corporate Governance Counsel coordinates the secretaries of the Board Committees, receiving at this end information on the items in the Committees’ agendas, the notices of the meetings, as well as their signed minutes.

Minutes of all Committee meetings are usually drafted by their respective secretaries. The current members of the Control and Risk Committee, Compensation Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on May 9, 2014, except for Director Profumo, appointed by the Board of Directors as a member of Nomination Committee and Sustainability and Scenarios Committee on September 17, 2015.

 

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

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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 2015, the Compensation Committee met a total of ten times, with an average attendance of 95% of its members and an average duration of 2 hours and 58 minutes. All the Committee meetings were attended by at least one member of the Board of Statutory Auditors.

Earlier in the year, the Committee focused its activities in particular on the following topics: (i) periodic assessment of the Remuneration Policy implemented in 2014, also for the purpose of defining the proposed Policy Guidelines for 2015; (ii) verification, with the support of leading law firms, of the application conditions of the clawback clause in effect and its review in order to bring it into line with the recommendations introduced in July 2014 in the Corporate Governance Code (Article 6.C.1, subparagraph f), with the definition of the related application criteria, to approve implementation rules which make the operating procedures more effective; (iii) closing of the 2014 corporate results and definition of the 2015 performance targets related to the variable incentive plans; (iv) definition of the proposals for the implementation of the Deferred Monetary Incentive Plan for the Chief Executive Officer and General Manager and other managerial resources; (v) review of the 2015 Eni Remuneration report; (vi) review and approval of the adjustment method used to monitor company performance in order to ensure that, by eliminating exogenous effects, the results can be compared and the targets assigned by management can be assessed; (vii) verification of the non-competition agreement entered into with the outgoing Chief Executive Officer; and (viii) review of the engagement process in order to maximize shareholders’ agreement on the 2015 Remuneration Policy.

In the second part of the year the Committee primarily analyzed the results of the 2015 Shareholder's Meeting season, regarding the Eni Remuneration Report, the main Italian and European listed companies as well as companies in the peer group of reference. With regard to the other main activities carried out, the Committee: (i) analyzed the regulatory developments regarding executive compensation, particularly with regard to the U.S. SEC’s recent proposals on clawback; (ii) finalized the implementation proposal (2015 assignment) of the Deferred Monetary Incentive Plan for the Chief Executive Officer and General Manager and other critical managerial resources; (iii) carried out a preliminary review of the reference compensation benchmarks, updated to 2015, for top management; (iv) was informed of the results of the periodic monitoring carried out on the evolution of the relevant regulatory framework; (v) was informed of the voting policies of the main proxy advisors and of the results of the benchmark studies on the remuneration reports published nationally and internationally in 2015; and (vi) was informed on the results of the first engagement cycle carried out in view of the 2016 Shareholders’ Meeting season.

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.

 

Control and Risk Committee
Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Karina Litvack¹⁶.

The Control and Risk Committee is entrusted with supporting, on the basis of an appropriate control process, the Board of Directors in evaluating and making decisions concerning the internal control and risk management system and in approving the periodical financial reports. It is entirely made up of non-executive and independent Directors¹⁷ who possess the necessary expertise consistent with the duties they are required to perform¹⁸.

In particular, at their appointment, the Directors Lorenzi and Litvack 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.

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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 Board assessment of the main company risks, identified taking into account the characteristics of the activities carried out by the company or its subsidiaries; c) on the evaluation, performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, at least once every six months it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the internal control and risk management system at the meeting of the Board of Directors indicated by the Chairman of the Board of Directors; d) on the approval, at least once a year, of the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; e) on the description, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, providing its evaluation of the overall adequacy of the system itself; and f) on the evaluation of the findings reported by the Audit Firm in any recommendations letter it may issue and in the latter’s report on the main issues arising during the audit.

The Committee furthermore: a) issues opinions to the Board of Directors on specific aspects concerning the identification of the main risks faced by the Company; b) examines and issues an opinion on the adoption and amendment of the rules on the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or Statutory Auditor holds a personal interest or an interest on behalf of a third party, while performing additional duties assigned it by the Board of Directors, including examining and issuing an evaluation on specific types of transactions, except for those relating to compensation; and c) gives an opinion on the fundamental guidelines of the Regulatory System, the regulatory instruments to be approved by the Board of Directors, their amendment or update and, upon request by the CEO, on specific aspects in relation to the instruments implementing the fundamental guidelines.

In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the Consolidated Financial Statements, prior to their approval by the Board of Directors; b) examines and evaluates 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 Management System Guideline 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 particular importance; and d) examines the information received from the Senior Executive Vice President of the Internal Audit Department and promptly reports its assessment to the Board of Directors in the case of: (i) significant deficiencies in the system for preventing irregularities and fraudulent acts, and irregularities or fraudulent acts committed by management personnel or by employees that perform important roles in the design or operation of the internal control and risk management system; and (ii) circumstances that may affect the maintenance of the independence of the Internal Audit Department and of auditing activities.

The Committee may also ask the Internal Audit Department to perform audits on specific operational areas, providing simultaneous notice to the Chairman of the Board of Statutory Auditors. The Committee also examines and assesses: a) communications and information received from the Board of Statutory Auditors and its members regarding the internal control and risk management system, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports; b) half

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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 Alessandro Profumo¹⁹.

The Nomination Committee is made up of non-executive Directors, a majority of whom are independent.

The Committee provides the Board of Directors with recommendations and advice. In particular, the Committee: a) assists the Board of Directors in formulating any criteria for the appointment of persons indicated in the following letter and of members of the other boards and bodies of Eni’s subsidiaries and associated companies; b) provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board, whose appointment fall under the Boards’ responsibility and oversees the associated succession plans. Where possible and appropriate, in relation to the shareholding structure, the Committee proposes to the Board of Directors the succession plan for the Chief Executive Officer; c) acting upon proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession plan for the Company’s key management personnel; d) proposes candidates to serve as Directors on the Board of Directors in the event one or more positions need to be filled during the course of the financial year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements on the minimum number of independent Directors and of the percentage reserved for the less represented gender; e) proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, taking account of any recommendation received from shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders; f) oversees the annual self-assessment program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and deals with the preliminary activity for appointing an external consultant for such self assessment. On the basis of the results of the self-assessment, the Committee provides its opinions to the Board of Directors regarding the size and composition of the Board or its Committees, as well as the skills and professional qualifications it feels should be represented within the same Board and Committees, so that the Board itself can give its opinion to the shareholders prior to the appointment of the new Board; g) proposes to the Board of Directors the slate of candidates for the position of Director, to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3 of the By-laws; h) in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of positions of Director or statutory auditor that a Company Director may hold and performs the preliminary activity for the associated periodic checks and evaluations to be submitted to the Board; i) periodically verifies that the Directors satisfy the independence and integrity requirements and ascertains the absence of circumstances that would render them incompatible or ineligible; j) provides its opinion to the Board of Directors on any activities carried out by the Directors in competition with the Company; and k) reports to the Board of Directors, at least once every six months and no later than the deadline for the approval of the annual financial statements and of the semi-annual financial report, on the activity carried out, as well as on the adequacy of the appointment system, at the Board Meeting indicated by the Chairman of the Board of Directors.

The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors on July 30, 2014, available to the public at the Company’s website.

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Sustainability and Scenarios Committee
Members: Fabrizio Pagani (Chairman), Andrea Gemma, Pietro A. Guindani, Karina Litvack and Alessandro Profumo²⁰.

The Sustainability and Scenarios Committee is made up of non-executive Directors, a majority of whom are independent.

The Sustainability and Scenarios Committee provides recommendations and advice to the Board of Directors on scenarios and sustainability, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: the health, well-being and safety of people and communities; the protection of rights; local development; access to energy, energy sustainability and climate change; the environment and efficient use of resources; integrity and transparency; and innovation.

 

Board of Statutory Auditors
The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of May 8, 2014 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.

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 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.

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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 accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements.

On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, and lastly on May 28, 2014, the Board of Statutory Auditors approved the internal rules concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s 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 perform other audit, review or certification services;
•		making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting;
•		approving the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;
•		approving the procedures for the pre-approval of specifically identified admissible non-audit services and examining the disclosures on the execution of the authorized services;
•		evaluating requests to use the external auditor firm engaged to perform audit services for admissible non-audit services and providing its opinion to the Board of Directors;
•		examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within 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 the Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department.

 

Eni Watch Structure and Model 231
In accordance with the Italian regulations concerning the "administrative liability of legal entities deriving from criminal offences", contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, "Legislative Decree No. 231/2001"), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001

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(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 meeting held on February 25, 2016, ratified the updating of the Model 231 to reflect certain corporate organizational changes of Eni SpA and incorporate the new crime of self laundering ("autoriciclaggio") now punishable according 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. At present, the Watch Structure of Eni is composed of three external members, including the Chairman, and three internal members. The internal members are the Chief Legal & Regulatory Officer; the Executive Vice President in charge of labor law matters and disputes 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. This task is carried out by the Magistrate of the Court of Auditors, Adolfo Teobaldo De Girolamo, appointed by the Presidential Council of the Court of Auditors on December 22, 2014. The Magistrate of the Court attends the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Control and Risk Committee.

 

 

 

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Employees

As of December 31, 2015, Eni had a total of 29,053 employees, with a decrease of 350 employees, or down by 1.2% from December 31, 2014, which mainly reflects a decrease of 339 employees working outside Italy.

		2013 (1)		2014 (1)		2015 (1)

(number)

Exploration & Production		12,352		12,777		12,821
Gas & Power (2)		4,962		4,561		4,484
Refining & Marketing (2)		8,092		6,441		5,852
Corporate and Other activities		5,564		5,624		5,896
		30,970		29,403		29,053

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The table below sets forth Eni’s employees as of December 31, 2013, 2014 and 2015 in Italy and outside Italy:

		2013 (1)		2014 (1)		2015 (1)

(number)

Exploration & Production		Italy		4,133		4,534		4,572
		Outside Italy		8,219		8,243		8,249
				12,352		12,777		12,821
Gas & Power (2)		Italy		2,310		2,067		2,023
		Outside Italy		2,652		2,494		2,461
				4,962		4,561		4,484
Refining & Marketing (2)		Italy		5,777		4,810		4,475
		Outside Italy		2,315		1,631		1,377
				8,092		6,441		5,852
Corporate and Other activities		Italy		5,407		5,320		5,650
		Outside Italy		157		304		246
				5,564		5,624		5,896
Total		Italy		17,627		16,731		16,720
		Outside Italy		13,343		12,672		12,333
				30,970		29,403		29,053
of which senior managers				970		958		947

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We seek to maintain constructive relationship with labor unions.

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Share ownership

As of February 29, 2016, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 295,973 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		87,241	(1)
Claudio Descalzi		CEO		39,455
Board of Statutory Auditors				6,400	(2)
Senior Managers				162,877	(3)

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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, 2016, the total amount of Eni’s voting securities owned by these shareholders was:

Title of class		Number of shares owned		Percent of class

Ministry of Economy and Finance		157,552,137		4.34
Cassa Depositi e Prestiti SpA		936,179,478		25.76

The following table shows the percentage of Eni’s share capital owned directly or indirectly by subjects that as of March 16, 2016, have notified that their holding exceeds the threshold of 2% pursuant to Article 120 of the Legislative Decree No. 58/1998 and to Consob Resolution No. 11971/99 (Consob Regulations on Issuers)²¹.

Title of class		Percent of class

People’s Bank of China

2.102

Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified Italian legislation governing the special powers of the Italian State to comply with European rules. See "Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)". As of March 28, 2016, there were 29,838,526 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 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 45 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 37 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 0.80 per share for fiscal year 2015.

Currently, in spite of a deteriorated oil price environment compared to one year ago, we confirm our commitment to pay a full cash dividend for fiscal year 2016 of euro 0.80 per share thanks to the results achieved in implementing our strategy including the disposals of non-core asset, which have ensured the Company a certain degree of financial flexibility.

In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year.

The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. For further details see "Item 3 – Risk factors" and the other planning assumptions and initiatives described in "Item 5 – Management’s expectations of operations".

At the General Shareholders’ Meeting scheduled on May 12, 2016, management intend to propose the distribution of a dividend of euro 0.80 per share for fiscal year 2015, of which euro 0.40 was paid as interim dividend in September 2015. Total cash outlay for the 2015 balance dividend is expected at approximately euro 1.5 billion (whereas euro 2 billion were distributed in September 2015) if the General 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 2015 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,
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
2015		17.430		13.140		39.290		29.280
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		16.680		13.370		37.690		31.960
Second quarter		17.430		15.720		39.290		34.940
Third quarter		16.210		13.140		35.610		30.300
Fourth quarter		15.730		13.240		36.020		29.280
2016
First quarter (to March 28, 2016)		13.800		10.930		31.050		25.000
Month of
October 2015		15.730		14.030		36.020		31.430
November 2015		15.430		14.360		33.190		30.780
December 2015		15.370		13.240		32.310		29.280
January 2016		13.550		12.160		29.420		26.820
February 2016		13.140		10.930		28.750		25.000
March 2016 (through March 28, 2016)		13.800		12.940		31.050		29.080

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 28, 2016, there were 29,838,526, ADRs outstanding, representing 59,677,052, ordinary shares or approximately 1.6% of all Eni’s shares outstanding, held by 107 holders of record (including the Depository Trust Company) in the United States, 107 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 Exchange. The constituents of the FTSE MIB are selected based on market capitalization of free-float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for float. Since June 1, 2009, the FTSE MIB is the principal indicator used to

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track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are the first largest component of the FTSE MIB, with a weighting of approximately 13%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective March 21, 2016.

Beginning from October 6, 2014, a two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Market (SeDeX). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated market where it is possible to trade securitized derivatives (for instance, covered warrants and certificates).

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an "official price", calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades and block trades, and a "reference price", calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective March 15, 2016: (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 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.

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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 aforementioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

 

Directors’ issues

Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting.

If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members.

The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions.

According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance.

The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time.

The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors.

In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote.

For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see "Item 6 – Board of Directors’ duties and responsibilities".

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Interests in Company’s transactions
As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob ("Commissione Nazionale per le Società e la Borsa" is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the "Consob Regulation"), the Board of Directors – on November 18, 2010 – unanimously approved the Management System Guidelines "Transactions involving interests of Directors and Statutory Auditors and transactions with related parties"²² ("MSG"), which has been in effect from January 1, 2011²³ to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. This MSG and the subsequent amendments received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The MSG sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required.

Moreover, to ensure compliance with the procedures envisaged by the above mentioned MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in which they 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 2015, 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.

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.

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Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.

In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors.

Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE.

 

Dividend rights
Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations. Specifically, the ordinary Shareholders’ Meeting called to approve the annual Financial Statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.

 

Voting rights
The general provisions on share "voting rights" are described at the paragraph "Shareholders’ Meeting" below. In relation to the appointment of the Board of Directors (Eni’s Board is not a "staggered board") and the Board of Statutory Auditors (see "Item 6"), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 28, 2016, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization), or by the Board of Directors. Each shareholder may, severally or jointly, submit and vote on a single slate only.

There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.

 

Liquidation rights
In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors.

 

Change in shareholders’ rights

A Shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision making quorum established by law for extraordinary meetings.

 

Shareholders’ Meeting

The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in "ordinary" or "extraordinary" form. 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’ Meetings 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.

The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by mail (the information is also available on the Company’s website) and, if envisaged, it may include instructions for

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participating in the Shareholders’ Meeting by means of telecommunication systems, as well as exercising the right to vote by electronic means. The Board of Directors shall make a report on each of the items on the agenda available to the public at the Company’s registered office, on the Company’s website and by other means envisaged by Consob regulations by the same date of the publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements.

The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit and debit records entered on the authorized intermediaries’ accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement, issued by the authorized intermediary, must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the Meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the Meeting; otherwise, the date of each call is deemed the reference date.

Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the Meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collection of proxies shall be made available in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.

The right to vote may also be exercised by mail in accordance with the applicable laws and regulations. If provided for in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules.

The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by applicable laws and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.

The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.

The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his or her opinion on the items on the agenda.

During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information.

 

Stock ownership limitation and voting rights restrictions

There are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to both residents and non-residents of Italy).

In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 3²⁴ 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

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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 rules²⁵.

The new special powers no longer apply to specific State-controlled companies, identified by name, but to companies that hold strategic assets vital to the interests of the Italian State as defined by the ministerial regulations which implement the relevant law.

The current legislation governing the special powers briefly include: a) veto power (or the power of imposing conditions or requirements) over transactions involving strategic assets that could result in a situation, not regulated by Italian or EU laws, that threatens serious injury to interests regarding networks and systems security, as well as continuity of supply; and b) power of attaching conditions or opposing the acquisition by an entity outside of the EU of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets, when such an acquisition may result in a threat of serious injury to the above mentioned essential interests of the Italian State. The shareholding of third parties who have entered into a shareholders' agreement with the buyer is taken into account in the calculation of above mentioned relevant shareholdings.

With particular reference to the power referred to in letter b), the legislation establishes notification obligations for the buyer entity outside of the EU to the Italian Presidency of the Council of Ministers as well as procedural terms. Until such notification and thereafter, up to the expiration of the term for the possible exercise of power, the voting rights and any other non-financial right related to the significant shareholding may not be exercised.

In the case of non-fulfillment of imposed conditions, throughout the relevant period, the voting rights and any other non-financial right related to the significant shareholding may not be exercised. The resolutions adopted with the decisive vote of such shareholding, or otherwise the resolutions or acts adopted in breach or default of the imposed conditions are void. In addition, unless the fact constitutes a crime, failure to comply with imposed conditions entail for the purchaser a fine.

In case of opposition, the buyer may not exercise the voting rights and any other non-financial right related to the significant shareholding, which must be sold within a year. In case of non-compliance, at the request of the Government, the Court will order the sale of the significant shareholding. Shareholders’ Meeting resolutions adopted with the decisive vote of such participation shall be void.

The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of 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

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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 Finance²⁶ and Consob Regulation²⁷, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%²⁸ (until March 17, 2016, the threshold was 2%), 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 3% (until March 17, 2016, the threshold was 2%) of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-quater.1 of the Consolidated Law on Finance) if the threshold is exceeded by both companies subsequent to an agreement authorized in advance by the ordinary shareholders’ meetings of the companies concerned.

If a person holds an interest exceeding the aforementioned threshold of a listed company, such listed company or any person controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended. Where it is not possible to ascertain which of the two persons was the last to exceed the limit, the suspension shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company.

Under the Consolidated Law on Finance, any agreement, in any form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed with the Register of Companies in which the listed company is

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registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights attached to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares may be challenged under the Italian Civil Code.

The same provisions also apply to agreements, in any form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe them; (c) provide for the purchase of the shares or of the above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis) which aim to encourage or frustrate a takeover bid or an exchange tender offer, including commitments relating to non-participation in a takeover bid.

Finally, in accordance with Law No. 287 of October 10, 1990, any merger or acquisition of sole or joint control over a company or any change of control over a company that would create or strengthen a dominant position in the domestic market in a manner that eliminates or significantly reduces competition is prohibited and mergers and acquisition of specified dimension must be subject to the prior authorization of the Italian Antitrust Authority²⁹. However, if the merging parties or the acquiring party and the company to be acquired operate in more than one EU Member State and/or outside Europe and exceed certain thresholds (e.g. turnover, asset value or market share thresholds), the antitrust approval for the merger and/or acquisition can fall under the jurisdiction of the European Commission or the EU Members States and/or other Competition Authorities outside Europe.

 

Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than are required by law.

Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the Shareholders’ resolution 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.

 

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Taxation

The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.

 

Italian taxation

The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.

Income tax
Dividends received by Italian resident individuals in relation to interest exceeding 2% of the voting rights or 5% of the share capital ("substantial interest") are included in the taxable income subject to personal income tax to the extent of 49.72% of their amount. 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 2015 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 undistributed profit of 2007 and previous years.

Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, and società di investimento a capitale variabile (SICAV) are not subject to substitute 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 90 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.

In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes.

Under the Tax Treaty between the United States and Italy, dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a

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reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the IRS) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.

Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.

As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (ADSs), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities 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

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shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non taxability pursuant to the convention have been satisfied.

 

Financial Transactions Tax
Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable is 0.10% for ADR negotiated in regulated markets (like the NYSE).

Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law.

 

Inheritance and gift tax
Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:
(a)		4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding 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

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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 dividends-received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities. For non-corporate U.S. Holders, dividends paid that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by the Group with respect to the Shares or ADSs will generally be qualified as dividend income. The amount of the dividend distribution that must be included in the income of a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot EUR/USD rate on the date the dividend distribution is includible in such person’s income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the U.S. Holder includes the dividend payment in income to the date he or she converts the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a refund of the tax withheld is available to a U.S. Holder under Italian law or under the income tax convention between the United States and Italy, the amount of tax withheld that is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See "Italian taxation – Income tax" above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the shares will be income from sources outside the United States and will, depending on your circumstances, be either "passive" or "general" income for purposes of computing the foreign tax credit allowable to you.

 

Sale or exchange of shares
Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent, determined at the spot rate on the date of disposition). Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.

 

PFIC rules
Eni believes that Shares and ADSs should not be treated as stock of a PFIC for U.S. federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, if classified as a U.S. Holder, 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

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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.

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, 17^th floor, New York, USA.

 

 

 

 

 

 

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Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.

The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and petrochemical operations depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products as in the case of gas prices. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.

As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives.

The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and 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 37 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, 32 and 33 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 and UniCredit SpA are the custodians (the "Custodian") on behalf of the holders of Eni’s ADRs, and their principal offices are located in Milan, Italy.

 

Fees and charges paid by ADR holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees.

 

 

 

 

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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.

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(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 2015, as agreed in the Deposit Agreement with the previous depositary bank, JPMorgan Chase Bank of New York, and subsequent amendments, the Depositary will reimburse to Eni up to US$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 US$196,460.21 for the year ended December 31, 2015.

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, 2015
		(US$)

BNY Mellon products and services		120,000.00
BNY Mellon related to servicing registered shareholders		947.76
BNY Mellon paid to third-party vendors (1)		75,512.45
Total		196,460.21

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(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, 2015.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, 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 2015 and 2014 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, 2015 and 2014, respectively:

	Year ended December 31,

		2014		2015

(euro thousand)

Audit fees		27,607		33,752
Audit-related fees		1,287		1,138
Tax fees		11		3
All other fees		-		-
Total		28,905		34,893

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 2015, 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

The issuer and its affiliated purchasers have not executed any purchase of equity securities of the issuer since the end of 2014 and up to and as of the date of the 20-F filing for the year ended December 31, 2015.

 

 

Item 16F. Change in Registrant’s Certifying Accountant

Not applicable.

 

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Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual

Corporate Governance. Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities. The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code for Italian listed companies, which Eni has adopted (hereinafter the Corporate Governance Code).

 

Independent Directors

NYSE standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year "cooling-off" period following the termination of any relationship that compromised a Director’s independence.

Eni standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of 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, who qualifies as independent, does not or no longer satisfies the independence requirements established by law, the Board declares the Director disqualified and provides for their substitution. Directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise.

 

Meetings of non-executive Directors

NYSE standards. Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors. In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year.

Eni standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year without the other Directors. During 2015, Eni’s independent Directors had numerous opportunities to meet, formally and informally, to hold discussions and exchange opinions.

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Audit Committee

NYSE standards. Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

Eni standards. 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. The Nomination Committee of Eni is made up of three to four Directors, a majority of whom are independent in accordance with the recommendations of the Corporate Governance Code³⁰. 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). On September 17, 2015, the Board appointed Director Alessandro Profumo (independent Director) as a member of the Committee, replacing Luigi Zingales who resigned from the Board on July 2, 2015. Further details on this Committee are reported in the Item 6.

 

Compensation Committee

NYSE standards. U.S. listed companies must have a Compensation Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The Compensation Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The Compensation Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers.

Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a Compensation Committee made up of 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.

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Eni standards. At its Meetings of December 15, 2003 and January 28, 2004, the Board of Directors of Eni approved an organizational, management and control model pursuant to Italian Legislative Decree No. 231 of 2001 (hereinafter "Model 231") and established the associated Eni Watch Structure. Moreover, after subsequent approvals of the updates to Model 231 in response to changes in the Italian legislation governing the matter and in the Company organizational structures, on March 14, 2008, the Board of Directors approved the overall revision of Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of Eni’s Code of Conduct of 1998. The Board of Directors, in its meeting of February 25, 2016, ratified the updating of Model 231 to reflect corporate organizational changes of Eni and incorporate the crime of self laundering, 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. At present, the Watch Structure of Eni SpA is composed of three external members, including the Chairman, and three internal members. The internal members are the Chief Legal & Regulatory Officer, the Executive Vice President in charge of labor law matters and disputes 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, 2015 and 2014	F-3
Consolidated profit and loss account for the years ended December 31, 2015, 2014 and 2013	F-4
Consolidated Statements of comprehensive income for the years ended December 31, 2015, 2014 and 2013	F-5
Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2015, 2014 and 2013	F-6
Consolidated Statement of cash flows for the years ended December 31, 2015, 2014 and 2013	F-9
Notes on 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
15.a(iii) Gaffney, Cline & Associates

 

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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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 12, 2016 expressed an unqualified opinion thereon.

 

/s/ Reconta Ernst & Young SpA

Rome, Italy

April 12, 2016

 

F-1

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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, 2015, 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’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting on page 169. 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, 2015, 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, 2015 and 2014, 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, 2015 and our report dated April 12, 2016 expressed an unqualified opinion thereon.

 

/s/ Reconta Ernst & Young SpA

Rome, Italy

April 12, 2016

F-2

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CONSOLIDATED BALANCE SHEET
(euro million)

				Dec. 31, 2014		Dec. 31, 2015

		Note		Total amount		of which with related parties		Total amount		of which with related parties

ASSETS
Current assets
Cash and cash equivalents		(8)		6,614						5,200
Financial assets held for trading		(9)		5,024						5,028
Financial assets available for sale		(10)		257						282
Trade and other receivables		(11)		28,601			1,973			20,950			1,944
Inventories		(12)		7,555						3,910
Current tax assets		(13)		762						351
Other current tax assets		(14)		1,209						622
Other current assets		(15) (33)		4,385			43			3,639			50
				54,407						39,982
Non-current assets
Property, plant and equipment		(16)		71,962						63,795
Inventory - compulsory stock		(17)		1,581						909
Intangible assets		(18)		3,645						2,433
Equity-accounted investments		(19)		3,115						2,619
Other investments		(19)		2,015						644
Other financial assets		(20)		1,022			239			788			158
Deferred tax assets		(21)		5,231						4,349
Other non-current assets		(22) (33)		2,773			12			1,757			10
				91,344						77,294
Discontinued operations and assets held for sale		(34)		456						17,516			559
TOTAL ASSETS				146,207						134,792
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		(23)		2,716			181			5,712			208
Current portion of long-term debt		(28)		3,859						2,671
Trade and other payables		(24)		23,703			1,954			14,615			1,521
Income taxes payable		(25)		534						422
Other taxes payable		(26)		1,873						1,442
Other current liabilities		(27) (33)		4,489			58			4,703			91
				37,174						29,565
Non-current liabilities
Long-term debt		(28)		19,316						19,393
Provisions for contingencies		(29)		15,898						15,266
Provisions for employee benefits		(30)		1,313						1,056
Deferred tax liabilities		(31)		7,847						6,921
Other non-current liabilities		(32) (33)		2,285			20			1,852			23
				46,659						44,488
Discontinued operations and liabilities directly associated with assets held for sale		(34)		165						7,070			235
TOTAL LIABILITIES				83,998						81,123
SHAREHOLDERS’ EQUITY		(35)
Non-controlling interest				2,455						1,916
Eni shareholders’ equity
Share capital				4,005						4,005
Reserve related to cash flow hedging derivatives net of tax effect				(284	)					(474	)
Other reserves				57,343						59,026
Treasury shares				(581	)					(581	)
Interim dividend				(2,020	)					(1,440	)
Net profit (loss) for the year				1,291						(8,783	)
Total Eni shareholders’ equity				59,754						51,753
TOTAL SHAREHOLDERS’ EQUITY				62,209						53,669
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY				146,207						134,792

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)

		2013		2014		2015

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		(38)		98,547			2,242			93,187			1,483			67,740			1,323
Other income and revenues				1,117			28			1,039			63			1,205			45
				99,664						94,226						68,945
OPERATING EXPENSES		(39)
Purchases, services and other				78,108			7,617			74,067			7,072			53,983			6,816
Payroll and related costs				2,657			38			2,572			60			2,778			55
OTHER OPERATING INCOME (EXPENSE)		(39)		(71	)		68			145			208			(485	)		96
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS		(39)		10,961						10,147						14,480
OPERATING PROFIT (LOSS)				7,867						7,585						(2,781	)
FINANCE INCOME (EXPENSE)		(40)
Finance income				5,030			33			5,672			41			8,576			72
Finance expense				(5,941	)		(85	)		(7,042	)		(55	)		(10,062	)		(54	)
Net finance income from financial assets held for trading				4						24						3
Derivatives financial instruments				(92	)					165						160
				(999	)					(1,181	)					(1,323	)
INCOME (EXPENSE) FROM INVESTMENTS		(41)
Share of profit (loss) from equity-accounted investments				220						104						(452	)
Other gain (loss) from investments				5,863						365						576
- of which gain on disposals of the 28.57% of Eni East Africa				3,359
				6,083						469						124
PROFIT (LOSS) BEFORE INCOME TAXES				12,951						6,873						(3,980	)
Income taxes		(42)		(9,055	)					(6,681	)					(3,147	)
Net profit (loss) for the year - Continuing operations				3,896						192						(7,127	)
Net profit (loss) for the year - Discontinued operations		(34)		1,063			672			658			821			(2,251	)		130
Net profit (loss) for the year				4,959						850						(9,378	)
Attributable to Eni
Continuing operations				3,472						101						(7,680	)
Discontinued operations		(34)		1,688						1,190						(1,103	)
				5,160						1,291						(8,783	)
Attributable to non-controlling interest		(35)
Continuing operations				424						91						553
Discontinued operations		(34)		(625	)					(532	)					(1,148	)
				(201	)					(441	)					(595	)
Earnings per share attributable to Eni (euro per share)		(43)
Basic				1.42						0.36						(2.44	)
Diluted				1.42						0.36						(2.44	)
Earnings per share attributable to Eni - Continuing operations (euro per share)		(43)
Basic				0.96						0.03						(2.13	)
Diluted				0.96						0.03						(2.13	)

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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(euro million)

		Note		2013		2014		2015

Net profit (loss)				4,959			850			(9,378	)
Other items of comprehensive income
Items not to be reclassified to profit or loss in subsequent periods
Remeasurements of defined benefit plans		(35)		65			(82	)		36
Share of other comprehensive income on equity-accounted entities in relation to remeasurements of defined benefit plans		(35)		(3	)		3
Tax effect related to other comprehensive income not to be reclassified to profit or loss in subsequent periods		(35)		(40	)		22			(21	)
				22			(57	)		15
Other comprehensive income to be reclassified to profit or loss in subsequent periods
Foreign currency translation differences		(35)		(1,871	)		5,008			4,534
Change in the fair value of available-for-sale investments		(35)		(64	)		(77	)
Change in the fair value of other available-for-sale financial instruments		(35)		(1	)		7			(4	)
Change in the fair value of cash flow hedging derivatives		(35)		(198	)		(167	)		(256	)
Share of other comprehensive income on equity-accounted entities		(35)					4			9
Tax effect related to other comprehensive income to be reclassified to profit or loss in subsequent periods		(35)		63			30			66
				(2,071	)		4,805			4,331
Total other items of comprehensive income				(2,049	)		4,748			4,346
Total comprehensive income				2,910			5,598			(5,032	)
Attributable to Eni
Continuing operations				1,501			4,779			(3,454	)
Discontinued operations		(34)		1,663			1,217			(1,049	)
				3,164			5,996			(4,503	)
Attributable to non-controlling interest
Continuing operations				411			94			554
Discontinued operations		(34)		(665	)		(492	)		(1,083	)
				(254	)		(398	)		(529	)

 

 

 

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (euro million)

		Eni shareholders’ equity

Note

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of tax effect

Reserve related to the fair value of available-for-sale financial instruments net of 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 for 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																		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																		(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																		(1	)					(1,640	)					(171	)								(1,812	)		(59	)		(1,871	)
Change and reversal of the fair value of investments net of tax effect															(62	)																							(62	)					(62	)
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect															(1	)																							(1	)					(1	)
Change and reversal of the fair value of cash flow hedge derivatives net of tax effect												(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)																														(829	)		1,956			(3,083	)		(1,956	)					(1,956	)
Interim dividend distribution of Eni SpA (euro 0.55 per share)																																	(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																					4																		4			(32	)		(28	)
Payments and reimbursements by/to minority shareholders																																										1			1
Treasury shares sold following the exercise of stock options by Saipem managers																																										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			4,005			959			6,201			(154	)		81			(72	)		296			(698	)		(201	)		44,626			(1,993	)		5,160			58,210			2,839			61,049

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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 tax effect

Reserve related to the fair value of available-for-sale financial instruments net of 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	(35)		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 for 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	(35)																	(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	(35)																	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	(35)																	(1	)					4,718						232									4,949			59			5,008
Change and reversal of the fair value of investments net of tax effect	(35)														(76	)																							(76	)					(76	)
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect	(35)														6																								6						6
Change and reversal the fair value of cash flow hedge derivatives net of tax effect	(35)											(130	)																										(130	)		(7	)		(137	)
Share of "Other comprehensive income" on equity-accounted entities	(35)																				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)	(35)																																1,993			(3,979	)		(1,986	)					(1,986	)
Interim dividend distribution of Eni SpA (euro 0.56 per share)	(35)																																(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	(35)																										(380	)											(380	)					(380	)
Payments and reimbursements by/to minority shareholders	(35)																																									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	(35)		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 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 tax effect

Reserve related to the fair value of available-for-sale financial instruments net of 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 (loss) for the year

Other comprehensive income (loss) related to discontinued operations

Total

Non- controlling interest

Total shareholders’ equity

Balance at December 31, 2014	(35)		4,005			959			6,201			(284	)		11			(122	)		207			4,020			(581	)		46,067			(2,020	)		1,291						59,754			2,455			62,209
Net loss for the year																																				(8,783	)					(8,783	)		(595	)		(9,378	)
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	(35)																	14																								14			1			15
Share of "Other comprehensive income" on equity-accounted entities in relation to remeasurements of defined benefit plans net of tax effect	(34) (35)																	17																					(17	)
																		31																					(17	)		14			1			15
Other comprehensive income to be reclassified to profit or loss in subsequent periods
Foreign currency translation differences	(35)																	(1	)					4,419						54												4,472			62			4,534
Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect	(35)														(3	)																										(3	)					(3	)
Change and reversal the fair value of cash flow hedge derivatives net of tax effect	(35)											(194	)																													(194	)		3			(191	)
Share of "Other comprehensive income" on equity-accounted entities	(35)																				(9	)																				(9	)					(9	)
Reclassification of "Other comprehensive income" related to discontinued operations	(34) (35)											4												(32	)														28
												(190	)		(3	)		(1	)		(9	)		4,387						54									28			4,266			65			4,331
Total comprehensive income of the year												(190	)		(3	)		30			(9	)		4,387						54						(8,783	)		11			(4,503	)		(529	)		(5,032	)
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.56 per share in settlement of 2014 interim dividend of euro 0.56 per share)	(35)																																2,020			(4,037	)					(2,017	)					(2,017	)
Interim dividend distribution of Eni SpA (euro 0.40 per share)	(35)																																(1,440	)								(1,440	)					(1,440	)
Dividend distribution of other companies																																													(21	)		(21	)
Allocation of 2014 net profit																														(2,746	)					2,746
Payments and reimbursements by/to minority shareholders	(35)																																												1			1
																														(2,746	)		580			(1,291	)					(3,457	)		(20	)		(3,477	)
Other changes in shareholders’ equity
Elimination of intercompany profit between companies with different Group interest																														(28	)											(28	)		28
Exclusion from the scope of consolidation of non-significant companies and changes in non-controlling interests																														(7	)											(7	)		(10	)		(17	)
Reclassification of the reserve for treasury shares									(5,620	)																				5,620
Other changes																					(18	)								12												(6	)		(8	)		(14	)
									(5,620	)											(18	)								5,597												(41	)		10			(31	)
Balance at December 31, 2015	(35)		4,005			959			581			(474	)		8			(92	)		180			8,407			(581	)		48,972			(1,440	)		(8,783	)		11			51,753			1,916			53,669

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)

		Note		2013		2014		2015

Net profit (loss) for the year							3,896						192						(7,127	)
Adjustments to reconcile net profit (loss) to net cash provided by operating activities
Depreciation and amortization		(39)					8,605						9,134						9,654
Impairments of tangible and intangible assets, net		(39)					2,356						1,013						4,826
Share of (profit) loss of equity-accounted investments		(41)					(220	)					(104	)					452
Gain on disposal of assets, net							(3,877	)					(99	)					(559	)
Dividend income		(41)					(400	)					(384	)					(402	)
Interest income							(137	)					(162	)					(153	)
Interest expense							685						687						667
Income taxes		(42)					9,055						6,681						3,147
Other changes							(1,839	)					864						588
Changes in working capital:
- inventories				431						1,557						1,228
- trade receivables				(1,189	)					1,969						4,910
- trade payables				720						(1,520	)					(2,248	)
- provisions for contingencies				(22	)					(218	)					70
- other assets and liabilities				181						360						490
Cash flow from changes in working capital							121						2,148						4,450
Net change in the provisions for employee benefits							15						12						1
Dividends received							629						601						544
Interest received							93						107						79
Interest paid							(917	)					(857	)					(692	)
Income taxes paid, net of tax receivables received							(8,933	)					(6,671	)					(4,294	)
Net cash provided by operating activities - Continuing operations							9,132						13,162						11,181
Net cash provided by operating activities - Discontinued operations		(34)					1,894						1,948						722
Net cash provided by operating activities							11,026						15,110						11,903
- of which with related parties		(45)					(2,911	)					(3,203	)					(3,966	)
Investing activities:
- tangible assets		(16)					(10,913	)					(10,685	)					(10,619	)
- intangible assets		(18)					(1,887	)					(1,555	)					(937	)
- consolidated subsidiaries and businesses		(36)					(25	)					(36	)
- investments		(19)					(292	)					(372	)					(228	)
- securities							(5,048	)					(77	)					(201	)
- financing receivables							(978	)					(1,289	)					(1,103	)
- change in payables and receivables in relation to investing activities and capitalized depreciation							50						669						(1,058	)
Cash flow from investing activities							(19,093	)					(13,345	)					(14,146	)
Disposals:
- tangible assets							514						97						373
- intangible assets							16						8						86
- consolidated subsidiaries and businesses		(36)					3,401												73
- investments							2,429						3,579						1,726
- securities							36						57						18
- financing receivables							1,561						506						533
- change in payables and receivables in relation to disposals							155						155						160
Cash flow from disposals							8,112						4,402						2,969
Net cash used in investing activities							(10,981	)					(8,943	)					(11,177	)
- of which with related parties		(45)					(390	)					(1,458	)					(1,583	)

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CONSOLIDATED STATEMENT OF CASH FLOWS continued
(euro million)

		Note		2013		2014		2015

Proceeds from long-term debt		(28)		5,418			1,916			3,376
Repayments of long-term debt		(28)		(4,720	)		(2,751	)		(4,466	)
Increase (decrease) in short-term debt		(23)		1,017			207			3,216
				1,715			(628	)		2,126
Net capital contributions by non-controlling interest				1			1			1
Sale of treasury shares different from Eni SpA				1
Sale (acquisition) of additional interests in consolidated subsidiaries				(28	)
Dividends paid to Eni’s shareholders				(3,949	)		(4,006	)		(3,457	)
Dividends paid to non-controlling interest				(250	)		(49	)		(21	)
Acquisition of treasury shares							(380	)
Net cash used in financing activities				(2,510	)		(5,062	)		(1,351	)
- of which with related parties		(45)		119			(99	)		13
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)				2			2			(13	)
Cash and cash equivalents related to discontinued operations										(898	)
Effect of exchange rate changes on cash and cash equivalents and other changes				(42	)		76			122
Net cash flow of the year				(2,505	)		1,183			(1,414	)
Cash and cash equivalents - beginning of the year		(8)		7,936			5,431			6,614
Cash and cash equivalents - end of the year		(8)		5,431			6,614			5,200

 

 

 

 

 

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Notes on Consolidated Financial Statements

In 2015 Consolidated Financial Statements, “Engineering & Construction” operating segment and “Chemical” business, managed respectively by Saipem SpA (Eni 42.91%) and Versalis SpA (Eni 100%), have been classified as “discontinued operations” based on the guidelines of IFRS 5¹. At the reporting date there was the firm commitment of the management to achieve the sale transaction, whose fulfillment is considered to be highly probable during following 12 months, which implies the loss of control over the two businesses keeping a non controlling interest. Economic results of the comparative reporting periods have been restated consistently.

With reference to Saipem, the sale transaction was finalized on January 22, 2016 with the closing of the sale of 12.5% of Saipem share capital by Eni to Fondo Strategico Italiano and the concurrent enter into force of the shareholders’ agreement between Eni and FSI which has modified Saipem’s corporate governance establishing the joint control of the two parties over Saipem; therefore, starting from January 1, 2016, Eni will exclude the former subsidiary from its consolidation area and will account for the investment retained using the equity method.

With reference to Chemical business, Eni has received an expression of interest by a potential industrial partner to acquire the controlling stake of Versalis, and negotiations are underway in order to define a shared industrial plan.

Because Eni is exiting two major lines of business, the mentioned businesses have been represented and accounted for as discontinued operations. Based on this accounting, results pertaining to the discontinued operations are presented separately from continuing operations and include only those from transactions with counterparties external to the Group. Any transactions between discontinued and continuing operations are eliminated as usual in the consolidation because both Saipem and Versalis and their own subsidiaries remain consolidated in 2015 Group financial statements. The accounting of the discontinued operations entails that, in presence of large intercompany transactions between discontinued and continuing operations, the results of the continuing operations do not fully represent the activities of the continuing operations as individual entities, due to the elimination of the results from intercompany transactions with the discontinued operations. In the case of Saipem, the costs incurred by the entity for the supply of capital goods (equipments and other facilities) and maintenance services to Eni’s Group companies are eliminated upon consolidation. However, in the case of Versalis, the revenues earned by the Group operating companies, mainly in the R&M segment, for the supply of oil-based chemical feedstock and other plant utilities, are eliminated upon consolidation.

Furthermore, with reference to Saipem’s non-current assets, Eni ceased recognizing depreciation charges starting from the classification date (November 1, 2015; Versalis was classified as discontinued operations at the reporting date). The carrying amounts of goodwill and other non-current assets at both disposal groups were adjusted to take into account the remeasurement of the two disposal groups’ net assets to their fair values at the reporting date, given by the market price for Saipem and the fair value based on the transaction that is underway for Versalis. Financial information of discontinued operations are indicated in note 34.

 

 

1 Basis of presentation

The Consolidated Financial Statements of Eni Group have been prepared in accordance with the International Financial Reporting Standards (IFRS)² 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 IFRSs must be measured at fair value as described in the paragraph “Summary of significant accounting policies”.

The 2015 Consolidated Financial Statements approved by Eni’s Board of Directors on April 7, 2016, 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).

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2 Principles of consolidation

Subsidiaries
The Consolidated Financial Statements include the financial statements of the parent company Eni SpA and those of its Italian and foreign 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 significant³ 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 the remeasurement of any investment retained in the former subsidiary to its fair value; and (iii) any amount related to the former subsidiary previously recognized in other comprehensive income which can be reclassified subsequently to profit and loss account⁴. Any investment retained in the former subsidiary is recognized at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria.

 

Interests in joint arrangements
A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

A joint operation is a joint arrangement whereby the parties 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 accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of impairment losses.

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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 method⁵.

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 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 Group 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 the remeasurement of any investment retained in the former joint venture/associate to its fair value⁶; 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 account⁷. Any investment retained in the former joint venture/associate is recognized at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria.

The investor’s share of losses of an investee, that exceeds the carrying amount of the investment, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to fund its losses.

 

Business combinations
Business 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 values⁸, 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.

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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 them⁹. 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 remeasured 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 exchange rates 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”¹⁰. 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 “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 investees 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.

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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 2013		Exchange rate at Dec. 31, 2013		Annual average exchange rate 2014		Exchange rate at Dec. 31, 2014		Annual average exchange rate 2015		Exchange rate at Dec. 31, 2015

U.S. dollar		1.33		1.38		1.33		1.21		1.11		1.09
British pound		0.85		0.83		0.81		0.78		0.73		0.73
Norwegian krone		7.81		8.36		8.35		9.04		8.95		9.60
Australian dollar		1.38		1.54		1.47		1.48		1.48		1.49
Hungarian forint		296.87		297.04		308.71		315.54		310.00		315.98

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 activities¹¹

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 expenditures", 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&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 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.

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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 above mentioned. 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"¹².

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. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any existing item of property, plant and equipment, are recognized as assets when they are necessary to obtain future economic benefits from other assets.

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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 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. Leasehold improvement costs are depreciated over the useful life of the improvements or, if lower, over the residual length of the lease, considering any renewal period if renewal depends entirely on the lessee and is virtually certain. Expenditures for ordinary maintenance and repairs are 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 is based on the forward prices prevailing in the marketplace, if there is a sufficient liquidity and reliability level, and on management’s long-term planning assumptions thereafter. When commodity prices fluctuate quite considerably, management considers the most updated variables available; in particular, for 2015, management estimated a price scenario based on: (i) the most recent trends of forward curves observed in January 2016; (ii) the consensus of a significant sample of independent analysts; and (iii) 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 asset. The measurement of the specific country risk to be included in the discount rate is defined considering information provided by external parties. WACC differs considering the risk associated with each operating segments where the asset operates. In particular for the assets belonging to the Gas & Power segment, taking into account its different risk compared with Eni as a whole, a specific WACC rate has been defined on the basis of a sample of companies operating in the same segment adjusted to take into consideration the risk premium of the specific country of the activity¹³. 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 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. 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 shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

The carrying amount of property, plant and equipment is derecognized on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognized in profit and loss account.

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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 impairment indicators occur. 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 amoun¹⁴, 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 reversed¹⁵.

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 and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate 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 service¹⁶.

The carrying amount of intangible assets is derecognized on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognized in profit and loss account.

 

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

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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.

 

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 construction contracts in progress 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 reserve¹⁷ 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)"¹⁸ 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.

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Receivables are measured at amortized cost (see below the accounting policy for "Non-current financial assets").

 

Non-current financial assets

Investments
Investments in equity instruments¹⁹ 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. 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 reversed²⁰.

Receivables and held-to-maturity financial assets
Receivables and held-to-maturity financial assets are accounted for at cost, that is the fair value of the initial consideration plus transaction costs (e.g. fees 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 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
Financial liabilities, other than derivative financial instruments, are measured at amortized cost (see above the accounting policy for "Non-current financial assets").

 

Derivatives
Derivatives, including embedded derivatives (see below) 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.

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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".

Embedded derivatives in hybrid instruments are separated from the host contract and accounted for as a derivative if the hybrid instruments are not measured at fair value with changes in fair value recognized in profit and loss account and if the economic characteristics and risks of the embedded derivatives are not closely related to those of the host contracts. The entity assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows, occurs.

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).

 

Offsetting of financial assets and liabilities
Financial assets and liabilities are set off in the balance sheet if the group has a legally enforceable right to set off and intends to settle on a net basis (or to realize the asset and settle the liability simultaneously).

 

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 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 29.

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Employee benefits
Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment.

Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. 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 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

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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 revenue. 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. Amounts collected or to be collected on behalf of third parties are not revenues.

Award credits, related to customer loyalty programs, are recognized as a 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. 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. The classification of non-current assets (or disposal groups) as held for sale requires the management to perform subjective judgments based on assumptions deemed reasonable in consideration of the information available at the time.

Immediately before the initial classification of a disposal group as held for sale, the assets and liabilities of the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell and their carrying amount. After the classification as held for sale of 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 of non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale. Non-current assets and current and non-current assets included within disposal groups, classified as held for sale, are considered a discontinued operation if, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognized on the disposal, are indicated in a separate 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.

 

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.

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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 financial instruments takes into account the counterparty’s credit risk for a financial asset (credit valuation adjustment, CVA) and the entity’s own credit risk for a financial liability (debit valuation adjustment, DVA).

In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs.

4 Financial statements²¹

Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature²². Assets and liabilities are classified as current when: (i) they are expected to be realized/settled in the entity’s normal operating cycle or within twelve months after the balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative instruments are classified as current when they are expected to be realized/settled within twelve months after the balance sheet date; on the contrary they are classified as non current.

The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS. The statement of changes in shareholders’ equity includes the 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 new or amended standards or interpretations effective from January 1, 2015 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.

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Oil and gas activities
Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil&gas reserves can be categorized as “proved”, the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgment. 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&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. Estimated proved reserves are affected, inter alia, by the trend of reference oil and gas commodity prices and by the specific legal agreement for the oil&gas activity.

In addition, estimated proved reserves are used to calculate future cash flows from oil&gas properties, which are used to assess any impairment loss. The larger is the volume of estimated reserves, the lower is the likelihood of asset impairment.

 

Impairment of assets
Assets are impaired when there are events or changes in circumstances that indicate that carrying 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&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&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

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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 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&gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil&gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental 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.

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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 sales of electricity and gas to retail customers include amount accrued for electricity and gas supplied between the date of the last invoice and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as they rely on other factors, considered by the management, which can impact on them. Information communicated by operators are adjusted within the fifth year subsequent the one in which it accrued, according to applicable regulations, in order to consider information about actual consumptions.

7 Recent accounting standards

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.

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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, 2018.

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. On December 17, 2015, the IASB issued an amendment which postpones indefinitely the application of the amendments to IFRS 10 and IAS 28.

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.

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 January 13, 2016, the IASB issued IFRS 16 “Leases” (hereinafter IFRS 16), which replaces IAS 17 and related interpretations. In particular, IFRS 16 defines a lease as a contract which conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration. The new IFRS eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial statements; for all leases with a term of more than 12 months, the lessee shall recognize an asset, as the right-of-use, and a liability, as the present value of the lease payments. Conversely, a lessor continues to classify its leases as operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and for lessors. IFRS 16 shall be applied starting from January 1, 2019.

On January 19, 2016, the IASB issued the amendments to IAS 12 “Recognition of Deferred Tax Assets for Unrealized Assets”, which: (i) confirm that a deductible temporary difference exists if the carrying amount of an asset measured at fair value is lower than its tax base (e.g. fixed-rate debt instrument whose fair value is lower that its tax base); (ii) provide that the estimate of probable future taxable profit may include the recovery of some of an entity’s assets for more than their carrying amount if there is sufficient evidence that it is probable that the entity will achieve this. This may be the case when an entity expects to hold a fixed-rate debt instrument until its maturity date and to collect the contractual cash flows, whose fair value at reporting date is lower than its principal paid at maturity date; (iii) define that future taxable profits to be considered in order to recognize a deferred tax asset shall exclude tax deductions resulting from the reversal of those deductible temporary differences; and (iv) state that, when an entity assesses whether taxable profits will be available against which it can utilize a deductible temporary difference, it considers whether tax law restricts the sources of taxable profits against which it may make deductions on the reversal of that deductible temporary difference. The amendments to IAS 12 shall be applied for annual periods beginning on or after January 1, 2017.

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On January 29, 2016, the IASB issued the amendments to IAS 7 "Disclosure Initiative", which enhance disclosures required in case of changes in liabilities arising from financing activities, including both changes arising from cash flows and non-cash changes. The amendments to IAS 7 shall be applied for annual periods beginning on or after January 1, 2017.

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 5,200 million (euro 6,614 million at December 31, 2014) included financial assets with maturity of three months or less at the date of inception amounting to euro 3,289 million (euro 3,373 million at December 31, 2014) and mainly included short-term deposits having notice of more than 48 hours.

Cash and cash equivalents for euro 898 million were reclassified as discontinued operations.

The average maturity of financial assets due within 90 days was 8 days and the average interest rate amounted to 0.25% (0.15% at December 31, 2014).

9 Financial assets held for trading

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Quoted bonds issued by sovereign states		1,325		925
Other		3,699		4,103
		5,024		5,028

The breakdown by currency is provided below:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Euro		4,996		3,906
Swiss franc		12		524
U.S. dollar				272
British pound		16		271
Canadian dollar				36
Australian dollar				19
		5,024		5,028

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The breakdown by issuing entity and credit rating 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		520		529		Baa2		BBB-
Spain		190		198		Baa2		BBB+
European Union		48		50		Aaa		AA+
Czech Republic		26		25		A1		AA-
France		23		23		Aa2		AA
Poland		19		18		A2		A-
Germany		13		13		Aaa		AAA
Austria		13		12		Aaa		AA+
Canada		3		3		Aaa		AAA
Sweden		3		2		Aaa		AAA
Japan		1		1		A1		A+
		859		874
Floating rate bonds
France		49		49		Aa2		AA
Sweden		2		2		Aaa		AAA
		51		51
Total quoted bonds issued by sovereign states		910		925
Other bonds
Fixed rate bonds
Quoted bonds issued by industrial companies		2,142		2,243		from Aaa to Baa3		from AAA to BBB-
Quoted bonds issued by financial and insurance companies		1,397		1,423		from Aaa to Baa3		from AAA to BBB-
European Investment Bank		2		2		Aaa		AAA
		3,541		3,668
Floating rate bonds
Quoted bonds issued by financial and insurance companies		332		332		from Aaa to Baa3		from AAA to BBB-
Quoted bonds issued by industrial companies		103		103		from Aaa to Baa3		from AAA to BBB-
		435		435
Total other bonds		3,976		4,103
Total other financial assets held for trading		4,886		5,028

The fair value hierarchy is level 1 and was determined based on market quotations.

10 Financial assets available for sale

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Securities held for operating purposes
Quoted bonds issued by sovereign states		204		243
Quoted securities issued by financial institutions		40		39
		244		282
Securities held for non-operating purposes
Quoted bonds issued by sovereign states		6
Quoted securities issued by financial institutions		7
		13
		257		282

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The breakdown by currency is provided below:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Euro		216		241
U.S. dollar		39		41
Indian rupee		2
		257		282

At December 31, 2015, bonds issued by sovereign states amounted to euro 243 million (euro 210 million at December 31, 2014). The breakdown 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

Spain

30

34

from 1.40 to 5.50

from 2016 to 2021

Baa2

BBB+

Belgium

27

32

from 3.75 to 4.25

from 2019 to 2021

Aa3

AA

Italy

27

27

from 0.65 to 5.75

from 2016 to 2020

Baa2

BBB-

Portugal

18

19

from 4.20 to 4.75

from 2016 to 2019

Ba1

BB+

France

17

19

from 1.00 to 3.25

from 2018 to 2023

Aa2

AA

Ireland

17

19

from 0.80 to 4.50

from 2019 to 2022

Baa1

A +

Poland

16

19

from 4.50 to 6.38

from 2019 to 2022

A2

A-

Slovakia

15

16

from 1.50 to 4.20

from 2016 to 2018

A2

A+

Iceland

14

15

from 2.50 to 5.88

from 2020 to 2022

Baa2

BBB

Finland

8

8

from 1.13 to 1.75

from 2017 to 2019

Aaa

AA+

Czech Republic

7

8

3.63

2021

A1

AA-

Slovenia

7

8

2.25

2022

Baa3

A-

Netherlands

6

7

4.00

from 2016 to 2018

Aaa

AAA

United States

7

7

from 1.25 to 3.13

from 2019 to 2020

Aaa

AA+

Canada

5

5

1.63

2019

Aaa

AAA

221

243

Quoted securities amounting to euro 39 million (euro 47 million at December 31, 2014) were issued by financial institutions with a rating Aaa (Moody’s) and AAA (S&P).

Securities held for non-operating purposes of euro 26 million were reclassified as discontinued operations.

Securities held for operating purposes of euro 282 million (euro 244 million at December 31, 2014) were designated to hedge the loss provisions of the Group’s insurance company Eni Insurance Ltd.

The effects of fair value measurement of securities are set out below:

(euro million)		Carrying amount at Dec. 31, 2014		Changes recognized in equity		Carrying amount at Dec. 31, 2015

Fair value		13			(4	)		9
Deferred tax liabilities		(2	)		1			(1	)
Other reserves of shareholders’ equity		11			(3	)		8

The fair value was determined based on market quotations. The fair value hierarchy is level 1.

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11 Trade and other receivables

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Trade receivables		19,709		12,022
Financing receivables:
- for operating purposes - short term		423		375
- for operating purposes - current portion of long-term receivables		839		1,238
- for non-operating purposes		555		685
		1,817		2,298
Other receivables:
- from disposals		86		33
- other		6,989		6,597
		7,075		6,630
		28,601		20,950

Trade receivables decreased by euro 7,687 million mainly in the Gas & Power segment (down by euro 4,462 million).

Trade receivables for euro 3,026 million were reclassified as discontinued operations.

Receivables are stated net of the valuation allowance for doubtful accounts of euro 1,937 million (euro 2,353 million at December 31, 2014):

(euro million)		Carrying amount at Dec. 31, 2014		Additions		Deductions		Other changes		Carrying amount at Dec. 31, 2015

Trade receivables		1,674		581		(247	)		(239	)		1,769
Financing receivables		59							7			66
Other receivables		620		46		(584	)		20			102
		2,353		627		(831	)		(212	)		1,937

Additions to allowance for doubtful accounts amounted to euro 581 million (euro 518 million in 2014) and related mainly to the Gas & Power segment for euro 549 million. This is reflective of the continuing difficulties in receivable collection in the retail customers segment. The allowance included a provision on accrued revenues in the retail segment for sales of gas (euro 130 million) and electricity (euro 96 million) relating to prior reporting periods. Eni adopted all the necessary actions to mitigate the counterparty risk through a large-scale recovery of doubtful accounts and specific external services.

Deductions amounting to euro 247 million (euro 154 million in 2014) related to the Gas & Power segment for euro 177 million.

At December 31, 2015, Eni had in place transactions to transfer to factoring institutions certain trade receivables without recourse for euro 743 million, due in 2016 (euro 1,794 million at December 31, 2014, due in 2015). Transferred receivables related to the Gas & Power segment. Furthermore, certain trade receivables without recourse due in 2016 were transferred by discontinued operations for euro 37 million and through Eni’s subsidiary Serfactoring SpA for euro 64 million.

Trade receivables outstanding as of December 31, 2015, included: (i) trade receivables overdue in the Exploration & Production segment for euro 771 million relating to equity hydrocarbons volumes supplied to Egyptian State-owned companies. This amount was reduced from euro 966 million outstanding at June 30, 2015, due to a stream of reimbursements received pursuant to the finalization of certain commercial agreements with the counterparties and a petroleum contract which included a mechanism to reduce the amounts owed by the Egyptian companies to Eni. In 2016, recovery actions will continue with those State-owned companies and other local governmental authorities leveraging on the established relationships with Egyptian counterparties; (ii) receivables for revenues accrued at the reporting date for volumes of gas and electricity delivered to retail customers in the G&P retail business, yet to be invoiced. The estimation on retail sales is performed also by using data communicated by national and local network operators that are responsible for verifying actual consumptions with the possibility of reviews and adjustments until the fifth subsequent reporting period. In 2015, management performed an estimate revision of revenues accrued on gas sales (euro 346 million) and power sales (euro 138 million) to retail customers in Italy dating back to the past reporting periods.

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The ageing of trade and other receivables is presented below:

		Dec. 31, 2014		Dec. 31, 2015

(euro million)		Trade receivables		Other receivables		Trade receivables		Other receivables

Neither impaired nor past due		15,575		5,713		9,257		5,308
Impaired (net of the valuation for doubtful accounts)		1,804		196		1,082		93
Not impaired and past due in the following periods:
- within 90 days		1,088		232		1,066		89
- 3 to 6 months		550		105		106		501
- 6 to 12 months		244		10		220		477
- over 12 months		448		819		291		162
		2,330		1,166		1,683		1,229
		19,709		7,075		12,022		6,630

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.

Trade receivables in currencies other than euro amounted to euro 3,939 million (euro 8,066 million at December 31, 2014). Trade receivables in currencies other than euro amounting to euro 1,941 million were reclassified as discontinued operations.

Financing receivables associated with operating purposes of euro 1,613 million (euro 1,262 million at December 31, 2014) included loans granted to joint ventures and associates to fund the execution of Eni’s capital projects for euro 1,126 million (euro 764 million at December 31, 2014) and cash deposits to hedge the loss provision made by Eni Insurance Ltd for euro 287 million (euro 332 million at December 31, 2014). The increase of euro 351 million comprised the extension of the financing loans for euro 411 million granted to the equity-accounted investee CARDÓN IV SA (Eni’s share being 50%) which is currently executing exploration and development activities in Venezuela.

Financing receivables associated with operating purposes for euro 149 million were reclassified as discontinued operations.

Financing receivables associated with non-operating activities amounted to euro 685 million (euro 555 million at December 31, 2014) and related to: (i) receivables relating margins on derivatives of Eni Trading & Shipping SpA for euro 457 million (euro 203 million at December 31, 2014); and (ii) restricted deposits in escrow for euro 209 million of Eni Trading & Shipping SpA (euro 287 million at December 31, 2014) of which euro 197 million with BNP Paribas and euro 11 million with ABN AMRO relating to derivatives.

Financing receivables associated with non-operating activities for euro 31 million were reclassified as discontinued operations.

Financing receivables in currencies other than euro amounted to euro 1,329 million (euro 1,063 million as of December 31, 2014).

In the course of 2015, Eni completed the collection of the receivable (euro 52 million outstanding at December 31, 2014) related to the divestment finalized in 2012 of a 3.25% interest in the Karachaganak project (equal to Eni’s 10% interest) to the Kazakh partner KazMunayGas as part of an agreement between the Contracting Companies of the Final Production Sharing Agreement (FPSA) and Kazakh Authorities which settled disputes on the recovery of the costs incurred by the International Consortium and certain tax claims. The receivable accrued interest income at market rates.

Other receivables of euro 6,597 million (euro 6,989 million at December 31, 2014) comprised euro 773 million (euro 663 million at December 31, 2014) of receivables related to the recovery of costs incurred for the development of two oil projects in the Exploration & Production segment. To recover its receivables, Eni commenced two arbitration proceedings that led respectively to the issuance of a final ruling in 2014 and a partial ruling in 2013, in both cases in favor of Eni. In a case, a final ruling could be issued by the Arbitration Committee on condition that certain restrictive measures issued by a local court which are currently blocking the arbitration would be revoked. Receivables amounting to euro 91 million at December 31, 2014 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 were fully cashed-in.

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Other receivables for euro 590 million were reclassified as discontinued operations.

Other receivables were as follows:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Receivables originated from divestments		86		33
Accounts receivable from:
- joint venture partners in exploration and production		4,837		4,656
- prepayments for services		857		496
- insurance companies		164		113
- non-financial government entities		18		104
- factoring arrangements		140		90
- non-Italian oil entities for oil tax refunds		47		27
- other receivables		926		1,111
		6,989		6,597
		7,075		6,630

Receivables from joint venture partners in exploration and production activities of euro 281 million (euro 207 million at December 31, 2014) included the liability for defined-benefit plans (see note 30 – Provisions for employee benefits).

Receivables from factoring arrangements of euro 90 million (euro 140 million at December 31, 2014) 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 5,909 million (euro 6,004 million at December 31, 2014).

Because of the short-term maturity and conditions of remuneration of trade and other receivables, the fair value approximated the carrying amount.

Receivables with related parties are described in note 45 – Transactions with related parties.

12 Inventories

		Dec. 31, 2014		Dec. 31, 2015

(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		468		210				2,177		2,855		179		35				1,879		2,093
Products being processed and semi-finished products		34		11				1		46		97						1		98
Work in progress						1,768				1,768						7				7
Finished products and goods		2,022		699				131		2,852		1,552		13				72		1,637
Certificates and emission rights								34		34								75		75
		2,524		920		1,768		2,343		7,555		1,828		48		7		2,027		3,910

Other inventories of raw and auxiliary materials and consumables of euro 1,879 million (euro 2,177 million at December 31, 2014) related to the Exploration & Production segment for euro 1,732 million and primarily comprised materials relating to perforation activities and the maintenance of infrastructures and facilities.

Certificates and emission rights of euro 75 million (euro 34 million at December 31, 2014) are measured at level 1 fair value based on market prices.

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Inventories of euro 87 million (euro 213 million at December 31, 2014) 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

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
2015
Gross carrying amount		8,027			(635	)								(8	)		249			(3,469	)		4,164
Loss provision		(472	)					(86	)		168			3			(10	)		143			(254	)
Net carrying amount		7,555			(635	)		(86	)		168			(5	)		239			(3,326	)		3,910

Negative changes of the period amounting to euro 635 million related to Gas & Power segment for euro 377 million and the Refining & Marketing segment for euro 322 million and were due to the impact of lower commodity prices on inventories evaluated at the weighted average cost method and to reduction due to ongoing optimization measures. The Exploration & Production segment recorded a euro 64 million increase. Additions for euro 86 million and deductions for euro 168 million of the loss provision primarily related to the Refining & Marketing segment (euro 38 million and euro 148 million, respectively), in particular, in relation to the alignment of the weighted average cost of inventories of crude oil and refined products to their net realizable values as of December 31, 2015.

Other changes of euro 3,326 million included the reclassification of euro 2,852 million as discontinued operations.

13 Current tax assets

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Italian subsidiaries		472		174
Subsidiaries outside Italy		290		177
		762		351

Current tax assets for euro 262 million were reclassified as discontinued operations.

Income taxes are described in note 42 – Income taxes.

14 Other current tax assets

(euro million)		Dec. 31, 2014		Dec. 31, 2015

VAT		817		379
Excise and customs duties		200		121
Other taxes and duties		192		122
		1,209		622

Current tax assets for euro 384 million were reclassified as discontinued operations.

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15 Other current assets

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Fair value of derivative financial instruments		3,299		3,220
Other current assets		1,086		419
		4,385		3,639

The fair value related to derivative financial instruments is disclosed in note 33 – Derivative financial instruments.

Other assets amounting to euro 419 million (euro 1,086 million at December 31, 2014) included: (i) gas volumes prepayments decreased by euro 388 million to an amount of euro 108 million outstanding as of December 31, 2015 (euro 496 million at December 31, 2014) that were made in previous reporting period due to the take-or-pay obligations in the Company’s long-term supply contracts, as the Company is forecasting to make-up the underlying gas volumes in the next 12 months based on its sales plans and the flexibility achieved following contract renegotiations. 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 37 million (euro 124 million at December 31, 2014); (iii) pre-paid rentals for euro 18 million (euro 51 million at December 31, 2014); and (iv) pre-paid insurance premiums for euro 3 million (euro 36 million at December 31, 2014).

Other current assets for euro 182 million were reclassified as discontinued operations.

Transactions with related parties are described in note 45 – Transactions with related parties.

Non-current assets

16 Property, plant and equipment

(euro million)

Net book amount at the beginning of the year

Additions

Depreciation

Impairment losses

Currency translation differences

Reclassification to discontinued operations and assets held for sale

Other changes

Net book amount at the end of the year

Gross book amount at the end of the year

Provisions for depreciation and impairments

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	)		3,363			(3	)		7,040			46,745		140,353		93,608
Industrial and commercial equipment		450		129		(121	)		(15	)		21						126			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	)		5,095			(138	)		2,284			71,962		174,027		102,065
2015
Land		615		1								(13	)		(98	)		(97	)		408		423		15
Buildings		1,633		32		(64	)		(23	)		16			(602	)		(196	)		796		3,053		2,257
Plant and machinery		46,745		5,226		(8,246	)		(2,253	)		3,212			(6,264	)		1,581			40,001		139,732		99,731
Industrial and commercial equipment		590		48		(84	)		(1	)		14			(197	)		(45	)		325		1,259		934
Other assets		458		52		(88	)		(427	)		17			(37	)		419			394		2,104		1,710
Tangible assets in progress and advances		21,921		5,260					(1,964	)		1,701			(311	)		(4,736	)		21,871		25,978		4,107
		71,962		10,619		(8,482	)		(4,668	)		4,947			(7,509	)		(3,074	)		63,795		172,549		108,754

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A breakdown by segment of capital expenditures made in 2015 is provided below:

(euro million)		2014		2015

Capital expenditures
Exploration & Production		9,081			9,385
Gas & Power		114			109
Refining & Marketing		527			401
Chemical		277			213
Engineering & Construction		682			550
Corporate and Other activities		86			46
Elimination of intragroup profits		(82	)		(85	)
		10,685			10,619

Capital expenditures included capitalized finance expenses of euro 158 million (euro 156 million in 2014) and related to the Exploration & Production segment (euro 149 million). The interest rates used for capitalizing finance expense ranged from 2.4% to 5.3% (2.7% and 5.3% at December 31, 2014).

The main depreciation rates used were substantially unchanged from the previous year and ranged as follows:

(%)
Buildings					2		-	10
Plant and machinery					2		-	15
Industrial and commercial equipment					4		-	33
Other assets					6		-	33

A breakdown of impairments losses recorded in 2015 and the associated tax effect is provided below:

(euro million)		2014		2015

Impairment losses
Exploration & Production		695		4,341
Gas & Power		79		153
Refining & Marketing		234		154
Chemical		98
Engineering & Construction		420
Corporate and Other activities		14		20
		1,540		4,668
Tax effects
Exploration & Production		134		1,673
Gas & Power		27		38
Refining & Marketing		69		38
Chemical		33
Engineering & Construction
Corporate and Other activities		4		2
		267		1,751
Impairments net of the relevant tax effects
Exploration & Production		561		2,668
Gas & Power		52		115
Refining & Marketing		165		116
Chemical		65
Engineering & Construction		420
Corporate and Other activities		10		18
		1,273		2,917

Impairments losses disclosed in this paragraph do not include those related to the discontinued operations of euro 1,235 million (and, in addition, euro 455 million of intangible assets and euro 279 million of deferred tax assets for a total of euro 1,969 million) which were determined according to the guidelines of IFRS 5, which provides that the net assets of the disposal groups be aligned to the lower of their carrying amount and fair value. More information is provided in note 34 – Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale.

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In order to verify the recoverability of the book value of tangible and intangible assets of the continuing operations, management assesses whether there are any indications that assets may be impaired. External impairment indicators comprise evidence that the carrying amount of the net assets of Eni 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. Internal impairment indicators comprise evidence of reservoirs underperformance, increases 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 for the continuing operations the following 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 goodwill arisen from business combinations was allocated (see note 18 – Intangible assets), electricity generation plants, international pipelines and minor CGUs have been identified as being individual cash generating units; and (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. 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. For the first four years of each projection, information are extracted from the Company’s four-year plan adopted by the top management. The plan includes data points on expected oil&gas production volumes, sales volumes, capital expenditure, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates. 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 considering the expected useful lives of the Company’s CGUs and certain assumptions regarding future trends in revenues and costs. In the case of the oil&gas CGUs, management is assuming the residual life of the reserves and the associated projections of operating costs and development expenditures. The CGUs of the Refining & Marketing segment and power plants are evaluated based on the economic and technical life of the plants and the associated projections of operating costs, expenditures to support plant efficiency, refining and selling margins and clean spark spread on power sales (differential between the selling price of electricity and the cost of fuel gas). A normalization factor is considered in order to reflect the structural capacity to generate profitability of these CGUs. The CGUs of the gas market business to which amounts of goodwill have been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0% (determining negative or equal-to-zero real growth rates) applying a normalization factor of the perpetuity to reflect any cyclicality observed in the business.

In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four year industrial plans and for the assessment of the profitability of capital projects. The Company’s price scenario is approved by the Board of Directors. Under normal market conditions, the price scenario incorporates 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 fair. Longer-term, commodity prices are based on internal assumptions about trends in market fundamentals of demand and supply of crude oil and other commodities.

Considering the strong discontinuity and volatility in market conditions recorded at the end of 2015, 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. Regarding the price assumptions of the plan 2016-2019 adopted in executing the impairment review for the annual report 2015, management considered the latest trends in forward prices recorded in December 2015 and January 2016 to project short-term commodity prices. Longer-term management projected commodity prices based on the Company’s own outlook on the evolution of supply and demand fundamentals, benchmarked against price forecasts made by specialized independent sources. Considering that in the last part of 2015 and early 2016 the structural imbalances in the oil market worsened further due to the persistence of oversupply and to a slowdown in global growth affecting the energy demand, Eni’s management has revised sharply downwards its commodity prices outlook compared to the one adopted in 2014 impairment review. Particularly the long-term reference price of the Brent crude oil marker has been reduced to

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65 $/BBL (in real terms in 2019), down from the 90-dollar case utilized in the previous planning assumptions and in the evaluation of the annual report 2014 (40, 50 and 60 $/BBL in the intermediate years, respectively).

Values-in-use are estimated by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production and Refining & Marketing to the Company’s weighted average cost of capital net of the risk factors attributable to the Gas & Power segment which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC).

In 2015, 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 relevant CGUs, increased by 10 basis points compared to 2014 as a consequence of an increase in the beta of Eni and of the higher impact in the cost of equity that reflects a capital structure and a leverage target determined by discounting the exclusion of Saipem and the repayment of the intercompany financing loans. Such increase was partially offset by a reduction in the sovereign risk premium incorporated into the yields of Italian bonds with a maturity of ten years and by a marginal reduction in the cost of borrowings. The adjusted WACC rates for 2015 highlighted a certain dispersion compared to the average value of Eni amounting to 6.5%. This reflected a noticeable increase in the country risk in certain upstream areas. The adjusted WACC rates used for impairment test purposes ranged from 5.5% to 12.0% for the Exploration & Production segment and the Refining & Marketing; 5.4% for the Gas & Power segment.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

The Exploration & Production segment recognized impairment losses related to oil&gas properties for a total pre-tax amount of euro 5,139 million (a post-tax loss of euro 3,466 million) mainly driven by a reduced commodity prices outlook. Impairment losses related to plants and equipment for euro 2,573 million, proved and unproved mineral interests for euro 1,768 million and goodwill for euro 161 million. In addition, impairments were recorded at joint venture initiatives for euro 455 million and at financial receivables related to development projects of hydrocarbon reserves for euro 182 million. Considering the asset class, impairment losses were recorded at assets acquired in prior-year business combination, representing approximately 41% of the total, in particular in Algeria, Turkmenistan and Congo, and at assets in high-cost areas amounting to approximately 30% of the total, in particular in the United States, the United Kingdom, Norway and Angola. Assets with negative revisions of uneconomic reserves at current prices represented approximately 13%, which includes several not individually significant impairment losses; impairments of financial assets amounted to approximately 12% of the total; and assets in countries with high political risk amounted to approximately 3% of the total. Post-tax WACCs of impairment losses exceeding euro 100 million related to 13 CGUs and ranged from 5.5% to 6.8%, corresponding to pre-tax discount rates ranged from 8.7% and 23.9%, respectively.

The Refining & Marketing segment recognized impairment losses for euro 154 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.

The Gas & Power segment recognized impairment losses for euro 153 million related to power plants following the revision of the expected margins on the wholesale sales of electricity and steam and the infrastructure of the GreenStream gas pipeline to an increased discount rate.

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 51.7 billion, exceeded by approximately 3% Eni’s market capitalization at the same date and considering that such gap widened in the first months of 2016 following acceleration of the downward trend in oil prices. 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 and Refining & Marketing segments were assessed to have fair values in line with the carrying amounts considering the regular adoption of the impairment test by Eni, while the carrying amounts of the disposal groups Engineering & Construction and Chemical were aligned at fair value. The 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. This review showed that the recoverable amount of the Group exceeds the book value of its net assets. On this basis, management concluded that the undervaluation of Eni at the market price current at the reporting date was attributable to the strong selling pressure on stocks of the oil sector in the financial markets in the final months of 2015 and the early months of 2016, due to an accelerating downtrend in crude oil prices with the Brent crude oil

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marker below 30 $/BBL, low in thirteen years, and market participants uncertainties about a recovery in the industry fundamentals as highlighted by a context of sharp volatility in equity and commodity markets.

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 tested against a sensitivity analysis of the discount rate applied to future cash flows of oil&gas properties by reassessing the country risk premium of certain countries, which are particularly exposed to the financial risk following the collapse in crude oil prices and a local geopolitical risk factors. In particular, the oil&gas properties of Eni in Libya, Egypt, Iraq, Venezuela and Nigeria were tested with a discount rate greater than 100 bp compared to the base case, which for the single countries considered is greater than the cost of equity capital of Eni, and substantially confirmed the headroom. Finally, for some large oil&gas projects the headroom was tested by assuming hypothesis of delay in the startup or in the restart of production, such as the Kashagan project, without significant effects on the recoverability of the carrying amount of that property.

Foreign currency translation differences of euro 4,947 million primarily related to translations of entities accounts denominated in U.S. dollar (euro 5,146 million), in British pound (euro 131 million) and, as decrease, in Norwegian krone (euro 344 million).

The reclassification to discontinued operations and assets held for sale of euro 7,509 million related to tangible assets reclassified as discontinued operations for euro 7,436 million and as assets held for sale for euro 73 million.

Other changes of euro 3,074 million related to the initial recognition and change in estimates of decommissioning costs and site restoration in the Exploration & Production segment amounting to euro 807 million and the reclassification as discontinued operations of depreciations and impairment losses pertaining to the Engineering & Construction segment and the Chemical segment before their classification as discontinued operations for euro 2,225 million.

Unproved mineral interests included in tangible assets in progress and advances are presented below:

(euro million)		Book amount at the beginning of the year		Impairment losses		Reclassification to proved mineral interest		Other changes and currency translation differences		Book amount at the end of the year

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
2015
Congo		1,214		(201	)		(127	)		135			1,021
Nigeria		823								85			908
Turkmenistan		524		(411	)					52			165
Algeria		373		(386	)		(22	)		35
United States		123					(20	)		6			109
Egypt		35					(34	)		8			9
		3,092		(998	)		(203	)		321			2,212

Accumulated provisions for impairments amounted to euro 14,260 million (euro 11,684 million at December 31, 2014). Accumulated provisions for impairments for euro 3,375 million were reclassified as discontinued operations.

At December 31, 2015, Eni pledged property, plant and equipment for euro 21 million primarily as collateral against certain borrowings (same amount as of December 31, 2014).

Government grants recorded as a decrease of property, plant and equipment amounted to euro 90 million (euro 105 million at December 31, 2014).

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Assets acquired under financial lease agreements amounted to euro 26 million (euro 58 million at December 31, 2014) and related to service stations of the Refining & Marketing segment (euro 27 million at December 31, 2014). Onshore drilling rigs of the Engineering & Construction segment for euro 34 million (euro 31 million at December 31, 2014) were reclassified as discontinued operations.

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 37 – Guarantees, commitments and risks - Liquidity risk.

Property, plant and equipment under concession arrangements are described in note 37 – Guarantees, commitments and risks - Assets under concession arrangements.

Property, plant and equipment by segment

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Property, plant and equipment, gross
Exploration & Production		129,331			147,553
Gas & Power		5,985			6,169
Refining & Marketing		17,355			17,629
Chemical		6,070
Engineering & Construction		13,657
Corporate and Other activities		2,201			1,854
Elimination of intragroup profits		(572	)		(656	)
		174,027			172,549
Accumulated depreciation, amortization and impairment losses
Exploration & Production		72,677			89,945
Gas & Power		4,000			4,287
Refining & Marketing		12,895			13,288
Chemical		4,877
Engineering & Construction		6,041
Corporate and Other activities		1,749			1,436
Elimination of intragroup profits		(174	)		(202	)
		102,065			108,754
Property, plant and equipment, net
Exploration & Production		56,654			57,608
Gas & Power		1,985			1,882
Refining & Marketing		4,460			4,341
Chemical		1,193
Engineering & Construction		7,616
Corporate and Other activities		452			418
Elimination of intragroup profits		(398	)		(454	)
		71,962			63,795

17 Inventory - compulsory stock

Compulsory inventories of euro 909 million (euro 1,581 million at December 31, 2014) were net of accumulated provisions for impairments of euro 174 million (euro 453 million at December 31, 2014) and were primarily held by Italian subsidiaries for euro 893 million (euro 1,566 million at December 31, 2014) 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

Currency translation differences

Reclassification to discontinued operations and assets held for sale

Other changes

Net book amount at the end of the year

Gross book amount at the end of the year

Provisions for depreciation and impairments

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	)		36						66			2,197
		3,876		1,555		(1,789	)		(53	)		76						(20	)		3,645
2015
Intangible assets with finite useful lives
Exploration expenditures		307		834		(959	)					28						(21	)		189		3,192		3,003
Industrial patents and intellectual property rights		285		26		(74	)					1			(31	)		69			276		1,353		1,077
Concessions, licenses, trademarks and similar items		479		8		(116	)					(1	)		(4	)		(5	)		361		2,413		2,052
Service concession arrangements		32				(2	)											2			32		51		19
Intangible assets in progress and advances		179		54											(7	)		(91	)		135		135
Other intangible assets		166		15		(30	)					2			(1	)		(26	)		126		2,214		2,088
		1,448		937		(1,181	)					30			(43	)		(72	)		1,119		9,358		8,239
Intangible assets with indefinite useful lives
Goodwill		2,197							(161	)		34			(363	)		(393	)		1,314
		3,645		937		(1,181	)		(161	)		64			(406	)		(465	)		2,433

Exploration expenditures of euro 189 million (euro 307 million at December 31, 2014) mainly related to the residual book value of license acquisition costs, amortized on a straight-line basis over the contractual term of the exploration lease. Additions of the year of euro 834 million (euro 1,422 million in 2014) included exploration drilling expenditures which are fully capitalized to reflect their investment nature and then entirely amortized for euro 826 million (euro 1,354 million in 2014) and license acquisition costs of euro 8 million (euro 68 million in 2014) primarily related to the acquisition of new exploration acreage in the United Kingdom and Ivory Coast. Amortizations of euro 959 million (euro 1,564 million in 2014) included amortizations of license acquisition costs for euro 143 million (euro 260 million in 2014).

Industrial patents and intellectual property rights of euro 276 million (euro 285 million at December 31, 2014) related to Eni SpA for euro 250 million (euro 236 million at December 31, 2014) 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 361 million (euro 479 million at December 31, 2014) primarily comprised transmission rights for natural gas imported from Algeria of euro 323 million (euro 423 million at December 31, 2014) and concessions for mineral exploration of euro 15 million (euro 18 million at December 31, 2014).

Service concession arrangements of euro 32 million primarily pertained to gas distribution activities outside Italy (same amount as of December 31, 2014).

Intangible assets in progress and advances of euro 135 million (euro 179 million at December 31, 2014) related to Eni SpA for euro 49 million (euro 79 million at December 31, 2014) and primarily concerned cost for software development.

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Other intangible assets with finite useful lives of euro 126 million (euro 166 million at December 31, 2014) comprised: 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 49 million (euro 31 million at December 31, 2014) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna.

The reclassification to discontinued operations and assets held for sale of euro 406 million relates for euro 395 million to intangible assets reclassified as discontinued operations and for euro 11 million to assets held for sale.

Other changes of euro 465 million related to the reclassification as discontinued operations of depreciations and impairment losses pertaining to the Engineering & Construction segment and Chemical segment before their classification as discontinued operations for euro 467 million.

The main amortization 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 161 million (euro 51 million in 2014) and related to the Exploration & Production segment as consequence of the impact of a reduced commodity prices outlook (see note 16 – Property, plant and equipment). Impairment losses were incurred at goodwill recognized in connection with the acquisition of Burren Energy in Congo (2008) assessed by using an adjusted post-tax WACC rate amounting to 6.8%, corresponding to a pre-tax discount rate of 16.9% and the acquisition of First Calgary in Algeria (2008) assessed by using an adjusted post-tax WACC rate amounting to 6.7%, corresponding to a pre-tax discount rate of 8.7%.

The carrying amount of goodwill at the end of the year was euro 1,314 million (euro 2,197 million at December 31, 2014) net of cumulative impairments charges amounting to euro 2,525 million (euro 2,353 million at December 31, 2014); the decrease related to a reclassification to assets held for sale.

A breakdown of the stated goodwill by operating segment is provided below:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Gas & Power		1,025		1,025
Engineering & Construction		747
Exploration & Production		323		196
Refining & Marketing		102		93
		2,197		1,314

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 and estimating the terminal value of the CGUS by applying the perpetuity method. For the determination of the cash flows see note 16 – Property, plant and equipment.

The amount of goodwill outstanding at the reporting date mainly related to the Gas & Power segment. A break-down is disclosed below.

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Gas & Power segment

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Domestic gas market		835		835
Foreign gas market		190		190
- of which European market		188		188
		1,025		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 acquired entity 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 any allocated goodwill.

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, and Nuon Belgium NV (now merged in Eni Gas & Power NV) in Belgium, which represent two stand-alone CGUs. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of both CGUs including any allocated goodwill.

In assessing the recoverability of the carrying amount of the Gas & Power CGUs including the allocated portion of goodwill, management determined the value in use of those CGUs. The assessment was performed considering the cash flows of the four-year plan approved by management and incorporating the perpetuity of the last year of the plan to determine the terminal value by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of 5.2% for Italy and 5.8% for Europe. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

The excess of the recoverable amount of the CGU Domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to euro 1,467 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 57% on average in the projected commercial margins; (ii) an increase of 8.2 percentage points in the discount rate; and (iii) a negative nominal growth rate of 14%.

In the Exploration & Production segment goodwill amounted to euro 196 million at the balance sheet date, following the impairments performed in 2015 as consequence of the impact of a reduced commodity prices outlook and related to the business combination Lasmo and Liverpool Bay.

In the Refining & Marketing segment goodwill amounted to euro 93 million at the balance sheet date. Goodwill amounting to euro 76 million pertained to retail networks acquired in previous years in Austria for which profitability expectations have remained unchanged from the previous-year impairment review.

 

 

 

 

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19 Investments

Equity-accounted investments

(euro million)

Book amount at the beginning of the year

Additions and subscriptions

Divestments and reimbursements

Share of profit of equity-accounted investments

Share of loss of equity-accounted investments

Deduction for dividends

Changes in the scope of consolidation

Currency translation differences

Other changes

Book amount at the end of the year

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
2015
Investments in unconsolidated entities controlled by Eni		196		8					66		(17	)		(92	)		15		17		(22	)		171
Joint ventures		1,215		93		(8	)		56		(37	)		(28	)				69		(211	)		1,149
Associates		1,704		124					24		(537	)		(22	)				167		(161	)		1,299
		3,115		225		(8	)		146		(591	)		(142	)		15		253		(394	)		2,619

In 2015, additions of euro 225 million mainly related essentially to capital contributions to joint ventures and associates engaged in the realization of projects in the interest of Eni: (i) Angola LNG Ltd (euro 123 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%); and (ii) PetroJunín SA (euro 40 million) which is developing gas and crude oil fields in Venezuela.

Eni’s share of profit of equity-accounted investments and dividend decrease pertained to the following entities:

		Dec. 31, 2014		Dec. 31, 2015

(euro million)

Share of profit of equity-accounted investments

Deduction for dividends

Eni’s interest (%)

Share of profit of equity-accounted investments

Deduction for dividends

Eni’s interest (%)

Eni BTC Ltd		22		17		100.00		59		90		100.00
PetroJunín SA		3				40.00		29				40.00
United Gas Derivatives Co		32		36		33.33		20		21		33.33
Eteria Parohis Aeriou Thessalonikis AE		9		10		49.00		11		8		49.00
Unión Fenosa Gas SA		42		23		50.00				13		50.00
CARDÓN IV SA		28				50.00
Unimar Llc		19		46		50.00
Petromar Lda		14				70.00
PetroSucre SA		6		29		26.00
Other investments		40		34				27		10
		215		195				146		142

 

 

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Eni’s share of losses of equity-accounted investments related to the following entities:

		Dec. 31, 2014		Dec. 31, 2015

(euro million)		Share of loss of equity-accounted investments		Eni’s interest (%)		Share of loss of equity-accounted investments		Eni’s interest (%)

Angola LNG Ltd		34		13.60		469		13.60
PetroSucre SA						66		26.00
Unión Fenosa Gas SA						25		50.00
Unimar Llc						7		50.00
CARDÓN IV SA						3		50.00
Westgasinvest Llc		6		50.01		2		50.01
South Stream Transport BV		20
Other investments		26				19
		86				591

Losses at the equity-accounted investment of Angola LNG Ltd of euro 469 million (euro 34 million in 2014) related mainly to impairment charges relating to the liquefaction plant which is being commissioned by this entity due to a reduced commodity prices outlook (euro 433 million) and to pre-production expenses and operating costs associated with the start-up of the liquefaction plant.

Currency translation differences of euro 253 million were primarily related to translation of entities accounts denominated in U.S. dollar (euro 222 million).

Other changes of euro 394 million comprised the reclassification as discontinued operations for euro 322 million.

List of equity-accounted investments:

	Dec. 31, 2014		Dec. 31, 2015

(euro million)	Net carrying amount		Number of shares held		Eni’s interest (%)		Net carrying amount		Number of shares held		Eni’s interest (%)

Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd		115		34,000,000		100.00		96		34,000,000		100.00
Other investments (*)		81						75
		196						171
Joint ventures
Unión Fenosa Gas SA		577		273,100		50.00		503		273,100		50.00
PetroJunín SA		93		44,424,000		40.00		174		44,424,000		40.00
CARDÓN IV SA		146		8,605		50.00		160		8,605		50.00
Eteria Parohis Aeriou Thessalonikis AE		111		99,396,500		49.00		109		94,839,500		49.00
Unimar Llc		58		50		50.00		57		50		50.00
Eteria Parohis Aeriou Thessalias AE		44		38,445,008		49.00		43		35,652,008		49.00
PetroBicentenario SA		4		40,000		40.00		27		40,000		40.00
Petromar Lda		42		1		70.00
Lotte Versalis Elastomers Co Ltd		31		8,720,000		50.00
Other investments (*)		109						76
		1,215						1,149
Associates
Angola LNG Ltd		1,226		1,471,803,666		13.60		1,015		1,591,200,000		13.60
PetroSucre SA		171		5,727,800		26.00		123		5,727,800		26.00
United Gas Derivatives Co		102		950,000		33.33		113		950,000		33.33
Novamont SpA		77		6,667		25.00
Rosetti Marino SpA		31		800,000		20.00
Other investments (*)		97						48
		1,704						1,299
		3,115						2,619

(*)		Each individual amount included herein was lower than euro 25 million.

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Equity-accounted investments are disclosed in note 44 – Information by industry segment and by geographical area.

Carrying amounts of equity-accounted investments included differences between the purchase price of the interest acquired and the book value of the corresponding fraction of net equity amounting to euro 146 million related to Unión Fenosa Gas SA.

The table below sets out the provisions for losses included in the provisions for contingencies of euro 137 million (euro 158 million at December 31, 2014), primarily related to the following equity-accounted investments:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		90		93
VIC CBM Ltd		25		29
Société Centrale Eletrique du Congo SA		9		8
Other investments		34		7
		158		137

Additional information is included in note 46 – Other information about investments.

 

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

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
2015
Investments in unconsolidated entities controlled by Eni		14		3										8			25		26		1
Associates		12										1		(3	)		10		10
Other investments:
- valued at fair value		1,744				(1,425	)		49								368		368
- valued at cost		245				(10	)					21		(15	)		241		244		3
		2,015		3		(1,435	)		49			22		(10	)		644		648		4

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 the investments valued at fair value of euro 1,425 million are stated net of gains on disposals (euro 144 million) and related to the sale of an interest of 8% in Galp Energia SGPS SA (entire stake own) for euro 560 million and the sale of an interest of 6.03% in Snam SpA for euro 865 million following the holders’ exercise of their exchange right in relation to the convertible bond.

The divestment of Galp Energia SGPS SA was carried out through placements with institutional investors and spot sales in two different tranches. In the first half 2015, 33,212,922 ordinary shares, corresponding to approximately 4.01% of the share capital were disposed of for a total consideration of euro 333 million, at a price of euro 10.9 per share and a gain of euro 52 million recognized in the profit and loss account. On November 24, 2015, a residual interest of 3.99% of the share capital (33,124,670 ordinary shares) were divested through an accelerated book-building procedure aimed at qualified institutional investors for a total consideration of euro 325 million, at a price of euro 9.81 per share and a gain on realization at fair value of euro 46 million recognized in the profit and loss account.

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The divestment of Snam SpA related to 211,002,719 ordinary shares, corresponding to approximately 6.03% of the share capital, following the bondholders’ exercise of their option in relation to the convertible bond, issued on January 18, 2013 due on January 18, 2016. The consideration was euro 911 million, at a conversion price of euro 4.32 per share and a gain on realization at fair value of euro 46 million recognized thorough profit. At December 31, 2015, Eni holds a residual stake in Snam of 77,680,883 corresponding to 2.22% of the share capital, of which 62,789,570 shares not yet exchanged, recorded at a price of euro 4.83 per share corresponding to euro 303 million and 14,891,313 shares subject to exchange, but not yet settled, recorded at a price of euro 4.32 per share corresponding to euro 65 million. In the month of January 2016 almost all bondholders exercised their option.

Valuation at fair value of euro 49 million related to the interests in Snam SpA. The fair value valuation was reported through profit and loss in application of the fair value option provided by IAS 39 as relating to shares of Snam SpA underlying the convertible bond. The fair value option was applied in order to eliminate an accounting mismatch which arises 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 33 million reflecting, in particular, progression to maturity.

The market value of Snam SpA is determined on the basis of quoted market prices. The fair value hierarchy is level 1.

The net carrying amount of other investments of euro 644 million (euro 2,015 million at December 31, 2014) was related to the following entities:

	Dec. 31, 2014		Dec. 31, 2015

(euro million)	Net carrying amount		Number of shares held		Eni’s interest (%)		Net carrying amount		Number of shares held		Eni’s interest (%)

Investments in unconsolidated entities controlled by Eni (*)		14						25
Associates		12						10
Other investments:
- Snam SpA		1,184		288,683,602		8.25		368		77,680,883		2.22
- Nigeria LNG Ltd		97		118,373		10.40		109		118,373		10.40
- Darwin LNG Pty Ltd		60		213,995,164		10.99		60		213,995,164		10.99
- Galp Energia SGPS SA		560		66,337,592		8.00
- other (*)		88						72
		1,989						609
		2,015						644

(*)		Each individual amount included herein was lower than euro 25 million.

Additional information is included in note 46 – Other information about investments.

20 Other financial assets

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Receivables held for operating purposes		946		711
Securities held for operating purposes		76		77
		1,022		788

Financing receivables held for operating purposes are stated net of the valuation allowance for doubtful accounts of euro 385 million (euro 134 million at December 31, 2014).

(euro million)		Amount at Dec. 31, 2014		Additions		Currency translation differences		Other changes		Amount at Dec. 31, 2015

Reserve of allowance for doubtful accounts of financing receivables

134

240

15

(4)

385

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Financing receivables held for operating purposes of euro 711 million (euro 946 million at December 31, 2014) primarily pertained to loans granted by the Exploration & Production segment (euro 458 million), the Gas & Power segment (euro 152 million) and Refining & Marketing segment (euro 2 million). Financing receivables granted to joint ventures and associates amounted to euro 158 million (euro 218 million at December 31, 2014).

Allowances for doubtful accounts of financing receivables of euro 240 million included an impairment for euro 182 million of financing receivables granted by the Exploration & Production segment related to the realization of a project in Nigeria as a consequence of the revision of the commodity price scenario.

Financing receivables held for operating purposes for euro 70 million were reclassified as discontinued operations.

Financing receivables held for operating purposes in currencies other than euro amounted to euro 611 million (euro 791 million at December 31, 2014).

Financing receivables held for operating purposes due beyond five years amounted to euro 416 million (euro 516 million at December 31, 2014).

The valuation at fair value of financing receivables of euro 734 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from 0% to 2.7% (0.2% and 2.7% at December 31, 2014).

Securities of euro 77 million (euro 76 million at December 31, 2014), designated as held-to-maturity investments, are listed bonds issued by sovereign states for euro 70 million (euro 69 million at December 31, 2014) and by the European Investment Bank for euro 7 million (same amount as of December 31, 2014). Securities amounting to euro 23 million (euro 20 million at December 31, 2014) 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		23		23		25		from 0.75 to 5.75		from 2016 to 2025		Baa2		BBB-
Spain		15		14		15		from 1.40 to 4.30		from 2019 to 2020		Baa2		BBB+
Ireland		9		8		9		from 4.40 to 4.50		from 2018 to 2019		Baa1		A+
Poland		3		2		3		4.20		2020		A2		A-
Slovenia		2		2		2		4.13		2020		Baa3		A-
Belgium		2		2		2		1.25		2018		Aa3		AA
Floating rate bonds
Belgium		7		7		7				2016		Aa3		AA
Italy		6		6		6				2016		Baa2		BBB-
Mozambique		3		3		3				from 2017 to 2019		B2		B-
Total sovereign states		70		67		72
Floating rate bonds
European Investment Bank		7		8		8				from 2016 to 2018		Aaa		AAA
		77		75		80

Securities with a maturity beyond five years amounted to euro 1 million (euro 4 million at December 31, 2014).

The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in note 45 – Transactions with related parties.

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21 Deferred tax assets

Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for euro 3,113 million (euro 3,915 million at December 31, 2014).

(euro million)	Amount at Dec. 31, 2014		Additions		Deductions		Currency translation differences		Other changes		Amount at Dec. 31, 2015

Deferred tax assets		8,531			1,827			(1,436	)		544			(610	)		8,856
Provision for impairments		(3,300	)		(1,420	)		4			(49	)		258			(4,507	)
		5,231			407			(1,432	)		495			(352	)		4,349

Deferred tax assets related for euro 1,980 million (euro 2,929 million at December 31, 2014) to the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes. Those assets were recorded on the pre-tax loss of the year and on the recognition of deferred deductible costs within the limits of the amounts expected to be recovered in future years based on availability of expected future taxable profit.

The decrease of euro 1,436 million in deferred tax assets mainly comprised the amount relating to the reduction in the statutory tax rate of the Italian subsidiaries from 27.5% to 24%²³ (euro 523 million).

Additions in provision for impairments of euro 1,420 million comprised a write-off of deferred tax assets incurred at non-Italian subsidiaries pertaining to the Exploration & Production segment due to a reduced profitability outlook on the back of a deteriorated commodity price environment (euro 1,058 million) and of Italian deferred tax assets due to projections of lower future taxable profit at Italian subsidiaries (euro 362 million).

Other changes of euro 352 million included deferred tax assets for euro 641 million were reclassified as discontinued operations.

Deferred tax assets are further described in note 31 – Deferred tax liabilities.

Income taxes are described in note 42 – Income taxes.

22 Other non-current assets

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Tax receivables from:
- Italian Tax Authorities
. income tax		864		44
. interest on tax credits		94		63
		958		107
- non-Italian Tax Authorities		265		287
		1,223		394
Other receivables:
- related to divestments		636		567
- other non-current		153		45
		789		612
Fair value of derivative financial instruments		196		218
Other asset		565		533
		2,773		1,757

The decrease in tax receivables from Italian Fiscal Authorities of euro 820 million related to Eni SpA for euro 854 million and primarily referred to reimbursements of tax receivables and associated interest from the Tax Administration and disposal of tax receivables to financing institutions, including interests, without recourse. In particular: (i) euro 510 million was reimbursed following settlement with the Italian Tax Authorities of the method

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for calculating an Italian corporate profit surcharge of 4% established by Law No. 7/2009 (the so-called Libyan Tax); (ii) euro 93 million were reimbursed due to enactment of Decree Law No. 201/2011. This provision enabled the full deductibility from the pre-tax profit subject to the Italian statutory tax rate (including a surcharge marginal tax rate on profits of the oil companies, the so-called Robin Tax) of an Italian tax on gross margin, relating to the portion determined on personnel expenses, with retroactive effects from 2012.

Receivables from divestments amounted to euro 567 million (euro 636 million at December 31, 2014). A receivable of euro 463 million (euro 401 million at December 31, 2014) related to the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunayGas on the basis of the agreements defined between the international partners of the North Caspian Sea PSA and the Kazakh government, which enacted a new contractual framework and a new setup for managing project operation. The reimbursement of the receivable is scheduled in three annual installments commencing the date when the agreed production target of the Experimental Program is achieved. The receivable accrues interest income at market rates. A residual amount of euro 25 million is outstanding (euro 123 million at December 31, 2014) following compensation agreed with the Republic of Venezuela for the expropriated Dación oil field in 2006. The receivable which is being repaid in annual installments accrues interests at market rates. In 2015, reimbursements amounted to euro 111 million (US$123 million) of which US$88 million related to the residual principal amount and US$35 million to interests accrued.

The fair value related to derivative financial instruments is disclosed in note 33 – Derivative financial instruments.

Other non-current assets amounted to euro 533 million (euro 565 million at December 31, 2014), of which euro 277 million (euro 395 million at December 31, 2014) were deferred costs of take-or-pay gas volumes in connection with the Company’s long-term supply contracts. The amount was recognized due to the obligation to pay 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. The Company is entitled to off-take the prepaid volumes in future years alongside contract execution, up to contract expiration or in a shorter term as the case may be. Those deferred costs, which are equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-year impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. In 2015, based on this accounting principle a revaluation of euro 7 million was recorded. The reduction in the amount of the deferred costs at the reporting date compared to 2014 was due to the off-take of prepaid gas volumes (euro 117 million) and, to a lesser extent, to the reclassification to other current assets of volumes that are expected to be recovered by 2016 (euro 8 million). A portion of the deferred costs was classified as non-current assets, because the Company plans to lift the prepaid quantities beyond the term of 12 months. In spite of weak market conditions in the European gas sector due to sluggish demand growth and strong competitive pressures fuelled by oversupplies, management plans to recover volumes underlying the deferred cost within the plan horizon. Management plans to achieve this by leveraging on an improved competitiveness of the Company in the gas market thanks to the benefit of contract renegotiations, an expected reduction in the Company’s annual minimum obligations, and other actions of commercial optimizations which will leverage the Company’s simultaneous presence in several markets and asset availability (logistics capacity, transportation rights). Other non-current assets for euro 86 million were reclassified as discontinued operations.

Transactions with related parties are described in note 45 – Transactions with related parties.

Current liabilities

23 Short-term debt

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Commercial papers		1,926		4,962
Banks		435		142
Other financial institutions		355		608
		2,716		5,712

The increase in short-term debt of euro 2,996 million includes net debt issuance for euro 3,216 million.

Finance debts for euro 243 million were reclassified as discontinued operations.

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Commercial papers of euro 4,962 million (euro 1,926 million at December 31, 2014) were issued by the Group’s financial subsidiaries Eni Finance International SA (euro 2,773 million) and Eni Finance USA Inc (euro 2,189 million).

The breakdown by currency of short-term debt is provided below:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Euro		453		3,048
U.S. dollar		1,987		2,616
Other currencies		276		48
		2,716		5,712

As of December 31, 2015, the weighted average interest rate on short-term debt was 0.6% (1.5% as of December 31, 2014).

As of December 31, 2015, Eni had undrawn committed and uncommitted borrowing facilities amounting to euro 40 million and euro 12,708 million, respectively (euro 41 million and euro 12,657 million at December 31, 2014, respectively). Those facilities bore interests and charges for undrawn that reflect prevailing market conditions.

As of December 31, 2015, Eni did not report any default on covenants or other contractual provisions in relation to borrowing facilities.

Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.

Payables due to related parties are described in note 45 – Transactions with related parties.

24 Trade and other payables

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Trade payables		15,015		9,345
Down payments and advances		2,278		637
Other payables:
- related to capital expenditures		2,693		1,876
- others		3,717		2,757
		6,410		4,633
		23,703		14,615

The decrease in trade payables amounting to euro 5,670 million primarily related to the Gas & Power segment (euro 2,335 million).

Trade payables for euro 2,845 million were reclassified as discontinued operations.

Down payments and advances for euro 637 million (euro 2,278 million at December 31, 2014) related to contract work-in-progress of the Gas & Power segment for euro 311 million (euro 55 million at December 31, 2014) and the Refining & Marketing segment for euro 253 million (euro 222 million at December 31, 2014). Down payments and advances²⁴ related to contract work-in-progress of the Engineering & Construction segment for euro 1,371 million and euro 639 million, respectively (euro 1,314 million and euro 620 million at December 31, 2014, respectively) were reclassified as discontinued operations.

 

 

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Other payables were as follows:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Payables related to capital expenditures due to
Suppliers in relation to investing activities		2,301		1,536
Joint venture operators in exploration and production activities		252		283
Other		140		57
		2,693		1,876
Other payables
Joint venture operators in exploration and production activities		2,117		1,750
Employees		485		170
Social security entities		182		85
Non-financial government entities		238		4
Other		695		748
		3,717		2,757
		6,410		4,633

Because of the short-term maturity and conditions of remuneration of trade payables, the fair value approximated the carrying amount.

Payables due to related parties are described in note 45 – Transactions with related parties.

25 Income taxes payable

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Italian subsidiaries		73		65
Subsidiaries outside Italy		461		357
		534		422

Income tax payables for euro 140 million were reclassified as discontinued operations.

Income tax expenses are described in note 42 – Income taxes.

26 Other taxes payable

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Excise and customs duties		971		716
Other taxes and duties		902		726
		1,873		1,442

Other taxes payable for euro 280 million were reclassified as discontinued operations.

27 Other current liabilities

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Fair value of other derivatives financial instruments		4,111		4,261
Other liabilities		378		442
		4,489		4,703

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Fair value related to derivative financial instruments is disclosed in note 33 – Derivative financial instruments.

Other current liabilities of euro 442 million (euro 378 million at December 31, 2014) included the current portion of advances recovered from gas customers who off-took lower volumes than the contractual minimum take provided by the relevant long-term supply contract for euro 11 million (euro 31 million at December 31, 2014) and the current portion of advances received from Suez following a long-term agreement for supplying natural gas and electricity for euro 76 million (euro 78 million at December 31, 2014). Non-current portion is disclosed in note 32 – Other non-current liabilities.

Transactions with related parties are described in note 45 – Transactions with related parties.

Non-current liabilities

28 Long-term debt and current portion of long-term debt

(euro million)		Maturity range		2014		2015		Current maturity 2016		2017		2018		2019		2020		After		Total

Banks		2016-2032		2,772		3,920		455		285		785		1,231		183		981		3,465
Ordinary bonds		2016-2043		17,924		17,608		1,837		2,665		1,203		2,534		2,406		6,963		15,771
Convertible bonds		2016		2,263		339		339
Other financial institutions		2016-2028		216		197		40		44		45		49		3		16		157
				23,175		22,064		2,671		2,994		2,033		3,814		2,592		7,960		19,393

Long-term debt and current portion of long-term debt of euro 22,064 million (euro 23,175 million at December 31, 2014) decreased by euro 1,111 million. The decrease of euro 1,111 million comprised new issuance of euro 3,376 million net of repayments made for euro 4,466 million and currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for euro 253 million.

Financial debt for euro 292 million were reclassified as discontinued operations.

Debt due to other financial institutions of euro 197 million (euro 216 million at December 31, 2014) included euro 26 million of finance lease transactions (euro 28 million at December 31, 2014).

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, 2015, debts subjected to restrictive covenants amounted to euro 2,127 million (euro 2,314 million at December 31, 2014). Eni believes that any non-compliance with those covenants in the future can be managed through contractual agreements and the Company’s ability to finance its operations will not be affected.

Ordinary bonds of euro 17,608 million (euro 17,924 million at December 31, 2014) consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 15,174 million and other bonds for a total of euro 2,434 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, 2015:

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		69			1,569		EUR				2016				5.000
- Eni SpA		1,500		14			1,514		EUR				2019				4.125
- Eni SpA		1,250		4			1,254		EUR				2017				4.750
- Eni SpA		1,200		17			1,217		EUR				2025				3.750
- Eni SpA		1,000		35			1,035		EUR				2020				4.250
- Eni SpA		1,000		30			1,030		EUR				2018				3.500
- Eni SpA		1,000		26			1,026		EUR				2029				3.625
- Eni SpA		1,000		19			1,019		EUR				2020				4.000
- Eni SpA		1,000		5			1,005		EUR				2023				3.250
- Eni SpA		1,000		5			1,005		EUR				2026				1.500
- Eni SpA		800		1			801		EUR				2021				2.625
- Eni SpA		750		12			762		EUR				2019				3.750
- Eni SpA		750		(3	)		747		EUR				2024				1.750
- Eni Finance International SA		613		16			629		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		160		1			161		YEN		2019		2037		1.955		2.810
		14,918		256			15,174
Other bonds:
- Eni SpA		1,109		6			1,115		EUR				2017				4.875
- Eni SpA		413		3			416		USD				2020				4.150
- Eni SpA		322					322		USD				2040				5.700
- Eni SpA		215					215		EUR				2017				variable
- Eni USA Inc		368		(2	)		366		USD				2027				7.300
		2,427		7			2,434
		17,345		263			17,608

As of December 31, 2015, ordinary bonds maturing within 18 months of euro 1,569 million were issued by Eni SpA. During 2015, new bonds for euro 1,752 million were issued by Eni SpA.

Following the exercise of the conversion right by bondholders of the 6.03% share capital of Snam (211,002,719 ordinary shares), at the balance sheet date the residual convertible bond amounted to euro 339 million corresponding to 77,680,883 underlying shares of Snam (2.22% of the share capital). The exercise of the conversion rights was almost completed in January 2016.

(euro million)	Amount		Discount on bond issue and accrued expense		Total		Currency		Maturity		Rate %

Issuing entity
Eni SpA		339		339		EUR		2016		0.625
		339		339

Convertible bond is 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.

Convertible bond outstanding at previous reporting date issued in 2012 for a nominal value of euro 1,028 million with 66 million ordinary shares of Galp underlying the bond, corresponding to 8% of share capital was fully repaid in two tranches during the year. The first tranche of repayment related to approximately 50% of the bond and was performed through a competitive bidding process, whereby Eni repurchased bonds from bondholders for a total nominal amount of euro 514.9 million in cash. The purchase price was set at euro 100,400 for each euro 100,000 nominal value of bonds, including accrued interest. In November 2015, the remaining bond with nominal value of euro 513 million was redeemed at maturity. The funds to repay down the bond were obtained through the sale of a residual interest in Galp corresponding to 33 million ordinary shares, equal to approximately 4% of Galp’s share capital through an accelerated bookbuilding procedure with qualified institutional investors for total consideration of approximately euro 325 million at the price of euro 9.81 per share.

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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, 2014 (euro million)		Average rate (%)		Dec. 31, 2015 (euro million)		Average rate (%)

Euro		20,625		3.2		19,614		3.2
U.S. dollar		1,744		5.4		1,660		5.0
British pound		592		5.3		629		5.3
Japanese yen		214		2.3		161		2.6
		23,175				22,064

As of December 31, 2015, Eni had undrawn long-term committed borrowing facilities of euro 6,576 million of which euro 1,000 million due in 2016 (euro 6,598 million at December 31, 2014). 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 20 billion, of which euro 14.9 billion were drawn as of December 31, 2015.

The Group has credit ratings of BBB+ outlook stable and A-2, respectively for long and short-term debt, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked to the Company’s industrial fundamentals and trends in the trading environment and, in addition, to the sovereign credit rating of Italy. 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.

Fair value of long-term debt, including the current portion of long-term debt amounted to euro 23,890 million (euro 25,364 million at December 31, 2014):

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Ordinary bonds		19,910		18,984
Convertible bonds		2,344		341
Banks		2,864		4,356
Other financial institutions		246		209
		25,364		23,890

Fair value of financial debt was calculated by discounting the expected future cash flows at discount rates ranging from 0% to 2.7% (0.2% and 2.7% at December 31, 2014).

At December 31, 2015, Eni did not pledge restricted deposits as collateral against its borrowings.

Information on net borrowings
In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS as endorsed by IASB less: cash, cash equivalents, held-for-trading securities and other financial assets, and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and available-for-sale securities not related to operations. Held-for-trading securities and other financial assets are part of a strategic reserve of liquidity that management has established by reinvesting proceeds from the Group disposal plans and is intended to provide a certain degree of financial flexibility in case of a prolonged price downturn, tight financial markets or in view of other Company’s purposes. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Available-for-sale securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and

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medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

		Dec. 31, 2014		Dec. 31, 2015

(euro million)

Current

Non-current

Total

Current

Non-current

Total

A.	Cash and cash equivalents		6,614					6,614		5,200					5,200
B.	Held-for-trading financial assets		5,024					5,024		5,028					5,028
C.	Available-for-sale financial assets		13					13
D.	Liquidity (A+B+C)		11,651					11,651		10,228					10,228
E.	Financing receivables		555					555		685					685
F.	Short-term debt towards banks		435					435		142					142
G.	Long-term debt towards banks		236			2,536		2,772		455			3,465		3,920
H.	Bonds		3,589			16,598		20,187		2,176			15,771		17,947
I.	Short-term debt towards related parties		181					181		208					208
L.	Other short-term liabilities		2,100					2,100		5,362					5,362
M.	Other long-term liabilities		34			182		216		40			157		197
N.	Total borrowings (F+G+H+I+L+M)		6,575			19,316		25,891		8,383			19,393		27,776
O.	Net borrowings (N-D-E)		(5,631	)		19,316		13,685		(2,530	)		19,393		16,863

Financial assets held for trading of euro 5,028 million (euro 5,024 million at December 31, 2014) were part of the Group liquidity reserve and pooled treasury activities managed by the parent company by Eni SpA. For further information see note 9 – Financial assets held for trading.

Available-for-sale financial assets of euro 13 million as of December 31, 2014, were held for non-operating purposes. The Company held at the reporting date held-to-maturity and available-for-sale securities which were destined to operating purposes amounting to euro 359 million (euro 320 million at December 31, 2014), of which euro 282 million (euro 244 million at December 31, 2014) were held to hedge the loss reserve of Eni Insurance Ltd. Those securities are excluded from the calculation above.

Current financing receivables of euro 685 million (euro 555 million at December 31, 2014) were held for non operating purposes. The Company held at the reporting date financing receivables which were destined to operating purposes amounting to euro 1,613 million (euro 1,262 million at December 31, 2014), of which euro 1,126 million (euro 764 million at December 31, 2014) were in respect of financing granted to joint ventures and affiliates which executed capital projects and investments on behalf of Eni’s Group companies and a euro 287 million cash deposit (euro 332 million at December 31, 2014) 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, 2014

New or increased provisions

Initial recognition and changes in estimates

Accretion discount

Reversal of utilized provisions

Reversal of unutilized provisions

Currency translation differences

Reclassification to discontinued operations and asset held for sale

Other changes

Carrying amount at Dec. 31, 2015

Provision for site restoration, abandonment and social projects		9,465				(771	)		293			(307	)					497					(179	)		8,998
Environmental provision		2,811		231					(7	)		(291	)		(14	)				(36	)		8			2,702
Provision for legal and other proceedings		1,335		906								(498	)		(70	)		88		(23	)		(19	)		1,719
Provision for taxes		488		246					(1	)		(108	)		(4	)		49		(56	)		(131	)		483
Loss adjustments and actuarial provisions for Eni’s insurance companies		368		151								(204	)							(10	)		18			323
Provision for onerous contracts		327		24					2			(104	)					24								273
Provision for green certificates		226		2								(38	)		(1	)				(1	)		1			189
Provision for redundancy incentives		235							1			(6	)		(25	)				(15	)		(4	)		186
Provision for losses on investments		167		8											(12	)		4		(8	)		(20	)		139
Provision for OIL insurance cover		77													(6	)		1		(2	)					70
Provision for disposal and restructuring		93										(4	)					3		(50	)		(12	)		30
Provision for long-term construction contracts		101																3		(126	)		22
Other (*)		205		84					3			(97	)		(23	)		6		(33	)		9			154
		15,898		1,652		(771	)		291			(1,657	)		(155	)		675		(360	)		(307	)		15,266

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

The Group makes full provision for the future costs of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The decommissioning provisions at the reporting date amounted to euro 8,998 million and included future costs for social projects. 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 of the Exploration & Production segment for euro 8,521 million. Negative estimates’ revisions of euro 771 million were primarily due to a rise in the discount rate curve in particular for the U.S. dollar and, secondly, to revision of previous estimates of decommissioning costs, and new provisions of the year. The accretion discount recognized in the profit and loss account for euro 293 million was determined by adopting discount rates ranging from 0.2% to 4.6% (from 0.3% to 4.4% at December 31, 2014). Main expenditures associated with decommissioning operations are expected to be incurred over a 40-year period.

Provisions for environmental risks of euro 2,702 million included the estimated costs for environmental remediation and restoration of soil and groundwater in areas owned or under concession where the Group conducted in the past industrial operations which were progressively divested, shut down, dismantled or restructured. The provision has been accrued because at balance sheet date there is a legal or constructive obligation for Eni to carry out cleaning-up operations and the expected costs can be estimated reliably. The provision includes the expected charges associated with strict liability related to obligations of restoring the contaminated sites that met the parameters set by the law at the time when the pollution occurred or because Eni assumed the liability of third operators when took over the ownership of the site. 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, 2015, environmental provision primarily related to Syndial SpA for euro 2,214 million and the Refining & Marketing segment for euro 388 million. Additions of euro 231 million primarily related to the Refining & Marketing segment for euro 110 million and Syndial SpA for euro 91 million. Utilizations of euro 291 million primarily related to Syndial SpA for euro 159 million and the Refining & Marketing segment for euro 105 million.

Provisions for legal and other proceedings of euro 1,719 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

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litigation and commercial proceedings and primarily related to the Gas & Power segment for euro 1,278 million and the Exploration & Production segment for euro 278 million. Additions and utilizations of euro 906 million and euro 498 million, respectively, mainly related to the Gas & Power segment and were recognized to take account of gas price revisions at long term supply contracts, including the settlement of certain arbitrations. Reversals of unutilized provision of euro 70 million were primarily made by the Gas & Power segment.

Provisions for taxes of euro 483 million included the estimated charges that the Company expects to incur for unsettled tax claims in connection with uncertainties in the application of tax rules at certain Italian and foreign subsidiaries in the Exploration & Production segment (euro 458 million).

Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance Ltd of euro 323 million represented the estimated liabilities accrued on the basis for third parties claims. Against such liability was recorded a receivable of euro 113 million recognized towards insurance companies for reinsurance contracts.

Provisions for onerous contracts of euro 273 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 regasification project and on an unutilized infrastructure for gas transportation.

Provisions for green certificates of euro 189 million included additional charges that electric power producers must sustain for using non-renewable sources of energy.

Provisions for redundancy incentives of euro 186 million were recognized due to a restructuring program involving the Italian personnel related to past reporting periods.

Provisions for losses on investments of euro 139 million were made with respect to certain investees for which expected or incurred losses exceeded carrying amounts.

Provisions for the OIL mutual insurance scheme of euro 70 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.

Provisions for disposal and restructuring of euro 30 million essentially related to Syndial SpA (euro 18 million).

Provisions for long-term construction contracts were reclassified as discontinued operations.

30 Provisions for employee benefits

(euro million)		Dec. 31, 2014		Dec. 31, 2015

TFR		376		236
Foreign defined benefit plans		572		532
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans		174		146
Other benefit plans		191		142
		1,313		1,056

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.

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Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and the United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement.

Group companies provide healthcare benefits. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company for retired managers.

Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers, jubilee awards and Gas fund. 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. The Gas fund is a supplementary pension fund set up in the 70’s and managed by INPS and relating to the employees of the gas distribution sector. This fund, previously considered a defined contribution plan, became a defined benefit plan as a result of a recent change of the law. Such regulatory change also affected Eni comprises personnel deriving from the merger of the former “Italgas Più” who resulted enrolled in the Gas fund.

Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

		Dec. 31, 2014		Dec. 31, 2015

(euro million)

TFR

Foreign defined benefit plans

FISDE and other foreign medical plans

Other benefit plans

Total

TFR

Foreign defined benefit plans

FISDE and other foreign medical plans

Other benefit plans

Total

Present value of benefit liabilities at beginning of year		350			1,257			136			178			1,921			376			1,282			174			191			2,023
Current cost					52			3			47			102						40			2			50			92
Interest cost		10			47			5			3			65			5			40			3			1			49
Remeasurements:		36			48			16			(1	)		99			(26	)		(20	)		(1	)		(15	)		(62	)
- actuarial (gains) losses due to changes in demographic assumptions					1									1						(5	)								(5	)
- actuarial (gains) losses due to changes in financial assumptions		43			57			18			5			123						4			2			(12	)		(6	)
- experience (gains) losses		(7	)		(10	)		(2	)		(6	)		(25	)		(26	)		(19	)		(3	)		(3	)		(51	)
Past service cost and (gains) losses settlements					(4	)					3			(1	)					(9	)		(1	)		13			3
Plan contributions:					1									1						1									1
- employee contributions					1									1						1									1
Benefits paid		(19	)		(46	)		(7	)		(51	)		(123	)		(25	)		(56	)		(7	)		(53	)		(141	)
Reclassification to discontinued operations and asset held for sale																	(97	)		(219	)		(33	)		(52	)		(401	)
Changes in the scope of consolidation		1												1
Currency translation differences and other changes		(2	)		(73	)		21			12			(42	)		3			143			9			7			162
Present value of benefit liabilities at end of year (a)		376			1,282			174			191			2,023			236			1,202			146			142			1,726
Plan assets at beginning of year					642									642						710									710
Interest income					26									26						23									23
Return on plan assets					18									18						(11	)								(11	)
Past service cost and (gains) losses settlements
Administration expenses paid					(1	)								(1	)					(1	)								(1	)
Plan contributions:					35									35						42									42
- employee contributions					1									1						1									1
- employer contributions					34									34						41									41
Benefits paid					(25	)								(25	)					(24	)								(24	)
Reclassification to discontinued operations and asset held for sale																				(123	)								(123	)
Currency translation differences and other changes					15									15						54									54
Plan assets at end of year (b)					710									710						670									670
Net liability recognized at end of year (a-b)		376			572			174			191			1,313			236			532			146			142			1,056

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Foreign defined benefit plans amounting to euro 532 million (euro 572 million at December 31, 2014) primarily related to pension plans for euro 401 million (euro 381 million at December 31, 2014).

Foreign employee benefit plans included the liability attributable to joint venture partners operating in exploration and production activities of euro 281 million (euro 207 million at December 31, 2014). Eni recorded a receivable for an amount equivalent to such liability.

Other employee benefit plans of euro 142 million (euro 191 million at December 31, 2014) related to: (i) defined benefit plans for euro 11 million related to the Gas fund; and (ii) long-term benefit plans for euro 131 million (euro 191 million at December 31, 2014) of which deferred monetary incentive plans for euro 81 million (euro 83 million at December 31, 2014), jubilee awards for euro 23 million (euro 47 million at December 31, 2014), long-term incentive plan for euro 5 million (euro 12 million at December 31, 2014) and other foreign long-term plans for euro 22 million (euro 49 million at December 31, 2014).

Employee benefit plans for euro 278 million were reclassified to discontinued operations.

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 benefit plans		Total

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
2015
Current cost				40			2			50			92
Past service cost and (gains) losses on settlements				(9	)		(1	)		13			3
Interest cost (income), net:
- interest cost on liabilities		5		40			3			1			49
- interest income on plan assets				(23	)								(23	)
Total interest cost (income), net		5		17			3			1			26
- of which recognized in "Payroll and related cost"										1			1
- of which recognized in "Financial income (expense)"		5		17			3						25
Remeasurements for long-term plans										(15	)		(15	)
Other costs/Administration expenses paid				1									1
Total		5		49			4			49			107
- of which recognized in "Payroll and related cost"				32			1			49			82
- of which recognized in "Financial income (expense)"		5		17			3						25

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Costs recognized in other comprehensive income consisted of the following:

		2014		2015

(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					1						1						(5	)					(5	)
Actuarial (gains)/losses due to changes in financial assumptions		43			57			18			118						4			2			6
Experience (gains) losses		(7	)		(10	)		(2	)		(19	)		(26	)		(19	)		(3	)		(48	)
Return on plan assets					(18	)					(18	)					11						11
		36			30			16			82			(26	)		(9	)		(1	)		(36	)

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, 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
December 31, 2015
Plan assets with a quoted market price		41		89		230		10		2		2		17		273		664
Plan assets without a quoted market price														6				6
		41		89		230		10		2		2		23		273		670

Plan assets are generally managed by external asset managers pursuing investment strategies, defined by Eni’s companies, with the aim of ensuring that assets are sufficient to pay the benefits. For this purpose, the investments are aimed at maximizing the expected return and limit the risk level through proper diversification.

The main actuarial assumptions used in the measurement of the liabilities at year end and in the estimate of costs expected for 2016 consisted of the following:

		TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other benefit plans

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
2015
Discount rate		(%)		2.0		0.8-15.3		2.0		0.5-2.0
Rate of compensation increase		(%)		3.0		2.0-13.3
Rate of price inflation		(%)		2.0		0.6-9.7		2.0		2.0
Life expectations on retirement at age 65		(years)				13-23		24

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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

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
2015
Discount rate		(%)		2.0		0.8-3.8		3.5-15.3		9.4-9.5		0.8-15.3
Rate of compensation increase		(%)		2.0-3.0		2.5-4.7		5.0-13.3		10.0		2.0-13.3
Rate of price inflation		(%)		2.0		0.6-2.5		3.5-9.7		5.5-8.2		0.6-9.7
Life expectations on retirement at age 65		(years)		22		22-23		13-15				13-23

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.

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, 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 benefit plans		(4	)		4		3
December 31, 2015
Effect on DBO
TFR		(14	)		15		10
Foreign defined benefit plans		(72	)		81		45		26				53
FISDE and other foreign medical plans		(7	)		8						8
Other benefit plans		(2	)		2		1

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 76 million, of which euro 48 million related to defined benefit plans.

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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 benefit plans

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
December 31, 2015
2016		3		31		5		29
2017		4		33		5		34
2018		5		43		5		53
2019		7		34		5		2
2020		9		37		6		2
2021 and thereafter		208		354		120		44

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 benefit plans

2014
Weighted average duration		13.3		18.1		14.3		4.6
2015
Weighted average duration		12.0		16.5		14.1		4.3

31 Deferred tax liabilities

Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for euro 3,113 million (euro 3,915 million at December 31, 2014).

(euro million)	Amount at Dec. 31, 2014		Additions		Deductions		Currency translation differences		Other changes		Amount at Dec. 31, 2015

7,847

578

(2,842)

883

455

6,921

Deferred tax assets and liabilities consisted of the following:

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Deferred tax liabilities		11,762			10,034
Deferred tax assets available for offset		(3,915	)		(3,113	)
		7,847			6,921
Deferred tax assets not available for offset		(5,231	)		(4,349	)
Net deferred tax liabilities		2,616			2,572

Net deferred tax liabilities of euro 2,572 million (euro 2,616 million at December 31, 2014) 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 163 million); (ii) the revaluation of defined benefit plans (deferred tax assets for euro 6 million); and (iii) the fair value measurement of available-for-sale securities (deferred tax liabilities for euro 1 million).

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

(euro million)	Carrying amount at Dec. 31, 2014		Additions		Deductions		Currency translation differences		Other changes		Carrying amount at Dec. 31, 2015

Deferred tax liabilities
Accelerated tax depreciation		8,320			199			(1,102	)		695			(300	)		7,812
Difference between the fair value and the carrying amount of assets acquired following business combinations		1,480			52			(536	)		150			(5	)		1,141
Site restoration and abandonment (tangible assets)		813			71			(303	)		(5	)		30			606
Application of the weighted average cost method in evaluation of inventories		53			1			(15	)		4			(4	)		39
Capitalized interest expense		2			28			(2	)		(1	)		(2	)		25
Other		1,094			227			(884	)		40			(66	)		411
		11,762			578			(2,842	)		883			(347	)		10,034
Deferred tax assets, gross
Carry-forward tax losses		(2,922	)		(761	)		37			(9	)		932			(2,723	)
Site restoration and abandonment (provisions for contingencies)		(2,372	)		(90	)		295			(176	)		(58	)		(2,401	)
Accruals for impairment losses and provisions for contingencies		(1,691	)		(113	)		298			(3	)		179			(1,330	)
Timing differences on depreciation and amortization		(2,103	)		(679	)		266			(214	)		75			(2,655	)
Impairment losses		(1,062	)		(11	)		138			2			123			(810	)
Unrealized intercompany profits		(309	)		(72	)		14			(3	)		121			(249	)
Other		(1,987	)		(101	)		388			(141	)		40			(1,801	)
		(12,446	)		(1,827	)		1,436			(544	)		1,412			(11,969	)
Impairments of deferred tax assets		3,300			1,420			(4	)		49			(258	)		4,507
Deferred tax assets, net		(9,146	)		(407	)		1,432			(495	)		1,154			(7,462	)
Net deferred tax liabilities		2,616			171			(1,410	)		388			807			2,572

Italian taxation law allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. An average tax rate of 24% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses, which will be utilized in future years to offset expected taxable profit. The corresponding rate for foreign subsidiaries was 35%.

Carry-forward tax losses amounted to euro 8,885 million and can be used indefinitely for euro 7,436 million. Carry-forward tax losses regarded Italian companies for euro 6,346 million and foreign companies for euro 2,539 million. Carry-forward tax losses amounted to euro 8,284 million which are likely to be utilized against future taxable profit and were in respect of Italian companies for euro 5,745 million and foreign subsidiaries for euro 2,539 million. Deferred tax assets recognized on these losses amounted to euro 1,368 million and euro 882 million, respectively.

32 Other non-current liabilities

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Fair value of derivatives financial instruments		143		98
Current income tax liabilities		20		23
Other payables towards tax authorities		5		29
Other payables		104		81
Other liabilities		2,013		1,621
		2,285		1,852

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Fair value related to derivative financial instruments is disclosed in note 33 – Derivative financial instruments.

Other liabilities of euro 1,621 million (euro 2,013 million at December 31, 2014) included advances received from Suez following a long-term agreement for supplying natural gas and electricity of euro 736 million (euro 812 million at December 31, 2014). The current portion is described in note 27 – Other current liabilities. Advances for euro 281 million at December 31, 2014 relating to volumes of gas collected for amounts lower than the minimum take by certain of Eni’s clients, reflecting take-or-pay clauses contained in the long-term sale contracts, were completely off-taken during 2015.

Liabilities with related parties are described in note 45 – Transactions with related parties.

33 Derivative financial instruments

		Dec. 31, 2014		Dec. 31, 2015

(euro million)

Fair value asset

Fair value liability

Level of fair value

Fair value asset

Fair value liability

Level of fair value

Non-hedging derivatives
Derivatives on exchange rate:
- currency swap		349			770			2		223			311			2
- outright		83			12			2		7			2			2
- interest currency swap		139			7			2		97			33			2
		571			789					327			346
Derivatives on interest rate:
- interest rate swap		52			29			2		30			20			2
		52			29					30			20
Derivatives on commodities:
- over the counter		980			600			2		550			491			2
- future		2,662			2,631			1		1,586			1,483			1
		3,642			3,231					2,136			1,974
		4,265			4,049					2,493			2,340
Trading derivatives
Derivatives on commodities:
- over the counter		2,130			2,552			2		2,647			3,054			2
- options		122			123			2		153			176			2
- future		156			214			1		409			559			1
		2,408			2,889					3,209			3,789
Cash flow hedge derivatives
Derivatives on commodities:
- over the counter		47			504			2		19			614			2
- future		45			50			1		107						1
		92			554					126			614
Derivatives on exchange rate:
- outright		1			8			2
		93			562					126			614
Embedded derivatives		34						2		20						2
Option embedded in convertible bonds					59			2					26			2
Gross amount		6,800			7,559					5,848			6,769
Offsetting		(3,305	)		(3,305	)				(2,410	)		(2,410	)
Net amount		3,495			4,254					3,438			4,359
Of which:
- current		3,299			4,111					3,220			4,261
- non-current		196			143					218			98

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace.

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Fair values of non-hedging derivatives consisted of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not relate to specific trade or financing transactions.

Fair values of trading derivatives consisted of derivatives entered for trading purposes and proprietary trading.

Fair value of cash flow hedge derivatives related to the hedges entered by the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanism of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 35 – Shareholders’ equity and in note 39 – Operating expenses. Information on hedged risks and hedging policies is disclosed in note 37 – Guarantees, commitments and risks - Risk factors.

Derivatives embedded in the pricing formulas related to certain long-term supply contracts of gas in the Exploration & Production segment.

Options embedded in convertible bonds related to the convertible bond into ordinary shares of Snam SpA. More information is disclosed in note 28 – Long-term debt and current portion of long-term debt.

Assets and liabilities related to derivative financial instruments for euro 50 million and euro 9 million, respectively, were reclassified as discontinued operations.

34 Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale

Discontinued operations

Saipem
On October 27, 2015, Eni executed a sale and purchase agreement to divest a stake in Saipem SpA consisting of No. 55,176,364 ordinary shares, representing 12.503% of the Company share capital to Fondo Strategico Italiano SpA (FSI), at a price per share of euro 8.3956 for a total consideration amounting to euro 463 million. At the same time, Eni and FSI entered into a shareholders’ agreement to become effective the date of closing of the transfer of share. The shareholder agreement is intended to define the term of engagement governing the relations between Eni and FSI as shareholders of Saipem and to establish joint control over the former subsidiary. The shareholders’ agreement, to which Eni and FSI will contribute an equal number of Saipem shares and is established with an initial term of three years, with automatic renewal of further three years, unless terminated by notice. The key elements of the shareholders’ agreement provides, inter alia: (a) for future corporate bodies appointment, the submission by Eni and FSI of a single list for the appointment of the Board of Directors (where the President and the CEO will be designated jointly by the parties) and the panel of statutory auditors and the relevant vote commitments; (b) mutual commitments to stand-still and lock-up commitment on all the shares contributed to the shareholders’ agreement, and certain other restriction regarding the transfer of shares not contributed to the shareholders’ agreement; and (c) obligations to engage in consultation before exercising voting rights and, to the extent permitted by law, voting commitments (also regarding saipem shares not contributed to the shareholders’ agreement) in relation to all resolutions submitted to the shareholders meetings of Saipem and certain resolutions of Saipem’s Board of Directors that are conventionally considered relevant, including in particular the approval of the industrial plans. At the time of the agreements, the two partners assumed towards Saipem an irrevocable commitment to a pro-rata subscription of the newly issued shares part of a share capital increase amounting to euro 3.5 billion approved by Saipem. Furthermore, the agreements provide for the reimbursement by Saipem of intercompany loans granted by Eni through the proceeds of the capital increase and the refinancing at credit institutions. On January 22, 2016, there was the closing of the sale and purchase agreement with the fulfillment of all the conditions precedent, in particular the clearance by Consob to the subscription of the share capital of Saipem. Eni collected a total consideration amounting to euro 463 million for the share transaction. At the same date the shareholder agreement between Eni and FSI entered into force and established the joint control of Saipem. Therefore, Saipem has been derecognized from Eni’s consolidated accounts and accounted for using the equity method. At the date of the loss of the control (January 22, 2016), the residual interest in the former subsidiary, representing approximately 30.42% of the entity share capital, was aligned at the market price at closing of euro 4.2 per share corresponding to a carrying amount of euro 564 million with a charge through profit and loss of euro 441 million (considering the carrying value at December 31, 2015). Subsequently to closing, Saipem’s market capitalization has fallen sharply. Under the provisions of IAS 10

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these negative developments do not constitute adjusting events of the Saipem valuation made in 2015 accounts which aligned the carrying amount of Eni’s net assets in Saipem to the market price at December 31, 2015. Following the successful closing of Saipem share capital increase before the end of February (Eni cash out of euro 1,069 million), Saipem performed the repayment of the intercompany loans granted by Eni through the proceeds of the share capital increase and new funding granted by financial institutions (euro 5,818 million as of December 31, 2015).

Versalis
Regarding the Eni’s Chemical business, managed by Versalis SpA (Eni 100%), as of the reporting date, negotiations were underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business.

As the Company considers those segments to be major lines of business, management recorded results of the operations of the Engineering & Construction and the Chemical business as discontinued operations. As provided by IFRS 5, Eni’s net assets in Saipem and Versalis have been aligned to the lower of their carrying amount and fair value.

For Saipem the alignment of the carrying amount to the market price at the reporting date (euro 7.49 per share) resulted in an impairment charge of euro 393 million as a contra to goodwill; furthermore depreciation of tangible assets has been discontinued from the date of the classification as discontinued operations (November 1, 2015).

For Versalis the alignment of the carrying amount to the fair value, consistent with the expected outcome of the negotiations currently underway, resulted in an impairment charge of euro 1,576 million as a contra to tangible assets, intangible assets and deferred tax assets.

As provided for by International Financial Reporting Standards (IFRS 5), Saipem and Versalis continued to be included in the scope of consolidation of Eni as of December 31, 2015. Therefore, the amounts represented as discontinued operations included elimination of intragroup transaction. In particular: (i) in the balance sheet assets and liabilities are represented in a specific line item, respectively; (ii) in the profit and loss account, results relating to discontinued operations net of tax effects, are presented in a specific line item before the net profit for the year; and (iii) in the statement of cash flows, net cash provided by operating activities relating to discontinued operations are separately indicated. The amounts relating to discontinued operations comprised in the profit and loss account and the statement of cash flows present the relevant comparisons.

The main line items of the balance sheet of the discontinued operations net of intragroup transactions are provided below.

Saipem

(euro million)		Dec. 31, 2015

Current assets		6,872
Non-current assets		8,531
Total assets		15,403
Current liabilities		5,667
Non-current liabilities		780
Total liabilities		6,447

Versalis

(euro million)		Dec. 31, 2015

Current assets		1,528
Non-current assets		455
Total assets		1,983
Current liabilities		370
Non-current liabilities		215
Total liabilities		585

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The main line items of profit and loss and cash flow statement of the discontinued operations net of intragroup transactions are provided below.

Saipem

(euro million)		2013		2014		2015

Revenues				10,743			11,644			10,277
Operating expenses				11,731			12,731			12,199
Operating profit				(988	)		(1,087	)		(1,922	)
Finance income (expense)				(14	)		116			60
Income (expense) from investments				2			24			30
Profit before income taxes				(1,000	)		(947	)		(1,832	)
Income taxes				(113	)		(2	)		(142	)
Net profit:				(1,113	)		(949	)		(1,974	)
- attributable to Eni				(488	)		(417	)		(826	)
- attributable to non-controlling interest				(625	)		(532	)		(1,148	)
Earnings per share		(euro per share)		(0.14	)		(0.12	)		(0.23	)
Net cash provided by operating activities				(521	)		273			(1,226	)
Net cash flow from investing activities				(938	)		(684	)		(456	)
Net cash used in financing activities				(227	)		126			(57	)
Capital expenditures				902			694			561

Versalis

(euro million)		2013		2014		2015

Revenues				5,677			5,078			4,603
Operating expenses				3,668			3,659			4,461
Operating profit				2,009			1,419			142
Finance income (expense)				4						13
Income (expense) from investments							(3	)		(3	)
Profit before income taxes				2,013			1,416			152
Income taxes				163			191			(429	)
Net profit:				2,176			1,607			(277	)
- attributable to Eni				2,176			1,607			(277	)
Earnings per share		(euro per share)		0.60			0.45			(0.08	)
Net cash provided by operating activities				2,415			1,675			1,948
Net cash flow from investing activities				(471	)		(391	)		(291	)
Net cash used in financing activities				(1	)		6			7
Capital expenditures				314			282			220

 

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 130 million and euro 38 million, respectively, related to the sale of 100% stake of the subsidiaries Eni Slovenija doo and Eni Hungaria Zrt, companies operating in the retail and wholesale marketing of fuels with activities in Slovenia and Hungaria. These subsidiaries were classified as assets held for sale following the sign of binding agreements with MOL Group, a Hungarian oil&gas company, at the end of 2015. The completion of these agreements is subject to certain conditions precedent, 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 amounted to euro 113 million (of which current assets for euro 41 million) and euro 38 million (of which current liabilities for euro 37 million), respectively. Eni will continue to operate in those countries through the wholesale marketing of lubricants.

Divestments made in 2015 for a total consideration of euro 214 million primarily related to: (i) the sale of 100% stake of the subsidiaries Eni Ceská Republika Sro, Eni Romania Srl and Eni Slovensko Spol Sro, companies operating in the retail and wholesale marketing of fuels, with activities in Czech Republic, Romania and Slovakia, respectively. Eni will continue to operate in those countries through the wholesale marketing of lubricants; (ii) the sale of 32.445% stake (entire stake own) in Ceská Rafinérská AS (CRC), a company operating in the refining activity in Czech Republic; (iii) the sale of a 20% stake (entire stake own) in Fertilizantes Nitrogenados de Oriente CEC and Fertilizantes Nitrogenados de Oriente SA, companies operating in the production of fertilizers in Venezuela; and (iv) the sale of a 76% stake in Inversora de Gas Cuyana SA (entire stake owned), a 6.84% stake in

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Distribudora de Gas Cuyana SA (entire stake owned), a 25% stake in Inversora de Gas del Centro SA (entire stake owned) and a 31.35% stake in Distribudora de Gas del Centro SA (entire stake owned), companies operating in the distribution and commercialization of natural gas in Argentina.

More information is provided in note 36 – Other information - Supplemental cash flow information and note 41 – Income (expense) from investments.

35 Shareholders’ equity

Non-controlling interest

(euro million)		Net profit		Shareholders’ equity

		2014		2015		Dec. 31, 2014		Dec. 31, 2015

Saipem SpA		(345	)		(600	)		2,398		1,872
Others		(96	)		5			57		44
		(441	)		(595	)		2,455		1,916

Eni shareholders’ equity

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Share capital		4,005			4,005
Legal reserve		959			959
Reserve for treasury shares		6,201			581
Reserve related to the fair value of cash flow hedging derivatives net of tax effect		(284	)		(474	)
Reserve related to the fair value of available-for-sale securities net of tax effect		11			8
Reserve related to the defined benefit plans net of tax effect		(122	)		(92	)
Other reserves		207			180
Cumulative currency translation differences		4,020			8,407
Treasury shares		(581	)		(581	)
Retained earnings		46,067			48,972
Interim dividend		(2,020	)		(1,440	)
Net profit for the year		1,291			(8,783	)
Other items of comprehensive income related to discontinued operations					11
		59,754			51,753

Share capital
As of December 31, 2015, 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, 2014).

On May 13, 2015, Eni’s Shareholders’ Meeting declared to distribute a dividend of euro 0.56 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2014 dividend of euro 1.12 per share, of which euro 0.56 per share paid as interim dividend. The balance was paid on May 20, 2015, to shareholders on the register on May 18, 2015, record date on May 19, 2015.

 

Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

 

Reserve for treasury shares
The reserve for treasury shares of euro 581 million (euro 6,201 million at December 31, 2014) represents the reserve which was established in previous reporting period to repurchase the Company shares in accordance with

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resolutions at Eni’s Shareholders’ Meetings. On November 8, 2015, the shareholders’ authorization to repurchase own shares expired and the unused portion of euro 5.62 billion was reclassified to the reserves from which it was originated.

 

Reserves related to the fair value measurement of cash flow hedging derivatives, available-for-sale financial assets and defined benefit plans
The reserves related to the valuation at fair value of cash flow hedging derivatives, available-for-sale financial instruments and defined benefit plans, net of the related tax effect, consisted of the following:

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	)
Reclassification to discontinued operations		(439	)		108			(331	)		(4	)		1			(3	)		34			(20	)		14			(409	)		89			(320	)
Changes of the year 2015		5			(1	)		4												23			(6	)		17			28			(7	)		21
Foreign currency translation differences																				(1	)					(1	)		(1	)					(1	)
Amount recognized in the profit and loss account		181			(44	)		137																					181			(44	)		137
Reserve as of December 31, 2015		(637	)		163			(474	)		9			(1	)		8			(98	)		6			(92	)		(726	)		168			(558	)

Reserve for available-for-sale financial instruments net of tax effect of euro 8 million (euro 11 million at December 31, 2014) related to the fair value evaluation of securities.

Reserve for defined-benefit plans of euro 1 million as of December 31, 2014 net of the related tax effect, related to investments accounted for under the equity method.

 

Other reserves Other reserves amounting to euro 180 million (euro 207 million at December 31, 2014) related to:

•

a reserve of euro 247 million representing the increase in Eni shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiary Snamprogetti SpA to Saipem Projects SpA (both merged into Saipem SpA) at a price higher than the book value of the interest transferred (same amount as of December 31, 2014);

•		a reserve of euro 63 million deriving from Eni SpA’s equity (same amount as of December 31, 2014);
•		a reserve of euro 5 million representing 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, 2014);
•		a negative reserve of euro 11 million relating to the share of "Other comprehensive income" on equity accounted entities (a negative reserve of euro 2 million at December 31, 2014);
•		a negative reserve of euro 124 million representing 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, 2014); and
•		a reserve of euro 18 million as of December 31, 2014 relating to the sale of treasury shares to Saipem managers upon exercise of stock options was reclassified to carry-forward profits relating to prior years following the depreciation of the corresponding goodwill.

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Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

 

Treasury shares
A total of 33,045,197 Eni’s ordinary shares (same amount as of December 31, 2014) were held in treasury for a total cost of euro 581 million (same amount as of December 31, 2014).

 

Interim dividend
The interim dividend for the year 2015 amounted to euro 1,440 million corresponding to euro 0.40 per share, as resolved by the Board of Directors on September 17, 2015, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 23, 2015, record date on September 21, 2015.

 

Distributable reserves
As of December 31, 2015, Eni shareholders’ equity included distributable reserves of approximately euro 46.9 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)		2014		2015		Dec. 31, 2014		Dec. 31, 2015

As recorded in Eni SpA’s Financial Statements		4,455			1,918			40,529			38,570
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company		(3,548	)		(10,518	)		22,913			15,599
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(16	)		(58	)		383			308
- adjustments to comply with Group account policies		(573	)		(523	)		(44	)		374
- elimination of unrealized intercompany profits		770			96			(1,604	)		(1,219	)
- deferred taxation		(238	)		(270	)		18			44
- other adjustments					(23	)		14			(7	)
		850			(9,378	)		62,209			53,669
Non-controlling interest		441			595			(2,455	)		(1,916	)
As recorded in Consolidated Financial Statements		1,291			(8,783	)		59,754			51,753

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36 Other information

Supplemental cash flow information

(euro million)		2013		2014		2015

Effect of investment of companies included in consolidationand businesses
Current assets		51			96
Non-current assets		39			265
Net borrowings		(12	)		(19	)
Current and non-current liabilities		(36	)		(291	)
Net effect of investments		42			51
Fair value of investments held before the acquisition of control		(8	)		(15	)
Purchase price		34			36
less:
Cash and cash equivalents		(9	)
Cash flow on investments		25			36
Effect of disposal of consolidated subsidiaries and businesses
Current assets		47			5			44
Non-current assets		41			2			125
Net borrowings		23						(77	)
Current and non-current liabilities		(69	)		(2	)		(45	)
Net effect of disposals		42			5			47
Reclassification of exchange rate differences to other items of comprehensive income								(34	)
Gain on disposal		3,359			(5	)		66
Non-controlling interest
Selling price		3,401						79
less:
Cash and cash equivalents								(6	)
Cash flow on disposals		3,401						73

Divestments of 2015 referred to the sale of 100% stake of Eni Ceská Republika Sro, Eni Romania Srl and Eni Slovensko Spol Sro, companies operating in the retail and wholesale marketing of fuels, with activities in Czech Republic, Romania and Slovakia, respectively.

37 Guarantees, commitments and risks

Guarantees

		Dec. 31, 2014		Dec. 31, 2015

(euro million)

Unsecured guarantees

Other guarantees

Total

Unsecured guarantees

Other guarantees

Total

Eni
Consolidated subsidiaries				10,683		10,683				7,929		7,929
Unconsolidated subsidiaries				180		180				113		113
Consolidated joint operations				14		14				6		6
Joint ventures and associates		6,122		99		6,221		6,122		75		6,197
Others		2		197		199		7		216		223
		6,124		11,173		17,297		6,129		8,339		14,468
Engineering & Construction
Consolidated subsidiaries				2,531		2,531				3,349		3,349
Joint ventures and associates		150				150		150		68		218
		150		2,531		2,681		150		3,417		3,567
		6,274		13,704		19,978		6,279		11,756		18,035

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Eni
Other guarantees issued on behalf of consolidated subsidiaries of euro 7,929 million (euro 10,683 million at December 31, 2014) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 4,381 million (euro 7,029 million at December 31, 2014), of which euro 2,483 million related to the Engineering & Construction segment (euro 3,900 million at December 31, 2014); (ii) VAT recoverable from tax authorities for euro 1,310 million (euro 1,469 million at December 31, 2014); and (iii) insurance risk for euro 140 million reinsured by Eni (euro 179 million at December 31, 2014). At December 31, 2015, the underlying commitment covered by such guarantees was euro 7,808 million (euro 10,631 million at December 31, 2014).

Other guarantees issued on behalf of unconsolidated subsidiaries of euro 113 million (euro 180 million at December 31, 2014) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for euro 102 million (euro 167 million at December 31, 2014). At December 31, 2015, the underlying commitment covered by such guarantees was euro 113 million (euro 21 million at December 31, 2014).

Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of euro 6,197 million (euro 6,221 million at December 31, 2014) primarily consisted of: (i) an unsecured guarantee of euro 6,122 million (same amount as of December 31, 2014) 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 12 million (euro 21 million at December 31, 2014); and (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for euro 6 million (euro 21 million at December 31, 2014). At December 31, 2015, the underlying commitment covered by such guarantees was euro 72 million (euro 97 million at December 31, 2014).

Unsecured and other guarantees given on behalf of third parties of euro 223 million (euro 199 million at December 31, 2014) 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 regasification activity for euro 187 million (euro 168 million at December 31, 2014); and (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit for euro 15 million on behalf of minor investments or companies sold (euro 8 million at December 31, 2014). At December 31, 2015, the underlying commitment covered by such guarantees was euro 214 million (euro 186 million at December 31, 2014).

Engineering & Construction segment
Other guarantees issued by the Engineering & Construction segment on behalf of consolidated subsidiaries belonging to its segment of euro 3,349 million (euro 2,531 million at December 31, 2014) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 3,092 million (euro 2,045 million at December 31, 2014); (ii) VAT recoverable from tax authorities for euro 99 million (euro 98 million at December 31, 2014). At December 31, 2015, the underlying commitment covered by such guarantees was euro 3,349 million (euro 2,531 million at December 31, 2014).

Unsecured guarantees and other guarantees issued by the Engineering & Construction segment on behalf of joint ventures and associates belonging to its segment of euro 218 million (euro 150 million at December 31, 2014) primarily consisted of: (i) unsecured guarantees and other guarantees given to banks in relation to loans and lines of credit received for euro 150 million (same amount as of December 31, 2014); and (ii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for euro 68 million. At December 31, 2015, the underlying commitment covered by such guarantees was euro 218 million (euro 150 million at December 31, 2014).

Commitments and risks

(euro million)		Dec. 31, 2014		Dec. 31, 2015

Commitments		15,276		21,241
Risks		415		422
		15,691		21,663

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Other commitments of euro 21,241 million (euro 15,276 million at December 31, 2014) 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 12,794 million (euro 11,112 million at December 31, 2014); (ii) commitments entered by the Exploration & Production for leasing contracts (chartering, operation and maintenance) of FPSO vessels to be used for development projects in Angola and Ghana. Total commitments amounted to approximately euro 4,364 million and have a duration ranging between 12 and 17 years; (iii) commitments assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service for the acquisition of volumes of regasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031) and towards Gulf LNG Energy for the acquisition of regasification capacity at the Pascagoula terminal (5.8 BCM/y) over a twenty-year period (until 2031). The expected commitments have been estimated at euro 2,590 million and euro 1,191 million, respectively (euro 2,431 million and euro 1,137 million at December 31, 2014, respectively) and have been included in 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; and (v) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 133 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 130 million at December 31, 2014). The commitment has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk".

Risks of euro 422 million (euro 415 million at December 31, 2014) primarily concerned potential risks associated with contractual assurances given to acquirers of certain investments and businesses of Eni for euro 326 million (euro 351 million at December 31, 2014), of which euro 39 million related to the Chemical business, and the value of assets of third parties under the custody of Eni for euro 96 million (euro 64 million at December 31, 2014).

 

Non-quantifiable commitments
A parent company guarantee was issued on behalf of CARDÓN IV (Eni’s interest 50%), a joint venture that is currently operating development activities at the Perla gas field located in Venezuela, for the supplying to PDVSA GAS of gas quantities until 2036 (end of the concession agreement). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective as a result of the revision of the contractual agreements. In case of failure on part of the operator to deliver the contractual gas volumes out of production, the amount of the guarantee execution will be determined by applying the local legislation. The Eni share of the contractual volumes of gas to be delivered to PDVSA amounted to a total of US$16 billion. Notwithstanding that amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued to Eni by PDVSA relating to the fulfillment of the commitments relating to the gas quantities to be collected by PDVSA GAS.

Following the integration signed on April 19, 2011, Eni confirmed to RFI - Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) on October 15, 1991, to guarantee a correct and timely execution of the section Milano-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as general contractor. In order to pledge the guarantee given, the regulation of CEPAV (Consorzio Eni per l’Alta Velocità) Due binds the associates to give proper sureties and guarantees on behalf of Eni.

Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain 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 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.

 

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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 expertise. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk-reducing, these derivatives are reclassified in proprietary trading. As the proprietary trading is considered separately from the other activities in specific portfolios of Eni Trading & Shipping, its exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s policies and guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon; (ii) limits of revision strategy, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given; and (iii) VaR which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account of the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s guidelines define rules to manage the commodity risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of revision strategy, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools the requests for negotiating commodity derivatives and executes them on the marketplace. According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni has decided to retain a cash reserve to face any extraordinary requirement. 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.

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Market risk - Exchange rate
Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates 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. 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. VaR 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&gas prices generally has a negative impact on Eni’s results of operations and vice versa, and may jeopardize the achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk. These exposures include those associated with the program for the production of proved and unproved oil&gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors as of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments, to the components related to the time horizon of the four-year plan and budget and the relevant activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted 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 commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not finalized to the delivery, both within the commodity and financial markets, with the aim to obtain a profit upon the occurrence of a favorable result in the market, in accordance with specific limits of authorized risk (VaR, stop loss). In the proprietary trading exposures are included the origination activities, if not connected to contractual or physical assets.

Strategic risk is not subject to systematic activity of management/coverage that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging activities related to strategic risks are delegated to the top management. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial

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activities in view of achieving stable economic results. The commodity risk and the exposure to commodity prices fluctuations embedded in commodities quoted in currencies other than the euro at each business line (Eni’s Divisions or subsidiaries) is pooled and managed by the Portfolio Management unit for commodities, and by Eni’s finance department for exchange rate requirements. The Portfolio Management unit manages business lines’ risk exposures to commodities, pooling and optimizing Group companies’ exposures and hedging net exposures on the trading venues through the trading unit of Eni Trading & Shipping. In order to manage commodity price risk, Eni uses derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, 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. VaR 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 VaR (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 years 2014 and 2015, 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 VaR, recorded in 2015 (compared with 2014) relating to interest rate and exchange rate risks in the first section and commodity risk. Regarding the management of strategic liquidity, the sensitivity to change of interest rates is expressed by the values of "Dollar Value per Basis Point" (DVBP).

(Value at Risk - Parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

		2014		2015

(euro million)

High

Low

Average

At year end

High

Low

Average

At year end

Interest rate (a)		4.42		1.29		2.05		2.49		6.21		2.45		4.06		4.40
Exchange rate (a)		0.23		0.03		0.09		0.12		0.52		0.05		0.13		0.13

(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%)

		2014		2015

(euro million)

High

Low

Average

At year end

High

Low

Average

At year end

Commercial exposures
- Management Portfolio (a)		44.20		4.02		21.46		4.02		61.91		3.37		26.82		3.37
Trading (b)		5.57		0.46		3.04		0.87		4.07		0.40		1.38		0.55

(a)		Refers to the Midstream Department (risk exposure from Refining & Marketing Division and Gas & Power Division), Versalis, Eni Trading & Shipping commercial portfolio and branches outside Italy pertaining to the Divisions. For the Midstream Department starting from 2014, following the approval of the Eni’s Board of Directors on December 12, 2013, VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the year considering all the volumes delivered in the year and the relevant financial hedging derivatives. Consequently, in the year the VaR pertaining to the Midstream Department presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon.
(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).

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(Sensitivity - Dollar Value of 1 Basis Point - DVBP)

		2014		2015

(euro million)

High

Low

Average

At year end

High

Low

Average

At year end

Strategic liquidity (a)

0.28

0.09

0.14

0.26

0.31

0.25

0.29

0.25

(a)		Management of strategic liquidity portfolio starting from July 2013.

Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of the business.

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. 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 20 billion, of which about euro 14.9 billion were drawn as of December 31, 2015.

The Group has credit ratings of BBB+ look stable and A-2, respectively for long and short-term debt, outlook stable, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked in addition to the Company’s industrial fundamentals and trends in the trading environment to the sovereign credit rating of Italy. On the basis of the methodologies used by

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Standard & Poor’s and Moody’s, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni.

In the course of 2015, Eni issued a bond amounting to euro 1.75 billion related to the Euro Medium Term Notes Program.

As of December 31, 2015, Eni maintained short-term unused borrowing facilities of euro 12,748 million, of which euro 40 million committed. Long-term committed borrowing facilities amounted to euro 6,576 million, of which euro 1,000 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.

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

		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

 

(euro million)		Maturity year

		2016		2017		2018		2019		2020		2021 and thereafter		Total

December 31, 2015
Non-current liabilities		2,332		3,010		2,038		3,826		2,599		8,000		21,805
Current financial liabilities		5,712												5,712
Fair value of derivative instruments		4,261		56		1		33				8		4,359
		12,305		3,066		2,039		3,859		2,599		8,008		31,876
Interest on finance debt		737		654		525		453		354		1,673		4,396
Financial guarantees		169												169

Trade and other payables
The tables below summarize the Group trade and other payables by maturity.

(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

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(euro million)		Maturity year

		2016		2017-2020		2021 and thereafter		Total

December 31, 2015
Trade payables		9,345						9,345
Other payables and advances		5,270		58		23		5,351
		14,615		58		23		14,696

 

Expected payments by period under contractual obligations
The Group has in place a number of contractual obligations arising in the normal course of the business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations pertain to take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors.

The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

(euro million)		Maturity year

		2016		2017		2018		2019		2020		2021 and thereafter		Total

Contractual obligations - Eni
Operating lease obligations (a)		493		397		279		203		174		807		2,353
Decommissioning liabilities (b)		423		423		408		372		351		15,079		17,056
Environmental liabilities (c)		241		238		207		179		37		643		1,545
Purchase obligations (d)		11,938		10,391		10,579		10,040		8,793		104,349		156,090
- Gas
. take-or-pay contracts		9,426		8,810		9,282		8,837		8,031		100,239		144,625
. ship-or-pay contracts		1,706		1,324		1,118		1,034		593		2,958		8,733
- Other take-or-pay or ship-or-pay obligations		111		101		94		87		86		277		756
- Other purchase obligations (e)		695		156		85		82		83		875		1,976
Other obligations		6		4		3		2		2		116		133
- Memorandum of intent relating Val d’Agri		6		4		3		2		2		116		133
		13,101		11,453		11,476		10,796		9,357		120,994		177,177
Contractual obligations - Engineering & Construction and Chemical
Operating lease obligations (a)		110		112		77		72		66		198		635
Environmental liabilities (c)		7		7		4		4		3		10		35
Purchase obligations (d)		96		28		21		14		14		15		188
- Other purchase obligations		96		28		21		14		14		15		188
		213		147		102		90		83		223		858

(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 generally did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(b)		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 regasification facilities in the United States (euro 1,325 million).

 

Capital investment and capital expenditure commitments
In the next four years Eni expects capital investments and capital expenditures of euro 40.3 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.

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The amounts shown in the table below include committed expenditures to execute certain environmental projects.

		Maturity year

(euro million)		2016		2017		2018		2019		2020 and thereafter		Total

Committed projects

8,675

8,040

6,101

5,125

6,040

33,981

Other information about financial instruments
The carrying amount of financial instruments and the relevant economic and equity effect as of and for the years ended December 31, 2014 and 2015 consisted of the following:

		2014		2015

		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)		5,024			24						5,028			3
Non-hedging derivatives (b)		192			424						245			330
Trading derivatives (b)		(481	)		27						(1,166	)		(657	)
Held-to-maturity financial instruments
Securities (a)		76			1						77			1
Available-for-sale financial instruments
Securities (a)		257			7			7			282			8			(4	)
Investments valued at fair value
Other non-current investments (c)		1,744			(60	)		(77	)		368			286
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other (d)		27,573			(233	)					19,264			(710	)
Financing receivables (a)		2,763			82						3,009			(133	)
Trade payables and other (e)		23,807			(187	)					14,696			83
Financing payables (a)		25,891			(1,155	)					27,776			(812	)
Net assets (liabilities) for hedging derivatives (f)		(470	)		(503	)		(167	)					(179	)		(256	)

(a)		Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(b)		In the profit and loss account, economic effects were recognized as loss within "Other operating income (loss)" for euro 487 million (income for euro 286 million in 2014) and as income within "Finance income (expense)" for euro 160 million (income for euro 165 million in 2014).
(c)		In the profit and loss account, economic effects were recognized as income within "Income (expense) from investments" for euro 286 million (expense for euro 60 million in 2014).
(d)		In the profit and loss account, economic effects were essentially recognized as expense within "Purchase, services and other" for euro 637 million (expense for euro 460 million in 2014) (impairments net of reversal) and as expense for euro 73 million within "Finance income (expense)" (income for euro 227 million in 2014) (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)		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 181 million (expense for euro 362 million at December 31, 2014) and as income within "Finance income (expense)" for euro 2 million (expense for euro 141 million in 2014) (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, 2014
Financial assets
Trade and other receivables		29,667		1,066		28,601
Other current assets		7,134		2,749		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		7,421		2,932		4,489
Other non-current liabilities		2,658		373		2,285
December 31, 2015
Financial assets
Trade and other receivables		21,661		711		20,950
Other current assets		6,049		2,410		3,639
Financial liabilities
Trade and other liabilities		15,326		711		14,615
Other current liabilities		7,113		2,410		4,703

The offsetting of financial assets and liabilities related to: (i) for euro 2,410 million the offsetting assets and liabilities for financial derivatives pertaining to Eni Trading & Shipping SpA for euro 2,389 million (euro 3,305 million at December 31, 2014) and Eni Trading &-Shipping Inc for euro 21 million; and (ii) for euro 711 million the offsetting of receivables and payables pertaining to the Exploration & Production segment towards state entities for euro 664 million (euro 1,066 million at December 31, 2014) and the offsetting of trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for euro 47 million.

 

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. Following an appeal against this sentence filed by the Public Prosecutor, on December 14, 2015, the Court of Appeal of Bari confirmed the acquittal sentence issued by the First Degree Court. Besides that, an appeal of constituted civil parties was declared inadmissible. Terms are pending to file a counterclaim before a Third Instance Court.

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(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 during the 2014. Once the consultants completed their work, the acts returned to the Public Prosecutor of Crotone for the next step and possible indictment. The defense brief in support of dismissal of charges has been deposited. There are no further developments.

(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 former manager of that industrial complex would stand trial. In the preliminary hearing held in November 2010, 189 persons entered the trial as plaintiff; while 107 persons were declared as having been offended by the alleged crime. The plaintiffs have requested that both Eni and Marzotto SpA would bear civil liability. However, compensation for damages suffered by the offended persons has yet to be determined. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants would stand trial for culpable manslaughter, culpable injuries, environmental disaster and negligent conduct about safety measures on the workplace. Following a settlement agreement with Eni, Marzotto SpA entered settlement agreements with all plaintiffs, except for the local administrations. In December 2014, the Tribunal issued an acquittal sentence for all defendants, as the indictment was found groundless. The Public Prosecutor has proposed an appeal against the sentence.

(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 trial is undergoing with an abbreviated procedure.

(v) Syndial SpA - The illegal landfill in Minciaredda area, Porto Torres site. On July 7, 2015, the Judge for the Preliminary Hearing of the Court of Sassari, on request of the Public Prosecutor, decided the seizure of the Minciaredda landfill area, near the western border of the Porto Torres site. All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure provision involved as well Syndial in accordance with the Legislative Degree No. 231/2001 that held companies liable for the crimes committed by their employees. The investigations are underway. With a reference to the clean-up activities in the Minciaredda area, on January 27, 2016, the administrative body responsible for sanctioning clean-up projects approved: (i) the operative project "Nuraghe" which provides for the soil clean-up in the area "Peci" (deposit of pitch from dimethyl terephthalate - DMT) and in the area "Palte Fosfatiche" (phosphates deposit) in the Minciaredda area; and (ii) an addendum to the operative project of clean-up of the groundwater in the Minciaredda area.

(vi) Syndial SpA - The Phosphate deposit at Porto Torres site (1). On June 30, 2015, the Judge for the Preliminary Hearing of the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, sentenced to seize – as a preventive measure – the area of “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster and carrying out an unauthorized disposal of hazardous wastes. Subsequently, on July 13, 2015 and on July 28, 2015, on specific request, both the Public Security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari authorized Syndial to implement better delimitation of the landfill area, to provide the area with devices to monitor the level of environmental pollutants and meteoric waters. The investigations are underway.

(vii) Syndial SpA - The Phosphate deposit at Porto Torres site (2). On December 16, 2015, the Public Prosecutor at the Court of Sassari sentenced to seize – as a probative measure – the containment systems for the meteoric waters in the area "Palte Fosfatiche" (phosphates deposit). These waters are being collected by Syndial following authorizations of the Public Security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up, management of radioactive waste and spill of waters containing hazardous substances. The Public Prosecutor

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decided to suspend the activities of collection, containment and preservation of the area, in spite that those activities have already been authorized. Syndial filed a request to continue conducting clean-up operations to the Judge for the Preliminary Hearing of the Court of Sassari. The investigations are underway.

(viii) Syndial SpA - Public Prosecutor of Gela. An investigation is pending before the Public Prosecutor of Gela regarding 17 former managers of the Eni Group. The proceeding regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged work-related diseases which those persons may have contracted at the plant of Clorosoda. Alleged crimes relate to the period from 1969, when the Clorosoda plant commenced operations till 1998 when the plant was shut down and clean-up activities were performed. The Public Prosecutor requested the performance of a medico-legal appraisal on over 100 people that were employed at the above mentioned plant. This appraisal was performed by independent consultants designated by the Judge for Preliminary Investigation and did not find any evidence that the various diseases which underwent the medical appraisal could be directly linked to the exposure to emissions related to the production of chlorine and caustic soda. The consultants also found that production activities were in compliance with applicable laws and regulations on health and safety. On January 23, 2015, the Judge for Preliminary Investigation declared that the gathering of evidence before a trial was concluded. The Public Prosecutor issued a notice of the conclusion of preliminary investigations. In this notice it is explained that following the first claim which involved a great number (over one hundred) of cases of bodily harm and culpable manslaughter, the Public Prosecutor decided not to ask for dismiss of charges only in relation to the one specific case, which regards one former employee which in the meantime had died. Therefore, the proceeding has been considerably downsized compared to the initial claim. The rest of the accusatory assumptions, however, seems to be groundless in the light of the results of assessment performed by independent consultants appointed by the Judge for Preliminary Investigation.

(ix) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria - Prosecuting body: Public Prosecutor of Castrovillari. Certain areas owned by Eni in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria have been preventively seized by the Judicial Authority, following a pending investigation about an alleged improper handling of industrial waste from the processing of zinc ferrites at the industrial site of Pertusola Sud, alleged illegally stored. The circumstances under investigation are the same considered in a criminal action for alleged omitted clean-up 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. Besides that, Syndial defined an agreement with the Municipality of Cerchiara and the Municipality of Cassano to settle all claims relating to alleged damages caused by the unauthorized waste disposal in the landfills on the territory of the two Municipalities. The criminal proceeding is still pending. Syndial is performing clean-up and remediation activities.

(x) 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. There are no further developments. Syndial has signed some settlements.

(xi) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA - Alleged environmental disaster. A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Gela Refinery and Enimed SpA relating environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. The Gela Refinery has been sued for administrative offence in accordance with the Law Decree No. 231/2001. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, in addition to the pollution of the sea water near the coast area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. On the closure of the preliminary investigation, the Public Prosecutor of Gela reunited in this proceeding the other investigations related to the pollution occurred at the other sites of the Gela Refinery, as well as hydrocarbon spills of Enimed. The proceeding is still pending, a notice of the conclusion of preliminary investigation was served.

(xii) Proceeding Val d'Agri. The Italian Public Prosecutor’s Office of Potenza started a criminal investigation in order to ascertain existence of an illegal handling of wastes material produced at the Viggiano oil center, part of the Eni-operated Val d’Agri oil complex, and disposed at treatment plants in the national territory. After a two-year investigation, the Prosecutors decided for the domiciliary detention of 5 Eni employees and to put under seizure certain plants functional to the production activity of the Val d’Agri complex which, as a consequences, has been shut down (60 KBOE/d net to Eni). From the commencement of the investigation, Eni has carried out several and

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in-depth technical and environmental surveys, with support of independent experts of international reach, who recognized full compliance of the plant and the industrial process with requirements of applicable laws, as well as with best available technologies and international best practices. For these reasons, Eni asked for the review of the seize measure before an Italian Court and the evidentiary examination, in order to make a definitive assessment of the correctness of the operational running of the plant.

 

1.2 Civil and administrative proceedings in the matters of environment, health and safety

(i) Syndial SpA - Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore - Prosecuting body: Ministry of the Environment. In May 2003, the Ministry of the Environment summoned Syndial to obtain a sentence condemning the Eni subsidiary to compensate an alleged environmental damage caused by the activity of the Pieve 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 of Turin. In the hearing of June 15, 2012, before the Second Degree Court of Turin, the Minister of the Environment, formalized trough the Board of State Lawyers its decision to not enforce the sentence until a final verdict on the matter is reached. The Second Degree Court requested Syndial to stand as defendant and then requested a technical appraisal of the matter. This technical appraisal was favorable to Syndial; however such outcome was questioned by the Board of State Lawyers. On July 8, 2015, the Court of Appeal of Turin requested the consultants appointed by the Court to perform again a technical appraisal of the matter with aim to identify adequate measures for environmental restoration of the external areas. The deadline for the completion of the technical appraisal is 180 days dating from the hearing of assignment (September 30, 2015). The next hearing is due to take place in July 8, 2016.

(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 liable 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. On the hearing of November 19, 2015, the Ministry reaffirmed Syndial’s strict liability as the Eni’s subsidiary took over the site due to a law provision. In 2016, a Third Degree Court sentenced that only the first motivation of the appeal filed by the Ministry is valid, which related to the statute of limitations for the crime of disaster applicable exclusively to the previous owners of the site. Therefore, the Court has definitely confirmed that Syndial is not liable, neither for activities directly conducted (including alleged delay/omission of the clean-up activities claimed by the Ministry) nor for strict liability (as it took over the site from the previous owners). Particular attention should be paid to this second profile in the light of the fact that the Avenza site was transferred to Eni due to a law provision which transferred to Eni the site owned by a third party (SIR/Rumianca) along with the Assemini, Porto Torres and Pieve Vergonte sites. With reference to Syndial’s position, the motivations of the appeal filed by the Ministry were rejected as considered inadmissible or groundless. The Third Instance Court decided that this case is to be returned to the Court of Appeal of Genoa. The proceeding will continue only in relation to the positions of SoGeMO and Nuova Cisa. The costs of the proceeding have been offset by the parties.

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(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 33 parents of children born malformed in the Municipality of Gela between 1992 and 2007. The claim for preventive technical inquiry aims at verifying the relation of causality between the malformation pathologies suffered by the children of the plaintiffs and the environmental pollution caused by the Gela site (pollution deriving from the existence and activities at the industrial plants of 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. The consultants appointed by the Court and those designated by the plaintiffs performed a technical appraisal of the matter, reaching however very different outcomes. Thus, parties failed to reach a settlement of the matter. On December 22, 2015, the three involved Eni companies were sued following a claim of the parents of a girl, whose case was assessed by the above mentioned technical appraisal. Subsequently, the Eni’s companies were sued in relation to other 12 cases, for which an hearing is scheduled. The proceeding is pending.

(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. The procedure is continuing, with a possible involvement of consultants and definition of queries for them.

(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 proceeding continues before the Prosecutor of Sassari. In February 2013, the Prosecutor of Sassari has notified the conclusion of preliminary investigations and requested a new imputation for negligent 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. After a hearing on a question of constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the Constitutional Court.

(vii) Syndial SpA and Versalis SpA - Summon for alleged environmental damage caused by illegal waste disposal in the Municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Syndial and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff claimed the responsibilities of Syndial and Versalis for the production of waste and because they commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001-2003 which would have

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allegedly traced the hazardous waste materials back to the Priolo and Gela industrial sites that are managed by the above mentioned Eni’s subsidiaries (in particular, the waste with high mercury concentration and railway sleepers no longer in use). Such waste was allegedly handled and disposed illegally at an unauthorized landfill owned by a third party (this landfill is located about 2 kilometers from the town of Melilli). The claim amounts to euro 500 million and refers to two Group’s subsidiaries and SMA.RI, the company which carries out activities of waste disposal, being jointly and severally liable. On February 8, 2016, the Judge accepted an explanation of Eni’s subsidiaries stating that the request of Municipality was not admissible, so that the request was rejected. The proceeding is still pending.

(viii) Summon for Eni, Raffineria di Gela SpA, Enimed SpA, Syndial SpA. 273 Gela residents filed an appeal to the Court of Gela requesting to halt all the production activities conducted by Eni’s subsidiaries at Gela site in order to put an end to environmental pollution impacting the health of the local population. The claimants also requested the appointment of commissioners in charge of carrying out the plants shutdown and of continuing to implement clean-up activities in the area. Besides that, they requested the Court to order to the Municipality of Gela – as a competent body in the field of health protection – to adopt certain provisions aimed to preserve the health of the local population. This proceeding arose in connection with an alleged environmental damage caused by the industrial activities of the site and consequent necessity to protect the population from serious harm to the health. The initiative was underpinned by certain technical assessments performed by consultants appointed by the Court on the preliminary stage. The aim of these assessments was to establish cause-and-effect relationship between the industrial contamination and congenital anomalies reported in the town of Gela.

 

2. Court inquiries and of other Regulatory Authorities

(i) 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 to the Court of Appeal of Milan which ruled in favor of the plaintiff. Therefore, Eni was sentenced to pay back about euro 9,200,000 to the airline companies. On October 5, 2015, Eni filed an appeal before a Third Instance Court. On November 13, 2015, the plaintiffs notified the counterclaim and cross-appeal, claiming a euro 17,800,000 payment instead. As a pre-emptive measure, on January 25, 2016, Eni requested not to implement the temporary sentence of the second-degree before the Court of Appeal of Milan, by scheduling the hearing. The Company made a provision for this legal proceeding.

(ii) 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. The proceeding is pending.

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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. With Resolution No. 25064 of August 1, 2014, the Italian Antitrust commenced an investigation to verify whether Eni controlled a bigger share of the domestic wholesale gas market than it had declared. Following the Legislative Decree No. 130 of 2010, which envisages a 55% ceiling to the wholesale market share for each Italian gas operator who inputs gas into the Italian backbone network, Eni declared that its market share was equal to 54%, therefore slightly below the established threshold. Eni calculated its market share by excluding certain sales of gas volumes. On the other hand, the Antitrust rejected this calculation method and therefore concluded that Eni’s market share was actually 56%. Nonetheless, the Antitrust decided not to impose any fine on the Company as the violation was immaterial. The Antitrust considered the fact that in its declaration Eni explained clearly how its market share was calculated. Besides that, in the opinion of the Ministry of Economic Development, expressed during the investigation, Eni calculated its market share correctly. Eni filed an appeal against the Antitrust’s decision before the Regional Administrative Court of Lazio, asking for annulment.

(ii) Eni SpA - Investigation for alleged violations of the Consumer Code in the matter of billing of gas and power consumptions. With a decision notified on July 8, 2015, the Italian Antitrust Authority (AGCM) commenced an investigation to ascertain alleged unfair commercial practices under the Consumer Code in the billing of gas and power consumptions to retail customers. This preliminary investigation originated from certain reports of consumers and consumer organizations received by the AGCM in the period March 2014-June 2015. These complaints regard cases in which Eni allegedly started procedures of formal notice, credit recovery and suspension of supply in relation to: (i) claims for payment of invoices for amounts false, anomalous and/or un-correctly estimated; (ii) credits towards clients for significant amounts accrued in consequence of continued delay in issuing invoices or adjustment payments made after many years with respect to the effective consumption; and (iii) requests for payment of invoices already settled by consumers. The preliminary investigation and the request for information to the Company are aimed at obtaining relevant elements for assessing the existence of these alleged unfair trade practices. In order to close the investigation and to avoid sanctions, Eni filed with the Antitrust Authority a proposal of commitments, which were rejected, though. The proceeding is still pending.

 

4. Court inquiries on the matter of criminal/administrative corporate responsibility

(i) EniPower SpA. In June 2004, the Milan Public Prosecutor commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately dismissed. The Court served EniPower (the commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of investigation in accordance with Legislative Decree No. 231/2001 that establishes that companies are liable for the crimes committed by their employees who acted on behalf of the employer. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the Preliminary Hearing 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 on 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.

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(ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to Saipem in Algeria. On February 4, 2011, Eni received from the Public Prosecutor of Milan an information request pursuant to Article 248 of the Italian Code of Criminal Procedure. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem and Technip relating to the engineering of the ground section of a gas pipeline). For that reason, 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. The proceeding was unified with the Iraq-Kazakhstan proceeding, concerning a different line of investigation, as it related to the activities carried out by Eni in Iraq and Kazakhstan. Subsequently Saipem was served a notice of seizure, then a request for documentation and finally a search warrant was issued, in order to acquire further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, who was fired at the beginning of 2013. On February 7, 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced in accordance with Article 25, third and fourth paragraph of Legislative Decree No. 231/2001 with respect to Eni, Eni’s former CEO, Eni’s former CFO and another senior manager. Eni’s former CFO had previously served as Saipem’s CFO including during the period in which alleged corruption took place and before being appointed as CFO of Eni on August 1, 2008. Eni conducted an internal investigation with the assistance of external consultants, in addition to the review activities performed by its audit and internal control departments and a dedicated team to the Algerian matters. During 2013, the external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department have not found any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on a voluntary basis of the MLE project, the only project that Eni understands to be under the prosecutors’ investigation where the client is an Eni Group company has not found evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling). Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal and accounting and administrative issues. The findings of the review performed have confirmed the autonomy of Saipem from the parent company. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. On October 24, 2014, Eni SpA received a request of probationary evidence by the Prosecutor of Milan relating to for the examination of two defendants: the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem and the former President and General Manager of Saipem Contracting Algérie SpA. On January 14, 2015, the Public Prosecutor of Milan notified the conclusion of preliminary investigations towards Eni, Saipem and eight persons (including, the former CEO and CFO of Eni and the Chief Upstream Officer of Eni who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor of Milan has issued a notice for alleged international corruption against all defendants (including Eni and Saipem on the base of the provisions of Legislative Decree No. 231/2001) in connection with the entry into intermediary contracts by Saipem in Algeria. Furthermore, some of the defendants (including the former CEO and CFO of Eni and the Chief Upstream Officer of Eni) were accused of tax offense for fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. Having acquired the actions of the court filed in relation to the request of probationary evidence, the minutes of the hearing and the documents filed for the conclusion of the preliminary investigation, Eni requested its consultants to perform additional analysis and investigation. As a result, Eni’s consultants reaffirmed their conclusions previously reported to the Company. In February 2015, the Public Prosecutor indicted all the investigated persons for above mentioned crimes. On October 2, 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni, former Chief Executive Officer and Chief Upstream Officer for all the alleged crimes. On February 24, 2016, the Court of Third Instance, upholding an appeal presented by the Public Prosecutor of Milan, reversed the dismissal, annulled the verdict, and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan, so that a new preliminary hearing could be held. At the end of 2012, Eni contacted the U.S. Authorities – the DoJ and the U.S. SEC – in order to

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voluntary inform them about this matter and kept them informed about the developments in the Italian prosecutors’ investigations. Following Eni’s notification in 2012, both the U.S. SEC and the DoJ have started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests.

(iii) Iraq - Kazakhstan. A criminal proceeding is pending before the Public Prosecutor of Milan in relation to alleged crimes of international corruption involving Eni’s activities in Kazakhstan regarding the management of the Karachaganak plant and the Kashagan project, as well as handling of assignment procedures of work contracts by Agip KCO. The Company has filed the documents collected and is fully collaborating with the Public Prosecutor. A number of managers and a former manager are involved in the investigation. The above mentioned proceeding has been combined with another (the so-called "Iraq proceeding") regarding a parallel proceeding related to Eni’s activities in Iraq, disclosed in the following paragraphs. On June 21, 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were searched by the Judicial Authorities. The search involved the offices of certain Group employees and of certain third parties in connection with alleged crimes of conspiracy and corruption as part of the "Jurassic" project in Kuwait. Particularly, the alleged crimes would have been committed in order to illicitly influence the award of a construction contract outside Italy where Eni was the commissioning entity. Considering the claims of the Public Prosecutor, Eni and Saipem believed that they were damaged by the crimes committed by their employees. Eni considered those employees to have breached the Company’s Code of Ethics. In spite of this, Eni SpA and Saipem SpA were notified of being under investigation pursuant to the Legislative Decree No. 231/2001 which establishes the liability of entities for the crimes committed by their employees. Eni SpA was notified by the Public Prosecutor of a request of extension of the preliminary investigations that has led up to the involvement of another employee, as well as other suppliers in the proceeding. The Public Prosecutor of Milan requested Eni SpA to be debarred for one year and six months from performing any industrial activities involving the production sharing contract of 1997 with the Republic of Kazakhstan and in the subsequent administrative or commercial arrangements, or the prosecution of the mentioned activities under the supervision of a commissioner pursuant to Article 15 of the Legislative Decree No. 231/2001. 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 Court. Also based on this decision, on March 13, 2014, the Eni legal team requested to the Public Prosecutor to dismiss the proceeding.

(iv) Block OPL 245, Nigeria. The criminal proceeding regarding alleged international corruption in the acquisition of Block OPL 245 in Nigeria is still pending. On July 2, 2014, the Italian Public Prosecutor of Milan served Eni with a notice of investigation relating to potential liability on the part of Eni arising from alleged international corruption, pursuant to Italian Legislative Decree No. 231/2001 whereby companies are liable for the crimes committed by their employees when performing their tasks. 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, in July 2014, 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. On September 10, 2014, the Public Prosecutor of Milan notified Eni of a restraining order issued by a British judge who ruled the seizure of a bank account 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 inferred that such Eni’s officers and former officers are under investigation by the Italian Public Prosecutor. During a hearing before a Court of London on September 15, 2014, Eni and its current executive officers gave evidence of their non-involvement in the matter regarding the seized bank account. Following the hearing, the Court reaffirmed the seizure. An investigation conducted by an independent U.S. law firm on behalf of Eni’s Board of Statutory Auditors and Watch Structure found no evidence of misconduct in relation to Eni and Shell’s 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. The outcome of the investigation has been made available to the judicial authority reaffirming Eni’s full cooperation and transparency. In December 2015, the Public Prosecutor of Milan requested further postponement of the conclusion of the preliminary investigation. On April 5, 2016, the subsidiary Nigerian Agip Exploration Ltd received a summon in

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order to acquire information in an investigation relating to the concession OPL 245 conducted by the Nigerian EFCC (Economic and Financial Crime Commission).

(v) Eni SpA Refining & Marketing Division - Criminal proceedings on fuel excise tax (Criminal proceeding No. 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 above mentioned, 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 Public Prosecutor of Rome. The motivations of the search are the same as the above mentioned proceeding as the ongoing investigations also relates to a period of time when he was in charge of that Eni’s Division. On March 5, 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. The three criminal proceedings were united together at Public Prosecutor’s Office of Rome, which is still conducting preliminary investigations. Ultimately, the Customs Agency, in reply to the national association of refiners, published a dedicated Circular which provides the rules the operators in the sector should follow to determine the quantity of oil products subjected to the excise tax, so as to give clarification to regional customs agencies, the Revenue Agency and the Finance Police. According to this Circular, Eni and other oil companies followed the correct procedures in order to determine the quantity subjected to the excise tax. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer to the Ministry of Economic Development. The technical appraisal is currently being conducted. On this occasion, it became clear that the proceeding has been extended to a large number of employees and former employees of the company.

(vi) Block Marine XII, Congo. On July 9, 2015, Eni received from the U.S. Department of Justice a subpoena ordering the Company to produce documents in view of the hearing of an Eni employee, relating to the assets "Marine XII" in Congo and relationships with certain persons and companies. According to preliminary informal contacts between Eni’s U.S. lawyers and the Authority, this hearing is part of a broader investigation, which is currently being carried out with regard to third parties. Within such investigation Eni is considered a witness and – potentially – a damaged party. The documents required by the Authority are currently being collected and filed with the Authority.

 

5. Tax Proceedings

Italy

(i) Eni SpA - Dispute for the omitted payment of a municipal tax related to certain oil platforms located in territorial waters in the Adriatic Sea. Several tax proceedings are pending in Italy, as certain municipalities claimed Eni SpA omitted payments of a tax on property relating offshore oil platforms located in the territorial waters under the municipality administration. After completing all degrees of judgment before Italian tax courts, on February 24, 2016, the Third Instance Court sentenced that: (i) property taxes on platforms are due by Eni; (ii) the taxable basis is to be defined by considering the platforms carrying amounts, instead of the replacement cost; and

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(iii) sanctions are not applicable. The proceeding continued with an indictment before a trial judge so as to determine the due amount. Eni has made a provision for this legal proceeding. Starting in 2016, the provisions of the Italian Budget Law provides that equipment, machinery, tools and other plants are excluded from the basis for calculating taxes on property, if functional to a comprehensive production process.

 

Outside Italy

(ii) 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.

 

6. Settled proceedings

(i) TSKJ consortium. This proceeding has been settled as the Third Degree Court rejected the recourse of Saipem against the Court of Appeal of Milan. The Second Degree Court sentenced to confiscate the profit coming from a crime of international corruption, amounting to about euro 25 million. Having released Saipem from this liability in the previous reporting periods, the specific provision had been made by Eni SpA.

(ii) Indonesia. The Tax Administration of Indonesia has questioned the application of a 10% tax rate on the profit earned by Eni’s subsidiary Lasmo Sanga Sanga Ltd, which is resident in the United Kingdom for tax purposes. The Tax Administration of Indonesia has claimed that – according to the Treaty for the avoidance of double taxation between Indonesia and the United Kingdom – a 20% local tax rate should be applied. Eni has accrued a provision with respect of this proceeding, which covers the full amount claimed by Indonesian Authority.

 

Saipem - Legal proceedings

(i) Court of Third Instance - Consob Decision No. 18949 of June 18, 2014 – claim for damage. With Resolution No. 18949 of June 18, 2014, the Italian Securities and Exchange Commission (Consob) fined Eni’s former subsidiary Saipem euro 80,000 for the alleged delay in the issue of a profit warning, which was published on January 29, 2013. On July 28, 2014, Saipem filed an appeal against this resolution to the Court of Appeal of Milan, but it was rejected by the Court in its ruling of December 11, 2014. Therefore, Eni filed a recourse against the Court of Appeal’s decision to the Italian Third Degree Court. On April 28, 2015, Saipem was served with a notice of a class action before the Court of Milan. The Company was sued by 64 institutional investors, claiming compensation amounting to euro 174 million, for damage allegedly incurred following the purchase of Saipem shares in the period between February 13, 2012 and June 14, 2013. Saipem appeared before a Judge, contesting entirely all the claims. The company objected the inadmissibility of the claims and stated that, in any case, those claims are groundless. The trial is still in the early stages. Besides that, in relation to the alleged delay in giving timely financial information to the market, in 2015, the Company received a number of out-of-court claims, as well as requests for mediation. The requests for which a mediation was sought but not successfully obtained amount to approximately euro 193 million. The Company denied any responsibility in relation to those out-of-court claims and requests for mediation. Up to date, neither the out-of-court claims nor the requests for mediation have turned into legal proceedings.

(ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with alleged international corruption relating to the commission of certain contracts to the former Eni’s subsidiary Saipem in Algeria. 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 Saipem was served a notice of seizure, then a request for documentation and finally a search warrant was issued, in order to acquire further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, who was fired at the beginning of 2013. The Company is collaborating fully with the Prosecutor’s office and rapidly implemented decisive managerial and administrative restructuring measures, irrespective of any liability that might result from the investigations. In agreement with the Board of Statutory Auditors and the Internal Control Bodies, and having duly informed the Prosecutor’s office,

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Saipem is looking into the contracts that are subject to investigation, and to this end has appointed an external legal firm. On July 17, 2013, the Board of Directors analyzed the conclusions reached by the external consultants following an internal investigation carried out in relation to a number of brokerage contracts and subcontracts regarding projects in Algeria. The internal investigation was based on the examination of documents and interviews of personnel from the Company and other companies in the Group, excluding those that, to the best knowledge of the Company, would be directly involved in the criminal investigation, so as not to interfere in the investigative activities of the Prosecutor. The Board, confirming its full cooperation with the investigative authorities, has decided to convey the findings of the external consultants to the Milan Public Prosecutor, for any appropriate assessment and initiative regarding competence in the wider context of the ongoing investigation. The consultants reported to the Board: (i) that they found no evidence of payments to Algerian public officials through the brokerage contractor subcontracts examined; and (ii) that they found violations, deemed detrimental to the interests of the Company, of internal rules and procedures – in force at the time – in relation to the approval and management of brokerage contracts and subcontracts examined and a number of activities in Algeria. On January 14, 2015, the Public Prosecutor of Milan notified the conclusion of preliminary investigations towards Saipem and natural persons. The Public Prosecutor of Milan served the above mentioned persons a notice of investigation for alleged international corruption (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 were also accused of tax offense for fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. On February 5, 2015, the Investigative Tax Police of Milan started a tax audit against Saipem in relation to: (i) the tax implications arising from the pending criminal proceeding with respect to the fiscal years 2008-2010; and (ii) economic transactions with non-EU companies operating in countries considered to be tax heavens for fiscal year 2010. At the end of these verifications, on April 14, 2015, Saipem was notified of a formal notice of assessment which claimed undue deductions of certain expenses for a total amount of about euro 181 million. Saipem submitted its defensive arguments and a request for a dismissal to the Tax Agency - Regional Department of Lombardy - Large Taxpayer Office. On July 9, 2015, the Tax Agency notified to Saipem four assessment notices relating to income taxes, interests and penalties in the amount of about euro 155 million. Saipem will appeal to the Provincial Tax Commission. On October 2, the Judge for the Preliminary Hearing pronounced the following decisions: (i) the sentence of dismissal in regard to all of the accused of the international corruption; and (ii) the decree that requests for trial, among others, for Saipem and its three former employees (the former Deputy Chairman and Managing Director-CEO, the former Chief Operating Officer of the Business Unit Engineering & Construction and the former Chief Financial Officer) with reference to the charge of international corruption formulated by the Public Prosecutor’s Office, according to which the accused were complicit in enabling Saipem to be commissioned seven contracts in Algeria on the basis of criteria of mere favoritism. For the natural persons only (not for Saipem), the indictment was pronounced also with reference to the allegation of fraudulent tax statements brought by the Public Prosecutor’s Office. On February 24, the Court of Third Instance, upholding an appeal presented by the Public Prosecutor of Milan and rejecting the ruling of the Judge for the Preliminary Hearing, ordered to transmit all documents and evidence of the case to another Judge for the Preliminary Hearing in the Court of Milan, so as a new preliminary hearing will be held. Since 2010, investigations have started in Algeria in relation to the commission of the GK3 contract to Saipem by Sonatrach (the so-called “Sonatrach 1” investigation) where the bank accounts of a Saipem’s subsidiary, Saipem Contracting Algérie SpA, have been frozen by the Algerian Authorities with a balance equivalent to about euro 90 million at current exchange rates. In 2012, a notice of investigation was served to Saipem Contracting Algérie SpA. The investigation is concerning alleged price miscalculation in connection with the commission of certain contracts by a governmental entity thanks to the influence of representatives of the managerial body of such entity. 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. On February 2, 2016, the Court of Algiers ordered Saipem Contracting Algérie SpA to pay euro 34,000 fine, in particular for inflating prices on commissioned contracts. Besides that, the sentence granted Saipem’s request to unfreeze its bank accounts in local currency, which have been blocked since 2010 and with a balance of around euro 82 million (amount calculated at the exchange rate of December 31, 2015). All the parties filed an appeal against this first-instance verdict, with except of the Algerian oil company Sonatrach. That is because Sonatrach had reserved the right to claim compensation for damage it allegedly suffered in a separate civil proceeding. However, up to date no such claim has been presented to the civil courts and no compensation has been requested. The filing of appeal suspended Court’s decisions (in particular, the payment of fine and unfreezing of two bank accounts). Furthermore, also the parent company Saipem is being investigated by the Judicial Authority in Algeria for alleged corrupt payments.

(iii) Ongoing investigations - Public Prosecutor’s Office of Milan - Brazil. On August 12, 2015, the Public Prosecutor’s Office of Milan served Saipem SpA with a notice of investigation and a request for documentation in the framework of new criminal proceedings, for the alleged crime of international corruption, initiated by the Court of Milan in relation to a contract awarded in 2011 by the Brazilian company Petrobras to Saipem SA (France) and Saipem do Brasil (Brazil). The investigations are still ongoing and no new notifications have been received from the Public Prosecutor’s Office of Milan. According to what was learned only through the press, this contract is being looked into by the Brazilian Judicial Authorities in relation to a number of Brazilian citizens, including a former

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collaborator of Saipem do Brasil. The Saipem Group has not received any notification in this regard from the Brazilian Judicial Authorities.

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 developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

 

Emission trading
Starting from 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 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 2015, the emissions of carbon dioxide from Eni’s plants were higher than the permits assigned. Against emissions of carbon dioxide amounting to approximately 19.67 million tonnes were assigned to Eni emission permits for a total amount of 6.84 million tonnes, determining a deficit of 12.84 million tonnes. This deficit was entirely offset through acquisitions in the emission market.

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38 Revenues

Net sales from operations

(euro million)		2013		2014		2015

Revenues from sales and services		98,552			93,225			67,744
Change in contract work in progress		(5	)		(38	)		(4	)
		98,547			93,187			67,740

Revenues from sales were stated net of the following items:

(euro million)		2013		2014		2015

Excise taxes		12,650		12,289		11,889
Exchanges of oil sales (excluding excise taxes)		2,018		1,586		1,154
Services recharged to joint venture partners		5,459		5,191		5,609
Sales to service station managers for sales billed to holders of credit cards		1,909		1,804		1,643
		22,036		20,870		20,295

Revenues from sales comprised an estimate revision of revenues accrued on gas sales (euro 346 million) and power sales (euro 138 million) to retail customers in Italy dating back to the past reporting periods.

Net sales from operations by industry segment and geographical area of destination are disclosed in note 44 – Information by industry segment and by geographical area.

Net sales from operations with related parties are disclosed in note 45 – Transactions with related parties.

 

Other income and revenues

(euro million)		2013		2014		2015

Gains from sale of assets		369		90		466
Gains on price adjustments under overlifting/underlifting transactions		44		390		253
Lease and rental income		84		88		83
Contract penalties and other trade revenues		33		36		35
Compensation for damages		40		42		33
Other proceeds (*)		547		393		335
		1,117		1,039		1,205

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

Gains from sale of assets of euro 466 million related for euro 456 million to the Exploration & Production segment.

Other income and revenues with related parties are disclosed in note 45 – Transactions with related parties.

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39 Operating expenses

Purchase, services and other

(euro million)		2013		2014		2015

Production costs - raw, ancillary and consumable materials and goods		62,226			58,655			37,801
Production costs - services		12,044			11,443			12,389
Operating leases and other		2,606			2,635			2,189
Net provisions for contingencies		709			312			634
Other expenses		904			1,349			1,387
		78,489			74,394			54,400
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(305	)		(246	)		(317	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(76	)		(81	)		(100	)
		78,108			74,067			53,983

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 139 million (euro 142 million and euro 134 million in 2013 and 2014, respectively).

Operating leases and other comprised operating leases for euro 635 million (euro 552 million and euro 559 million in 2013 and 2014, respectively) and royalties on the extraction of hydrocarbons for euro 865 million (euro 1,413 million and euro 1,278 million in 2013 and 2014, respectively).

Other expenses of euro 1,387 million (euro 904 million and euro 1,349 million in 2013 and 2014, respectively) included: (i) expenses for changes in selling prices for overlifting and underlifting operations for euro 278 million (euro 50 million and euro 409 million in 2013 and 2014, respectively); (ii) provision to the reserve of allowance for doubtful accounts of trade receivables of the Gas & Power segment for euro 549 million; the provision comprised an estimated loss on accrued revenues gas and electricity for euro 130 million and 96 million, respectively, relating to volumes supplied in previous reporting periods of the Gas & Power retail business; and (iii) losses on disposal of tangible and intangible assets for euro 70 million, of which euro 60 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)		2013		2014		2015

To be paid:
- within 1 year		621		520		493
- between 2 and 5 years		1,042		1,106		1,053
- beyond 5 years		310		724		807
		1,973		2,350		2,353

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 634 million (euro 709 million and euro 312 million in 2013 and 2014, respectively) and mainly related to net provisions for legal proceedings amounting to euro 192 million (net utilizations of euro 44 million and net provisions euro 35 million in 2013 and 2014, respectively) and net provisions for environmental liabilities amounting to euro 217 million (net provisions of euro 121 million and euro 170 million in 2013 and 2014, respectively). More information is provided in note 29 – Provisions for contingencies. Risk provisions net of reversal of unused provisions are disclosed in note 44 – Information by industry segment and by geographical area.

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Payroll and related costs

(euro million)		2013		2014		2015

Wages and salaries		2,112			2,319			2,391
Social security contributions		372			367			378
Cost related to employee benefit plans		62			69			82
Other costs		335			144			166
		2,881			2,899			3,017
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(164	)		(266	)		(193	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(60	)		(61	)		(46	)
		2,657			2,572			2,778

Other costs of euro 166 million (euro 335 million and euro 144 million in 2013 and 2014, respectively) comprised provisions for redundancy incentives of euro 28 million (euro 254 million and euro 5 million in 2013 and 2014, respectively) and costs for defined contribution plans of euro 72 million (euro 69 million and euro 70 million in 2013 and 2014, respectively).

Cost related to employee benefit plans are described in note 30 – Provisions for employee benefits.

 

Average number of employees
The Group average number and breakdown of employees by category is reported below:

(number)		2013		2014		2015

Subsidiaries

Joint operations

Subsidiaries

Joint operations

Subsidiaries

Joint operations

Senior managers		935		35		939		25		936		17
Junior managers		7,795		131		8,026		121		8,224		108
Employees		15,659		806		15,666		595		15,321		379
Workers		4,490		809		4,256		559		3,941		303
		28,879		1,781		28,887		1,300		28,422		807

The above Group average number do not include employees of discontinued operations.

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.

 

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 38 million, euro 43 million and euro 42 million for 2013, 2014 and 2015, respectively, and consisted of the following:

(euro million)		2013		2014		2015

Wages and salaries		25		25		26
Post-employment benefits		2		2		2
Other long-term benefits		11		10		12
Indemnities upon termination of employment				6		2
		38		43		42

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Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 11.4 million, euro 10.1 million and euro 6.7 million for 2013, 2014 and 2015, respectively. Compensation of Statutory Auditors amounted to euro 0.474 million, euro 0.419 million and euro 0.551 million in 2013, 2014 and 2015, 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 (expense)
The analysis of net income (loss) on commodity derivatives was as follows:

(euro million)		2013		2014		2015

Net income (loss) on cash flow hedging derivatives		25			(133	)		2
Net income (loss) on other derivatives		(96	)		278			(487	)
		(71	)		145			(485	)

Net income (loss) on cash flow hedging derivatives related to the ineffective portion of the hedging relationship on commodity derivatives which was recognized through profit and loss in the Gas & Power segment.

Net income (loss) on other derivatives included: (i) the fair value measurement and settlement of commodity derivatives for trading purposes and proprietary trading amounting to a net loss of euro 657 million (net loss of euro 8 million in 2013 and net income of euro 27 million in 2014); (ii) the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk amounting to a net income of euro 186 million (net loss of euro 91 million in 2013 and net income of euro 220 million in 2014); and (iii) the fair value evaluation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts of the Exploration & Production segment amounting to a net loss of euro 16 million (net income of euro 3 million in 2013 and net income of euro 31 million in 2014).

Operating expenses with related parties are reported in note 45 – Transactions with related parties.

 

Depreciation, depletion, amortization and impairments

(euro million)		2013		2014		2015

Depreciation, depletion and amortization:
- tangible assets		6,652			7,368			8,482
- intangible assets		1,962			1,772			1,181
		8,614			9,140			9,663
Impairments:
- tangible assets		2,061			1,022			4,668
- intangible assets		507			53			161
		2,568			1,075			4,829
less:
- reversal of impairments - tangible assets		(212	)		(62	)		(3	)
- capitalized direct costs associated with self-constructed assets - tangible assets		(3	)		(2	)		(2	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(6	)		(4	)		(7	)
		10,961			10,147			14,480

Depreciation, depletion, amortization and impairments by industry segment are disclosed in note 44 – Information by industry segment and by geographical area.

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40 Finance income (expense)

(euro million)		2013		2014		2015

Finance income (expense)
Finance income		5,030			5,672			8,576
Finance expense		(5,941	)		(7,042	)		(10,062	)
Net finance income from financial assets held for trading		4			24			3
		(907	)		(1,346	)		(1,483	)
Income (expense) from derivative financial instruments		(92	)		165			160
		(999	)		(1,181	)		(1,323	)

The breakdown by lenders or type of net finance income or expense is provided below:

(euro million)		2013		2014		2015

Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(742	)		(759	)		(740	)
Interest due to banks and other financial institutions		(145	)		(112	)		(98	)
Interest and other income from financial receivables and securities held for non-operating purposes		36			26			2
Interest from banks		39			19			19
Net finance income from financial assets held for trading		4			24			3
		(808	)		(802	)		(814	)
Exchange differences
Positive exchange differences		4,803			5,407			8,352
Negative exchange differences		(4,779	)		(5,815	)		(8,703	)
		24			(408	)		(351	)
Other finance income (expense)
Capitalized finance expense		166			157			159
Interest and other income on financing receivables and securities held for operating purposes		61			74			109
Finance expense due to the passage of time (accretion discount) (a)		(240	)		(292	)		(291	)
Other finance (expense)		(110	)		(75	)		(295	)
		(123	)		(136	)		(318	)
		(907	)		(1,346	)		(1,483	)

Finance income (loss) on derivative financial instruments consisted of the following:

(euro million)		2013		2014		2015

Options		(41	)		68		33
Derivatives on exchange rate		(91	)		51		96
Derivatives on interest rate		40			46		31
		(92	)		165		160

Net income from derivatives of euro 160 million (net loss of euro 92 million and net income of euro 165 million in 2013 and 2014, respectively) was recognized in connection with fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. The lack of formal requirements to qualify these derivatives as 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.

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Income on options of euro 33 million (net loss of euro 41 million in 2013 and income of euro 68 million in 2014) related to the measurement at fair value of the options embedded in the bond convertible into ordinary shares of Snam SpA (loss of euro 55 million in 2013 and income of euro 23 million in 2014) following to the reduction of the liability outstanding at 2014 as consequence of the exercise by the bondholders of their option rights on approximately 6% of the shares of Snam and the progression to maturity of the options on approximately 2% of the shares retained by Eni as of December 31, 2015. The measurement at fair value of the options embedded in the bond convertible into ordinary shares of Galp Energia SGPS SA had no effect on earnings (income of euro 14 million in 2013 and euro 45 million 2014); the bond was fully repaid during 2015. More information is provided in note 28 – Long-term debt and current portion of long-term debt.

More information is provided in note 45 – Transactions with related parties.

41 Income (expense) from investments

Share of profit (loss) of equity-accounted investments

(euro million)		2013		2014		2015

Share of profit from equity-accounted investments		294			188			146
Share of loss from equity-accounted investments		(84	)		(79	)		(591	)
Decreases (increases) in the provision for losses on investments		10			(5	)		(7	)
		220			104			(452	)

More information is provided in note 19 – Investments.

Share of profit (loss) of equity accounted investments by industry segment is disclosed in note 44 – Information by industry segment and by geographical area.

 

Other gain (loss) from investments

(euro million)		2013		2014		2015

Dividends		400		384			402
Net gains on disposals		3,598		160			164
Other net income (expense)		1,865		(179	)		10
		5,863		365			576

In 2015, dividend income for euro 402 million primarily related to Nigeria LNG Ltd for euro 222 million, Snam SpA for euro 72 million and Galp Energia SGPS SA for euro 21 million. In 2014, dividend income for euro 384 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 2015, net gains on disposals amounting to euro 164 million related to: (i) a gain of euro 98 million for the sale of 8% stake in Galp Energia SGPS SA; (ii) a gain of euro 46 million for the sale of 6.03% stake in Snam SpA; (iii) a gain of euro 32 million for the sale of 100% stake in Ceská Republika Sro; (iv) a gain of euro 31 million for the sale of 100% stake of Eni Romania Srl; (v) a gain of euro 6 million for the sale of 32.445% stake (entire stake own) in Ceská Rafinérská AS (CRC); (vi) a gain of euro 1 million of 100% stake in Eni Slovensko Spol Sro; and (vii) a loss of euro 47 million for the sale of a 76% stake in Inversora de Gas Cuyana SA (entire stake owned), a 6.84% stake in Distribudora de Gas Cuyana SA (entire stake owned), a 25% stake in Inversora de Gas del Centro SA (entire stake owned) and a 31.35% stake in Distribudora de Gas del Centro SA (entire stake owned).

In 2014, net gains on disposals amounting to euro 160 million related to: (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

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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.

In 2013, net gains on disposals amounting 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.

In 2015, other net income of euro 10 million included: (i) a gain on the remeasurement at market fair value of 77.7 million shares of Snam SpA for euro 49 million to which the fair value option was applied as provided for by IAS 39; (ii) a reversal of unutilized provision for losses on investments of euro 10 million relating to Caspian Pipeline Consortium R - Closed Joint Stock Co; and (iii) an impairment for euro 49 million relating to Union Fenosa Gas SA. In 2014, other net expense of euro 179 million included the remeasurement at market fair value at the balance sheet date of 66.3 million shares of Galp Energia SGPS SA (loss for 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 remeasurement at fair value recorded to profit amounted to euro 1,682 million. The consideration for the disposal was cashed in January 2014; and (ii) the remeasurement at market fair value of 288.7 million shares of Snam SpA and of 66.3 million shares 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).

More information is provided in note 19 – Investments.

42 Income taxes

(euro million)		2013		2014		2015

Current taxes:
- Italian subsidiaries		827			(566	)		160
- subsidiaries of the Exploration & Production segment - outside Italy		7,602			6,512			4,015
- other subsidiaries - outside Italy		97			114			211
		8,526			6,060			4,386
Net deferred taxes:
Italian subsidiaries		(33	)		511			628
- subsidiaries of the Exploration & Production segment - outside Italy		756			128			(1,844	)
- other subsidiaries - outside Italy		(194	)		(18	)		(23	)
		529			621			(1,239	)
		9,055			6,681			3,147

Income taxes currently payable by Italian subsidiaries amounted to euro 160 million and were in respect of the Italian corporate taxation (IRES for euro 12 million and IRAP for euro 31 million) and foreign taxes on the share of profit earned outside Italy for euro 117 million.

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The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 27.5% (38.0% and 27.5% in 2013 and in 2014, respectively) and the effective tax charge is the following:

(euro million)		2013		2014		2015

Profit (loss) before taxation		12,951			6,873			(3,980	)
Tax rate (IRES) (%)		38.0			27.5			27.5
Statutory corporation tax charge (credit) on profit or loss		4,921			1,890			(1,095	)
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy		2,606			4,064			2,767
- impact pursuant to the write-off of deferred tax assets and recalculation of tax rates		1,244			1,002			834
- allowance for doubtful accounts and revision of revenues accrued on gas and power sales relating to past periods								227
- effect due to the tax regime provided for intercompany dividends		108			51			114
- Italian regional income tax (IRAP)		10			5			105
- effect due to non-taxable gains/losses on sales		(1,063	)		25			(39	)
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law No. 7/2009					(825	)
- impact pursuant to the application of the Italian Windfall Corporate tax as per Law No. 7/2009		185
- effect due to discontinued operations		674			496			148
- permanent differences and other adjustments		370			(27	)		86
		4,134			4,791			4,242
Effective tax charge		9,055			6,681			3,147

In 2015, the higher tax charges at non-Italian subsidiaries of euro 2,767 million related to the Exploration & Production segment for euro 2,699 million, including a write-off of deferred tax assets due to a reduced profitability outlook of euro 1,058 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of euro 834 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit for euro 311 million and to a reduction due to a change in the statutory tax rate from 27.5% to 24%, which was considered substantially enacted at the reporting date, for euro 523 million. The effect due to the Italian regional income tax (IRAP) of euro 105 million included a write-off at deferred tax assets due to projections of lower future taxable profit for euro 54 million.

In 2014, the higher tax charges at non-Italian subsidiaries of euro 4,064 million essentially related to the Exploration & Production segment. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of euro 1,002 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit for euro 526 million and to a lower prospective tax rate in relation to the windfall tax (the so-called Robin Tax) provided by Article 81 of the Legislative Decree No. 112/2008 which was assessed to be no more recoverable as, in February 2015, by the Italian Court for euro 476 million. Such sentence stated the illegitimacy of a tax rule prospectively, denying any reimbursement right.

In 2013, the higher tax charges at non-Italian subsidiaries of euro 2,606 million essentially related to the Exploration & Production segment. The effect due to non-taxable losses on sales of euro 1,063 million related to the transactions of the 28.57% at Eni East Africa SpA for euro 917 million and non-taxable gains on sale and revaluation relating to the transactions at Galp Energia SGPS SA and Snam SpA for euro 123 million. Permanent differences and other adjustments of euro 370 million related to a non-deductible impairment of the goodwill allocated to the European gas market CGU for euro 135 million.

 

 

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Income tax expense related to discontinued operations, included in the item "Net profit (loss)" of the profit and loss account, consisted of the following:

(euro million)		2013		2014		2015

Current taxes:
- Italian subsidiaries		(21	)		25			4
- Foreign subsidiaries		215			199			339
		194			224			343
Net deferred taxes:
- Italian subsidiaries		(165	)		(197	)		233
- Foreign subsidiaries		(79	)		(216	)		(5	)
		(244	)		(413	)		228
		(50	)		(189	)		571

43 Earnings per share

		2013		2014		2015

Average number of shares used for the calculation of the basic and diluted earnings per share				3,622,797,043		3,610,387,582		3,601,140,133
Eni’s net profit		(euro million)		5,160		1,291		(8,783	)
Basic and diluted earning (loss) per share		(euro per share)		1.42		0.36		(2.44	)
Eni’s net profit - Continuing operations		(euro million)		3,472		101		(7,680	)
Basic and diluted earning (loss) per share		(euro per share)		0.96		0.03		(2.13	)
Eni’s net profit - Discontinued operations		(euro million)		1,688		1,190		(1,103	)
Basic and diluted earning (loss) per share		(euro per share)		0.46		0.33		(0.31	)

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, 2013, 2014 and 2015 was 3,622,797,043, 3,610,387,582 and 3,601,140,133, respectively.

There were no pending issues of new shares that could dilute earnings at the reporting date.

44 Information by industry segment and by geographical area

Information by industry segment
Eni’s segmental reporting is established on the basis of the Group’s operating segments that are evaluated regularly by the chief operating decision maker (the CEO) in deciding how to allocate resources and in assessing performance.

Effective January 1, 2015, Eni’s segment information was modified to align Eni’s reportable segments to certain changes in the organization and in profit accountability defined by Eni’s top management. The main changes adopted compared to the previous setup of the segment information related to:
•		results of the oil and products trading activities and related risk management activities were transferred to the Gas & Power segment, consistently with the new organizational setup. In previous reporting periods, results of those activities were reported within the Refining & Marketing segment as part of a reporting structure which highlighted results for each stream of commodities. In 2014, this activity reported net sales from operations of approximately euro 50 billion and an operating loss of euro 122 million;
•		Refining & Marketing and Versalis operating segments are now combined into a single reportable segment because a single manager is accountable for both segments and they show similar long-term economic performance; and
•		the previous reporting segments "Corporate and financial companies" and "Other activities" have been combined being residual components of the Group, in order to reduce the number of reportable segments in line with the segmental reporting of the comparable oil&gas players.

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The segmental financial information reported to the CEO comprises segment revenues, operating profit, as well as segmental assets and liabilities, which are reviewed only on occasion of the statutory reports (the annual and the interim reports).

As result of the disposal plans underway at the reporting date, the Chemical business managed by Versalis (Eni 100%), previously combined in a single reportable segment with Refining & Marketing and the Engineering & Construction segment managed by Saipem (Eni’s interest 42.9%) have been classified as discontinued operations. Prior period results have been restated consequently (see note 1 – Principles of consolidation).

As of December 31, 2015, Eni’s reportable segments have been regrouped as follows:

•		Exploration & Production: is engaged in exploring for and recovering crude oil and natural gas, including participation to projects for the liquefaction of natural gas;
•		Gas & Power: is engaged in supply and marketing of natural gas at wholesale and retail markets, supply and marketing of LNG and supply, production and marketing of power at retail and wholesale markets. Gas & Power is engaged in supply and marketing of crude oil and oil products targeting the operational requirements of Eni’s refining business and in commodity trading (including crude oil, natural gas, oil products, power, emission allowances, etc.) targeting to both hedge and stabilize the Group industrial and commercial margins according to an integrated view and to optimize margins.
•		Refining & Marketing: is engaged in manufacturing, supply and distribution and marketing activities for oil products.
•		Corporate and other activities: represents the key support functions, comprising holdings and treasury, headquarters, central functions like IT, HR, real estate, self-insurance activities, as well as the Group environmental clean-up and remediation activities performed by the subsidiary Syndial.

The comparative reporting periods of this press release have been restated consistently with the new segmental reporting adopted by the Eni and the discontinued operations.

As reported in 2013 and 2014

(euro million)

Exploration & Production

Gas & Power

Refining & Marketing

Versalis

Engineering & Construction

Corporate and financial companies

Other activities

Intragroup eliminations

Intragroup profits

Total

2013
Net sales from operations (a)		31,264			32,212			57,238			5,859			11,598			1,453			80			18			(25,025	)		114,697
Operating profit		14,868			(2,967	)		(1,492	)		(725	)		(98	)		(399	)		(337	)		38						8,888
Identifiable assets		59,784			18,205			15,013			3,169			14,208			968			255			(793	)					110,809
2014
Net sales from operations (a)		28,488			28,250			56,153			5,284			12,873			1,378			78			54			(22,711	)		109,847
Operating profit		10,766			186			(2,229	)		(704	)		18			(246	)		(272	)		398						7,917
Identifiable assets		68,113			16,603			12,993			3,059			14,210			1,042			258			(486	)					115,792

As restated

		Discontinued operations		Discontinued operations

(euro million)

Exploration & Production

Gas & Power

Refining & Marketing

Chemical

Engineering & Construction

Corporate and Other activities

Intragroup profits

Intragroup eliminations

Total

Engineering & Construction

Intragroup eliminations

Chemical

Intragroup eliminations

Continuing operations

2013
Net sales from operations (a)		31,264		79,619			27,201			5,859			11,598			1,496			18			(42,358	)		114,697		(11,598	)		1,018		(5,859	)		289			98,547
Operating profit		14,868		(2,923	)		(1,534	)		(727	)		(98	)		(736	)		38						8,888		98			890		727			(2,736	)		7,867
Identifiable assets		59,784		20,500			12,718			3,169			14,208			1,223			(793	)					110,809
2014
Net sales from operations (a)		28,488		73,434			24,330			5,284			12,873			1,429			54			(36,045	)		109,847		(12,873	)		1,244		(5,284	)		253			93,187
Operating profit		10,766		64			(2,107	)		(704	)		18			(518	)		398						7,917		(18	)		1,105		704			(2,123	)		7,585
Identifiable assets		68,113		19,342			10,254			3,059			14,210			1,300			(486	)					115,792

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The information by the new segmental reporting is the following:

		Other activities		Discontinued operations

(euro million)

Exploration & Production

Gas & Power

Refining & Marketing

Chemical

Engineering & Construction

Corporate and Other activities

Intragroup profits

Total

Engineering & Construction

Intragroup eliminations

Chemical

Intragroup eliminations

Continuing operations

2013
Net sales from operations (a)		31,264			79,619			27,201			5,859			11,598			1,496			18
Less: intersegment sales		(18,218	)		(18,143	)		(3,349	)		(289	)		(1,018	)		(1,341	)
Net sales to customers		13,046			61,476			23,852			5,570			10,580			155			18			114,697			(10,580	)					(5,570	)					98,547
Operating profit		14,868			(2,923	)		(1,534	)		(727	)		(98	)		(736	)		38			8,888			98			890			727			(2,736	)		7,867
Provisions for contingencies		61			314			100			65			76			255			(21	)		850			(76	)					(65	)					709
Depreciation, amortization and impairments		7,829			2,098			978			139			721			81			(25	)		11,821			(721	)					(139	)					10,961
Share of profit (loss) of equity-accounted investments		129			71			5						2			15						222			(2	)											220
Identifiable assets (b)		59,784			20,500			12,718			3,169			14,208			1,223			(793	)		110,809
Unallocated assets																							27,532
Equity-accounted investments		1,730			999			74			148			166			36						3,153
Identifiable liabilities (c)		15,608			12,577			3,684			844			5,517			4,346			(86	)		42,490
Unallocated liabilities																							34,802
Capital expenditure		10,475			229			672			314			902			211			(3	)		12,800
2014
Net sales from operations (a)		28,488			73,434			24,330			5,284			12,873			1,429			54
Less: intersegment sales		(16,618	)		(14,251	)		(2,409	)		(253	)		(1,244	)		(1,270	)
Net sales to customers		11,870			59,183			21,921			5,031			11,629			159			54			109,847			(11,629	)					(5,031	)					93,187
Operating profit		10,766			64			(2,107	)		(704	)		18			(518	)		398			7,917			(18	)		1,105			704			(2,123	)		7,585
Provisions for contingencies		29			(26	)		124			28			154			188			(3	)		494			(154	)					(28	)					312
Depreciation, amortization and impairments		9,163			360			566			195			1,157			84			(26	)		11,499			(1,157	)					(195	)					10,147
Share of profit (loss) of equity-accounted investments		52			42			8			(4	)		21			2						121			(21	)					4						104
Identifiable assets (b)		68,113			19,342			10,254			3,059			14,210			1,300			(486	)		115,792
Unallocated assets																							30,415
Equity-accounted investments		1,959			772			73			155			120			36						3,115
Identifiable liabilities (c)		19,152			12,141			3,395			698			6,171			3,903			(165	)		45,295
Unallocated liabilities																							38,703
Capital expenditure		10,524			172			537			282			694			113			(82	)		12,240
2015
Net sales from operations (a)		21,436			52,096			18,458			4,717			11,507			1,468
Less: intersegment sales		(12,115	)		(9,917	)		(2,372	)		(171	)		(1,243	)		(1,314	)
Net sales to customers		9,321			42,179			16,086			4,546			10,264			154						82,550			(10,264	)					(4,546	)					67,740
Operating profit		(144	)		(1,258	)		(552	)		(1,393	)		(694	)		(497	)		(23	)		(4,561	)		694			1,228			1,393			(1,535	)		(2,781	)
Provisions for contingencies		221			41			138			10			104			226			8			748			(104	)					(10	)					634
Depreciation, amortization and impairments		13,404			515			498			1,484			1,208			91			(28	)		17,172			(1,208	)					(1,484	)					14,480
Share of profit (loss) of equity-accounted investments		(447	)		(2	)					(3	)		17			(3	)					(438	)		(17	)					3						(452	)
Identifiable assets (b)		68,640			14,290			8,743			1,362			13,608			1,117			(543	)		107,217
Unallocated assets																							27,575
Equity-accounted investments		1,821			690			72			188			134			36						2,941			(134	)					(188	)					2,619
Identifiable liabilities (c)		17,742			9,313			3,121			536			5,861			3,824			(199	)		40,198
Unallocated liabilities																							40,925
Capital expenditure		10,234			154			408			220			561			64			(85	)		11,556

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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

2013
Identifiable assets (a)		28,619		14,513		7,992		8,683		17,921		31,300		1,781		110,809
Capital expendituresin 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
2015
Identifiable assets (a)		20,933		12,081		7,725		7,349		21,774		35,896		1,459		107,217
Capital expenditures in tangible and intangible assets		1,348		729		1,173		752		2,382		5,114		58		11,556

Sales from operations by geographical area of destination

(euro million)		2013		2014		2015

Italy		29,049		26,921		22,366
Other European Union		28,966		27,112		18,637
Rest of Europe		10,849		11,729		6,934
Americas		5,259		5,658		4,156
Asia		13,886		12,683		8,936
Africa		9,990		8,776		6,470
Other areas		548		308		241
		98,547		93,187		67,740

45 Transactions with related parties In the ordinary course of its business Eni enters into transactions regarding:

(a)		exchange of goods, provision of services and financing with joint ventures, associates and non consolidated subsidiaries;
(b)		exchange of goods and provision of services with entities controlled by the Italian Government;
(c)		relations with Vodafone 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 mainly involve costs for mobile communication services for euro 17 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.

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, are related to the ordinary course of Eni’s business.

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Trade and other transactions with related parties

(euro million)		Dec. 31, 2013		2013

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
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		42		16		6,122
EnBW Eni Verwaltungsgesellschaft mbH		33												165		1
InAgip doo		57		22						63						6
Karachaganak Petroleum Operating BV		26		220				1,218		275		4				19
KWANDA - Suporte Logistico Lda		55		5
Mellitah Oil & Gas BV		7		61				16		215						3
Petrobel Belayim Petroleum Co		32		360						570						1
Petromar Lda		71		7		29
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		228		5		150		46		8
		607		1,109		6,226		1,313		1,484		41		586		79		9
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		115		153						506		16				52		4
Eni BTC Ltd						147
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		62		1		10										2
Other (*)		14		56		2		6		11		4		6		7		1
		191		210		159		6		517		20		6		61		5
		798		1,319		6,385		1,319		2,001		61		592		140		14
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		40		1
Terna Group		43		58				124		149		13		118		35		2		19
GSE - Gestore Servizi Energetici		86		135				811				96		265		21		9
Other (*)		47		70				7		88		4		48		4
		647		856		13		982		3,123		117		1,301		209		14		68
Pension funds and foundations				2						4		48
		1,445		2,177		6,398		2,301		5,128		226		1,893		349		28		68
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due										127						168
CEPAV (Consorzio Eni per l’Alta Velocità) Uno										2						44
InAgip doo																28
KWANDA - Suporte Logistico Lda										2		1				6
Petrobel Belayim Petroleum Co																46
Petromar Lda										6		1				69
Other (*)										86		2				34		1
										223		4				395		1
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV																489
Other (*)										34				7		1		4
										34				7		490		4
Entities controlled by the Government
Snam Group																47
Terna Group																3
Other (*)										19
										19						50
Pension funds and foundations												3
										276		7		7		935		5
		1,445		2,177		6,398		2,301		5,404		233		1,900		1,284		33		68

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(euro million)		Dec. 31, 2014		2014

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		2		60						169
CEPAV (Consorzio Eni per l’Alta Velocità) Due		120		152
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		23		12		6,122
EnBW Eni Verwaltungsgesellschaft mbH														134		2
InAgip doo		52		11						44				1		7
Karachaganak Petroleum Operating BV		43		233				1,246		320		22				20
KWANDA - Suporte Logistico Lda		68		15
Mellitah Oil & Gas BV		98		58				10		235						7
Petrobel Belayim Petroleum Co		32		375						603						2
Petromar Lda		93		4		21
South Stream Transport BV																		1
Unión Fenosa Gas Comercializadora SA		15		1										157
Unión Fenosa Gas SA						57				1		1
Other (*)		122		67				17		85		6		90		56		10
		668		988		6,200		1,273		1,457		29		382		94		11
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV										342		7				32		2
Eni BTC Ltd						167
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		61		1		10										3
Other (*)		13		52		1				11				4		2		4
		74		53		178				353		7		4		37		6
		742		1,041		6,378		1,273		1,810		36		386		131		17
Entities controlled by the Government
Enel Group		156		122						933				181		133		1		183
Snam Group		147		585		7		155		1,867		5		235		33				13
Terna Group		33		65				89		154		7		120		31		44		12
GSE - Gestore Servizi Energetici		88		124				580		2		60		172		14
Other (*)		44		93				8		86		3		45		2		1
		468		989		7		832		3,042		75		753		213		46		208
Pension funds and foundations				2						4		60
		1,210		2,032		6,385		2,105		4,856		171		1,139		344		63		208
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due										159						216
CEPAV (Consorzio Eni per l’Alta Velocità) Uno										3						14
KWANDA - Suporte Logistico Lda										10						9
Petrobel Belayim Petroleum Co																83
Petromar Lda										1		1				61
South Stream Transport BV																495
Other (*)										97		12		5		36		5
										270		13		5		914		5
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV																155
Other (*)										2
										2						155
Entities controlled by the Government
Snam Group																39
Terna Group																4
Other (*)										25						4		1
										25						47		1
Pension funds and foundations												1
										297		14		5		1,116		6
		1,210		2,032		6,385		2,105		5,153		185		1,144		1,460		69		208

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(euro million)		Dec. 31, 2015		2015

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		6		60						187
CEPAV (Consorzio Eni per l’Alta Velocità) Due				1
CEPAV (Consorzio Eni per l’Alta Velocità) Uno						6,122
Karachaganak Petroleum Operating BV		48		171				748		403		8				10
Mellitah Oil & Gas BV		8		16				46		339						19
Petrobel Belayim Petroleum Co		16		183						543
Petromar Lda		2				6
Unión Fenosa Gas SA		1				57														(4	)
Other (*)		93		16				27		70		1		52		63		13		(2	)
		174		447		6,185		821		1,542		9		52		92		13		(6	)
Unconsolidated entitiescontrolled by Eni
Eni México S. de RL de CV						101
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		65		1		9										3
Other (*)		10		19		3		2		2				4		2		2
		75		20		113		2		2				4		5		2
		249		467		6,298		823		1,544		9		56		97		15		(6	)
Entities controlled by the Government
Enel Group		138		203						1,063				196		134				90
Snam Group		144		522		3		137		2,014		5		249		24		1
Terna Group		18		42				109		125		14		77		15		29		12
GSE - Gestore Servizi Energetici		44		63				419		5		35		307		43
Other (*)		22		36						44		6		29		1
		366		866		3		665		3,251		60		858		217		30		102
Pension funds and foundations		1		2						4		50
Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»		185		300						453		12		35		60
		801		1,635		6,301		1,488		5,252		131		949		374		45		96
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due		60		99		68				101						145
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		9		3						3						1
KWANDA - Suporte Logistico Lda		69		10								5				8
Mellitah Oil & Gas BV		9								7
Petrobel Belayim Petroleum Co		19														86
Petromar Lda		97		16						16						45
Other (*)		39		53				10		108				9		28		25
		302		181		68		10		235		5		9		313		25
Unconsolidated entities controlled by Eni
Other (*)		8		1						2
		8		1						2
Entities controlled by the Government
Snam Group		25		46												36
Terna Group																4
Other (*)				7						15
		25		53						15						40
Pension funds and foundations												1
		335		235		68		10		252		6		9		353		25
		1,136		1,870		6,369		1,498		5,504		137		958		727		70		96

Most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

•		provision of specialized services in upstream activities and Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach - Agip «GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for Karachaganak Petroleum Operating BV, purchase of oil products by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs;
•		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;

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•		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;
•		planning, construction and technical assistance 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;
•		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;
•		guarantees given on behalf of Eni México S. de RL de CV covering the minimum work plan provided at the auction; 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 with Snam Group on the basis of tariffs set by Italian Regulatory Authority for Electricity, Gas and Water and purchase and sale of natural gas for granting the balancing of the system on the basis of prices referred to the quotations of the main energy commodities, as they would be conducted on an arm’s length basis;
•		sale and purchase of electricity, the acquisition of domestic electricity transmission service on the basis of prices referred to the quotations of the main energy commodities, as they would be conducted on an arm’s length basis 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 and sale of oil products with GSE - Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/2012.

Transactions with pension funds and foundation concerned:

•		provisions to pension funds for euro 44 million; and
•		contributions to Eni Foundation for euro 6 million and to Eni Enrico Mattei Foundation for euro 5 million.

Financing transactions with related parties

(euro million)		Dec. 31, 2013		2013

Name		Receivables		Payables		Guarantees		Charges		Gains

Continuing operations
Joint ventures and associates
CARDÓN IV SA		236								10
CEPAV (Consorzio Eni per l’Alta Velocità) Due						150
Matrìca SpA		100
Shatskmorneftegaz Sarl		51						13
Société Centrale Electrique du Congo SA		74				5
Unión Fenosa Gas SA				120
Other (*)		281		86		15		72		19
		742		206		170		85		29
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		33
Discontinued operations
Joint ventures and associates
Matrìca SpA										4
Other (*)										4
										8
		801		264		171		85		41

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(euro million)		Dec. 31, 2014		2014

Name		Receivables		Payables		Guarantees		Charges		Gains

Continuing operations
Joint ventures and associates
CARDÓN IV SA		621								29
CEPAV (Consorzio Eni per l’Alta Velocità) Due						150				6
Matrìca SpA		200
Société Centrale Electrique du Congo SA		84				2
Unión Fenosa Gas SA				90
Other (*)		84		13		19		55		4
		989		103		171		55		39
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		41
Discontinued operations
Joint ventures and associates
Matrìca SpA										5
										5
		1,057		181		173		55		46

 

(euro million)		Dec. 31, 2015		2015

Name		Receivables		Payables		Guarantees		Charges		Gains

Continuing operations
Joint ventures and associates
CARDÓN IV SA		1,112								65
Société Centrale Electrique du Congo SA		94
Unión Fenosa Gas SA				90
Other (*)		77		7		12		54		5
		1,283		97		12		54		70
Unconsolidated entities controlled by Eni
Other (*)		51		111						1
		51		111						1
Entities controlled by the Government
Other (*)		27								1
		27								1
		1,361		208		12		54		72
Discontinued operations
Joint ventures and associates
Matrìca SpA		219								11
CEPAV (Consorzio Eni per l’Alta Velocità) Due						150
Other (*)		5
		224				150				11
		1,585		208		162		54		83

Most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

•		financing loans granted to CARDÓN IV SA for the exploration and development activities of a gas field in Venezuela and to Société Centrale Electrique du Congo SA for the construction of an electric plant in Congo;
•		bank debt guarantees issued on behalf of CEPAV (Consorzio Eni per l’Alta Velocità) Due;

F-113

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•		financing loans granted to Matrìca SpA in relation to the "Green Chemistry" project at the Porto Torres plant; and
•		a cash deposit at Eni’s financial companies on behalf of Unión Fenosa Gas SA.

 

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, 2014		Dec. 31, 2015

(euro million)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Trade and other receivables		28,601		1,973		6.90		20,950		1,944		9.28
Other current assets		4,385		43		0.98		3,639		50		1.37
Other non-current financial assets		1,022		239		23.39		788		158		20.05
Other non-current assets		2,773		12		0.43		1,757		10		0.57
Discontinued operations and assets held for sale		456						17,516		559		3.19
Current financial liabilities		2,716		181		6.66		5,712		208		3.64
Trade and other payables		23,703		1,954		8.24		14,615		1,521		10.41
Other current liabilities		4,489		58		1.29		4,703		91		1.93
Other non-current liabilities		2,285		20		0.88		1,852		23		1.24
Discontinued operations and liabilities directly associated to assets held for sale		165						7,070		235		3.32

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

		2013		2014		2015

(euro million)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Continuing operations
Net sales from operations		98,547			2,242			2.28		93,187			1,483			1.59		67,740			1,323			1.95
Other income and revenues		1,117			28			2.51		1,039			63			6.06		1,205			45			3.73
Purchases, services and other		78,108			7,617			9.75		74,067			7,072			9.55		53,983			6,816			12.63
Payroll and related costs		2,657			38			1.43		2,572			60			2.33		2,778			55			1.98
Other operating
income (expense)		(71	)		68			..		145			208			..		(485	)		96			..
Financial income		5,030			33			0.66		5,672			41			0.72		8,576			72			0.84
Financial expense		(5,941	)		(85	)		1.43		(7,042	)		(55	)		0.78		(10,062	)		(54	)		0.54
Discontinued operations
Net sales from operations		16,420			947			5.77		16,722			1,127			6.74		14,880			387			2.60
Operating expenses		15,399			283			1.84		16,390			311			1.90		16,660			268			1.61
Income (expense) from investments		(10	)		8			..		116			5			4.31		73			11			15.07

 

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Main cash flows with related parties are provided below:

(euro million)		2013		2014		2015

Revenues and other income		2,270			1,546			1,368
Costs and other expenses		(6,448	)		(5,951	)		(5,720	)
Other operating income (loss)		68			208			96
Net change in trade and other receivables and liabilities		557			164			126
Net interests		32			41			71
Net cash provided from operating activities - Continuing operations		(3,521	)		(3,992	)		(4,059	)
Net cash provided from operating activities - Discontinued operations		610			789			93
Net cash provided from operating activities		(2,911	)		(3,203	)		(3,966	)
Capital expenditure in tangible and intangible assets		(1,207	)		(1,181	)		(1,151	)
Net change in accounts payable and receivable in relation to investments		(13	)		(114	)		(238	)
Change in financial receivables		830			(163	)		(194	)
Net cash used in investing activities		(390	)		(1,458	)		(1,583	)
Change in financial liabilities		119			(99	)		13
Net cash used in financing activities		119			(99	)		13
Total financial flows to related parties		(3,182	)		(4,760	)		(5,536	)

The impact of cash flows with related parties consisted of the following:

		2013		2014		2015

(euro million)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Cash provided from operating activities		11,026			(2,911	)		..		15,110			(3,203	)		..		11,903			(3,966	)		..
Cash used in investing activities		(10,981	)		(390	)		3.55		(8,943	)		(1,458	)		16.30		(11,177	)		(1,583	)		14.16
Cash used in financing activities		(2,510	)		119			..		(5,062	)		(99	)		1.96		(1,351	)		13			..

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46 Other information about investments

Information on Eni’s investments as of December 31, 2015
The following section provides the information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2015. 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 (in liquidation)

San Donato Milanese (MI)

Italy

EUR

120,000

Eni SpA

100.00

Co.

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 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 (in liquidation)

Nicosia (Cyprus)

Cyprus

EUR

1,710

Burren En. (Berm) Ltd

100.00

Co.

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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 (in liquidation)

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 (in liquidation)

Nicosia (Cyprus)

Cyprus

EUR

3,420

Burren (Cyp) Hold. Ltd Burren En. (Berm) Ltd

50.00 50.00

Co.

Burren Energy Shipping and Transportation Ltd (in liquidation)

Nicosia (Cyprus)

Cyprus

EUR

3,420

Burren (Cyp) Hold. Ltd 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.

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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

2,004

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

Rio de Janeiro (Brazil)

Brazil

BRL

1,593,415,000

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

13,132,000,000

Eni International BV Third parties

99.98 0.02

99.98

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

London (United Kingdom)

Ivory Coast

GBP

1

Eni UK Ltd

100.00

100.00

F.C.

Eni JPDA 03-13 Ltd

London (United Kingdom)

Australia

GBP

250,000

Eni International BV

100.00

100.00

F.C.

Eni JPDA 06-105 Pty Ltd

Perth (Australia)

Australia

AUD

80,830,576

Eni International BV

100.00

100.00

F.C.

Eni JPDA 11-106 BV

Amsterdam (Netherlands)

Australia

EUR

50,000

Eni International BV

100.00

100.00

F.C.

Eni Kenya BV

Amsterdam (Netherlands)

Kenya

EUR

20,000

Eni International BV

100.00

100.00

F.C.

Eni Krueng Mane Ltd

London (United Kingdom)

Indonesia

GBP

2

Eni Indonesia Ltd

100.00

100.00

F.C.

Eni Lasmo Plc

London (United Kingdom)

United Kingdom

GBP

337,638,724.25

Eni Investments Plc Eni UK Ltd

99.99 (..)

100.00

F.C.

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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 Montenegro BV

Amsterdam (Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Eni Mozambique Engineering Ltd

London (United Kingdom)

United Kingdom

GBP

1

Eni UK Ltd

100.00

100.00

F.C.

Eni Mozambique LNG Holding BV

Amsterdam (Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

100.00

F.C.

Eni Muara Bakau BV

Amsterdam (Netherlands)

Indonesia

EUR

20,000

Eni International BV

100.00

100.00

F.C.

Eni México S. de RL de CV

Lomas de Chapultepec, Mexico City (Mexico)

Mexico

MXN

3,000

Eni International BV Eni Oil Holdings BV

99.90 0.10

Eq.

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 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

100.00

F.C.

Eni Rapak Ltd

London (United Kingdom)

Indonesia

GBP

2

Eni Indonesia Ltd

100.00

100.00

F.C.

Eni RD Congo SA

Kinshasa (Democratic Republic of the Congo)

Democratic Republic of the Congo

CDF

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.

F-119

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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

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

Algiers (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

Eq.

HOEC Bardahl India Ltd

Vadodara (India)

India

INR

5,000,200

Hindus. Oil E. Co Ltd

100.00

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.

F-120

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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 Eni SpA

99.00 1.00

Eq.

Zetah Congo Ltd

Nassau (Bahamas)

Republic of the Congo

USD

300

Eni Congo SA Burren En. Congo Ltd

66.67 33.33

Co.

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

Co.

Eni Trading & Shipping SpA

Rome

Italy

EUR

60,036,650

Eni SpA Eni Gas & Power NV

94.73 5.27

100.00

F.C.

EniPower Mantova SpA

San Donato Milanese (MI)

Italy

EUR

144,000,000

EniPower SpA Third parties

86.50 13.50

86.50

F.C.

EniPower SpA

San Donato Milanese (MI)

Italy

EUR

944,947,849

Eni SpA

100.00

100.00

F.C.

LNG Shipping SpA

San Donato Milanese (MI)

Italy

EUR

240,900,000

Eni SpA

100.00

100.00

F.C.

Servizi Fondo Bombole Metano SpA

Rome

Italy

EUR

13,580,000.20

Eni SpA

100.00

Co.

Trans Tunisian Pipeline Co SpA

San Donato Milanese (MI)

Tunisia

EUR

1,098,000

Eni SpA

100.00

100.00

F.C.

Outside Italy

Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana

Ljubljana (Slovenia)

Slovenia

EUR

12,956,935

Eni SpA Third parties

51.00 49.00

51.00

F.C.

Distrigas LNG Shipping SA

Bruxelles (Belgium)

Belgium

EUR

788,579.55

LNG Shipping SpA Eni Gas & Power NV

99.99 (..)

100.00

F.C.

Eni G&P France BV

Amsterdam (Netherlands)

France

EUR

20,000

Eni International BV

100.00

100.00

F.C.

Eni G&P Trading BV

Amsterdam (Netherlands)

Turkey

EUR

70,000

Eni International BV

100.00

100.00

F.C.

Eni Gas & Power France SA

Levallois Perret (France)

France

EUR

29,937,600

Eni G&P France BV Third parties

99.85 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 Trading & Shipping Inc

Dover, Delaware (USA)

USA

USD

36,000,000

ETS SpA

100.00

100.00

F.C.

Eni Wind Belgium NV

Bruxelles (Belgium)

Belgium

EUR

5,494,500

Eni Gas & Power NV

100.00

100.00

F.C.

Société de Service du Gazoduc Transtunisien SA - Sergaz SA

Tunisi (Tunisia)

Tunisia

TND

99,000

Eni International BV Third parties

66.67 33.33

66.67

F.C.

Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA

Tunisi (Tunisia)

Tunisia

TND

200,000

Eni International BV Eni Gas & Power NV Eni SpA Trans Tunis. P. Co SpA

99.85 0.05 0.05 0.05

100.00

F.C.

F-121

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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 and Chemical

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 (in liquidation)

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.

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

Wien (Austria)

Austria

EUR

78,500,000

Eni International BV Eni Deutsch. GmbH

75.00 25.00

100.00

F.C.

Eni Benelux BV

Rotterdam (Netherlands)

Netherlands

EUR

1,934,040

Eni International BV

100.00

100.00

F.C.

Eni Deutschland GmbH

Munich (Germany)

Germany

EUR

90,000,000

Eni International BV Eni Oil Holdings BV

89.00 11.00

100.00

F.C.

Eni Ecuador SA

Quito (Ecuador)

Ecuador

USD

103,142

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

Budaors (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

Wien (Austria)

Austria

EUR

19,621,665.23

Eni Mineralölh. GmbH Eni International BV

99.99 (..)

100.00

F.C.

Eni Mineralölhandel GmbH

Wien (Austria)

Austria

EUR

34,156,232.06

Eni Austria GmbH

100.00

100.00

F.C.

Eni Schmiertechnik GmbH

Wurzburg (Germany)

Germany

EUR

2,000,000

Eni Deutsch. GmbH

100.00

100.00

F.C.

Eni Slovenija doo

Ljubljana (Slovenia)

Slovenia

EUR

3,795,528.29

Eni International BV

100.00

100.00

F.C.

Eni Suisse SA

Lausanne (Switzerland)

Switzerland

CHF

102,500,000

Eni International BV Third parties

99.99 (..)

100.00

F.C.

Eni USA R&M Co Inc

Wilmington (USA)

USA

USD

11,000,000

Eni International BV

100.00

100.00

F.C.

F-122

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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.

Chemical

Versalis SpA

San Donato Milanese (MI)

Italy

EUR

1,553,400,000

Eni SpA

100.00

100.00

F.C.

In Italy

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 America Inc

Dover, Delaware (USA)

USA

USD

100,000

Versalis International SA

100.00

Eq.

Versalis Deutschland GmbH

Eschborn (Germany)

Germany

EUR

100,000

Versalis SpA

100.00

100.00

F.C.

Versalis France SAS

Mardyck (France)

France

EUR

126,115,582.90

Versalis SpA

100.00

100.00

F.C.

Versalis International SA

Bruxelles (Belgium)

Belgium

EUR

15,449,173.88

Versalis SpA Versalis Deutsch. GmbH Dunastyr Zrt Versalis France SAS

59.00 23.71 14.43 2.86

100.00

F.C.

Versalis Kimya Ticaret Ltd Sirketi

Istanbul (Turkey)

Turkey

TRY

20,000

Versalis International SA

100.00

Eq.

Versalis Pacific (India) Private Ltd

Mumbai (India)

India

INR

115,110

Versalis Pacific Trading Third parties

99.99 0.01

Eq.

Versalis Pacific Trading (Shanghai) Co Ltd

Shanghai (China)

China

CNY

1,000,000

Versalis SpA

100.00

100.00

F.C.

Versalis UK Ltd

Hythe (United Kingdom)

United Kingdom

GBP

4,004,041

Versalis SpA

100.00

100.00

F.C.

Engineering & Construction

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.

In Italy

Denuke Scarl

San Donato Milanese (MI)

Italy

EUR

10,000

Saipem SpA Third parties

55.00 45.00

23.71

F.C.

F-123

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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.

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 (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 (Mozambique)

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

2,738,411,200

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.

Saipem Australia Pty Ltd

West Perth (Australia)

Australia

AUD

14,800,000

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

Algiers (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 Contracting Prep SA

Panama (Panama)

Panama

USD

500

Saipem SA

100.00

43.11

F.C.

Saipem do Brasil Serviçõs de Petroleo Ltda

Rio de Janeiro (Brazil)

Brazil

BRL

1,380,796,299

Saipem Intern. BV

100.00

43.11

F.C.

F-124

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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 Finance International BV

Amsterdam (Netherlands)

Netherlands

EUR

20,000

Saipem Intern. BV

100.00

43.11

F.C.

Saipem India Projects Private 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 Ukraine Llc

Kiev (Ukraine)

Ukraine

EUR

4,206,060.61

Saipem Intern. BV Saipem Luxemb. SA

99.00 1.00

43.11

F.C.

Saiwest Ltd

Accra (Ghana)

Ghana

GHS

937,500

Saipem SA Third parties

80.00 20.00

Co.

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.

F-125

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

Snamprogetti Netherlands BV

Amsterdam (Netherlands)

Netherlands

EUR

203,000

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 Australia Ltd

100.00

43.11

F.C.

Corporate and Other activities

Corporate and financial companies

In Italy

Agenzia Giornalistica Italia SpA

Rome

Italy

EUR

2,000,000

Eni SpA

100.00

100.00

F.C.

Eni Adfin SpA

Rome

Italy

EUR

85,537,498.80

Eni SpA Third parties

99.64 0.36

99.64

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.

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.

Other activities

Syndial SpA - Attività Diversificate

San Donato Milanese (MI)

Italy

EUR

421,947,684.55

Eni SpA Third parties

99.99 (..)

100.00

F.C.

In Italy

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

5,518,620.64

Syndial SpA

100.00

100.00

F.C.

F-126

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

Outside Italy

Oleodotto del Reno SA

Coira (Switzerland)

Switzerland

CHF

1,550,000

Syndial SpA

100.00

Eq.

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.

Outside Italy

Agiba Petroleum Co (†)

Cairo (Egypt)

Egypt

EGP

20,000

Ieoc Production BV Third parties

50.00 50.00

Co.

Angola LNG Ltd

Hamilton (Bermuda)

Angola

USD

11,700,000,000

Eni Angola Prod. BV Third parties

13.60 86.40

Eq.

Ashrafi Island Petroleum Co

Cairo (Egypt)

Egypt

EGP

20,000

Ieoc Production BV Third parties

25.00 75.00

Co.

Barentsmorneftegaz Sàrl (†)

Luxembourg (Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV Third parties

33.33 66.67

Eq.

Cabo Delgado Gas Development Limitada (†)

Maputo (Mozambique)

Mozambique

MZN

2,500,000

Eni 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-Fayrouz Petroleum Co (†) (in liquidation)

Cairo (Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV Third parties

50.00 50.00

Co.

El Temsah Petroleum Co

Cairo (Egypt)

Egypt

EGP

20,000

Ieoc Production BV Third parties

25.00 75.00

Co.

Enstar Petroleum Ltd

Calgary (Canada)

Canada

CAD

0.10

Unimar Llc

100.00

Fedynskmorneftegaz Sàrl (†)

Luxembourg (Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV Third parties

33.33 66.67

Eq.

InAgip doo (†)

Zagreb (Croatia)

Croatia

HRK

54,000

Eni Croatia BV Third parties

50.00 50.00

Co.

Karachaganak Petroleum Operating BV

Amsterdam (Netherlands)

Kazakhstan

EUR

20,000

Agip 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

469,186,704.96

Zagoryanska P BV

100.00

Llc Industrial Company Gazvydobuvannya

Poltava (Ukraine)

Ukraine

UAH

354,965,000

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.

F-127

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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

410,500,000

Eni Lasmo Plc Third parties

40.00 60.00

Eq.

PetroJunín SA (†)

Caracas (Venezuela)

Venezuela

VEF

2,591,100,000

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

7,850,000

Eni International BV Third parties

50.00 50.00

Eq.

Tecninco Engineering Contractors Llp (†)

Aksai (Kazakhstan)

Kazakhstan

KZT

29,478,455

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.

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 (†) (in liquidation)

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.

F-128

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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.

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

72,759,200

Eni SpA Third parties

49.00 51.00

Eq.

Eteria Parohis Aeriou Thessalonikis AE (†)

Ampelokipi-Menemeni (Greece)

Greece

EUR

193,550,000

Eni SpA Third parties

49.00 51.00

Eq.

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

Nueva Electricidad del Gas SA (in liquidation)

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.

Unión Fenosa Gas Comercializadora SA

Madrid (Spain)

Spain

EUR

2,340,240

U. Fenosa Gas SA Third parties

99.99 (..)

Unión Fenosa Gas Exploración y Produccion SA

Logrono (Spain)

Spain

EUR

1,060,110

U. Fenosa Gas SA

100.00

Unión Fenosa Gas Infrastructures BV

Amsterdam (Netherlands)

Netherlands

EUR

90,000

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 and Chemical

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.

F-129

---

Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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.

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 - Raffineriebeteiligungs-gesellschaft 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 (†)

Neustadt (Germany)

Germany

EUR

10,226,000

Eni Deutsch. GmbH Third parties

20.00 80.00

20.00

J.O.

City Carburoil SA (†)

Rivera (Switzerland)

Switzerland

CHF

6,000,000

Eni Suisse SA Third parties

49.91 50.09

Eq.

ENEOS Italsing Pte Ltd

Singapore (Singapore)

Singapore

SGD

12,000,000

Eni International BV Third parties

22.50 77.50

Eq.

FSH Flughafen Schwechat Hydranten-Gesellschaft OG

Wien (Austria)

Austria

EUR

7,816,139.91

Eni Austria GmbH Eni Mineralölh. GmbH Eni Marketing A. GmbH Third parties

14.29 14.29 14.28 57.14

Co.

Fuelling Aviation Services GIE

Tremblay en France (France)

France

EUR

1

Eni France Sàrl Third parties

25.00 75.00

Co.

Mediterranée Bitumes SA

Tunisi (Tunisia)

Tunisia

TND

1,000,000

Eni International BV Third parties

34.00 66.00

Eq.

Routex BV

Amsterdam (Netherlands)

Netherlands

EUR

67,500

Eni International BV Third parties

20.00 80.00

Eq.

Saraco SA

Meyrin (Switzerland)

Switzerland

CHF

420,000

Eni Suisse SA Third parties

20.00 80.00

Co.

Supermetanol CA (†)

Jose Puerto La Cruz (Venezuela)

Venezuela

VEF

12,086,744.85

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.

Chemical

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.

F-130

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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

400,000

Versalis SpA Genomatica Inc

81.59 18.41

Eq.

Novamont SpA

Novara

Italy

EUR

13,333,500

Versalis SpA Third parties

25.00 75.00

Eq.

Priolo Servizi ScpA

Melilli (SR)

Italy

EUR

28,100,000

Versalis SpA Syndial 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

8,695,718

Versalis SpA Syndial SpA Third parties

48.44 38.39 13.17

Eq.

Outside Italy

Lotte Versalis Elastomers Co Ltd (†)

Yeosu (South Korea)

South Korea

KRW

165,200,010,000

Versalis SpA Third parties

50.00 50.00

Eq.

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. (†)

Venice 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.

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 (†)

Genoa

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

Eq.

CCS Lng Mozambique Limitada (†)

Maputo (Mozambique)

Mozambique

MZN

150,000

Saipem Intern. BV Third parties

33.33 66.67

Eq.

CCS 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.

F-131

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

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.

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 Dangote E&C Ltd (†)

Victoria Island, Lagos (Nigeria)

Nigeria

NGN

100,000,000

Saipem Intern. BV Third parties

49.00 51.00

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.

S.B.K. Baltica Società Consortile a Responsabilità Limitata Sp. K. (†)

Gdansk (Poland)

Poland

PLN

10,000

SaipemSpA Baltica Scarl Third parties

49.00 2.00 49.00

Co.

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

Eq.

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 Mühendislik 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.

F-132

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

Corporate and Other activities

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.

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

1,015,761,791

Eni G&P LNG Aus BV Third parties

10.99 89.01

Co.

New Liberty Residential Co Llc

West Trenton (USA)

USA

USD

0 (b)

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 NV

Amsterdam (Netherlands)

Kazakhstan

EUR

128,520

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.

F-133

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Table of Contents

Company name

Registered office

Country of operation

Currency

Share Capital

Shareholders

% Ownership

% Equity ratio

(*)

Refining & Marketing and Chemical

Refining & Marketing

In Italy

Consorzio Obbligatorio degli Oli Usati

Rome

Italy

EUR

36,149

Eni SpA Third parties

13.27 86.73

Co.

Società Italiana Oleodotti di Gaeta SpA (1)

Rome

Italy

ITL

360,000,000

Eni SpA Third parties

72.48 27.52

Co.

Outside Italy

BFS Berlin Fuelling Services GbR

Hamburg (Germany)

Germany

EUR

178,853

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

175,713

Eni Iberia SLU Third parties

15.44 84.56

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 other activities

Corporate and financial companies

In Italy

Emittenti Titoli SpA

Milan

Italy

EUR

4,264,000

Eni SpA Emittenti Titoli SpA Third parties

10.00 0.78 89.22

Co.

Mip Politecnico di Milano - Graduate School of Business ScpA (former 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.

Snam SpA (#)

San Donato Milanese (MI)

Italy

EUR

3,696,851,994

Eni SpA Snam SpA Third parties

2.22 0.03 97.75

F.V.

F-134

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Table of Contents

Information on Eni’s consolidated subsidiaries with significant non-controlling interest

In 2015, Eni did not own any consolidated subsidiaries with significant non-controlling interest as consequence of the classification of Saipem Group as discontinued operations. For 2014, 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.

		2014

(euro million)		Saipem Group

Non-controlling interest (%)		56.89
Current assets		8,632
Non-current assets		8,996
Current liabilities		9,605
Non-current liabilities		3,828
Revenues		12,873
Net profit (loss) for the year		(621	)
Total comprehensive income (loss) for the year		(555	)
Net cash provided by operating activities		1,198
Net cash used in investing activities		(699	)
Net cash used in financing activities		(214	)
Net cash flow of the year		305
Net profit (loss) for the year attributable to non-controlling interest		(345	)
Dividends paid to non-controlling interest		45

Total shareholders’ equity attributable to non-controlling interest amounted to euro 1,916 million, of which euro 1,872 million pertaining to the Saipem Group (euro 2,455 million at December 31, 2014, of which euro 2,398 million pertaining to the Saipem Group).

 

Changes in the ownership interest without loss of control

In 2014 and 2015, Eni did not report any changes in the ownership interest without loss or acquisition of control.

F-135

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Table of Contents

Principal joint ventures, joint operations and associates as of December 31, 2015

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
PetroJunín SA		Caracas (Venezuela)		Venezuela		Exploration & Production		40.00		40.00
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

 

 

 

 

 

 

F-136

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Table of Contents

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:

 

		2014		2015

(euro million)

CARDÓN IV SA

Eteria Parohis Aeriou Thessalonikis AE

PetroJunín SA

Unión Fenosa Gas SA

Other joint ventures

CARDÓN IV SA

Eteria Parohis Aeriou Thessalonikis AE

PetroJunín SA

Unión Fenosa Gas SA

Other joint ventures

Current assets		871			43			118			715			821			1,125			61			197			695			257
- of which cash and cash equivalent		43			25			14			87			347			27			34			5			55			93
Non-current assets		1,674			208			490			1,246			949			2,849			204			623			1,156			406
Total assets		2,545			251			608			1,961			1,770			3,974			265			820			1,851			663
Current liabilities		2,089			24			375			270			1,094			3,356			19			361			294			136
- current financial liabilities		1,248									62			408			2,223									55			5
Non-current liabilities		164						1			732			187			298			23			25			697			174
- non-current financial liabilities											647			31												590			98
Total liabilities		2,253			24			376			1,002			1,281			3,654			42			386			991			310
Net equity		292			227			232			959			489			320			223			434			860			353
Eni’s ownership interest (%)		50.00			49.00			40.00			50.00						50.00			49.00			40.00			50.00
Book value of the investment		146			111			93			577			253			160			109			174			503			170
Revenues and other operating income					117			44			1,619			1,130			189			137			84			1,770			435
Operating expense		(7	)		(80	)		(38	)		(1,463	)		(880	)		(73	)		(92	)		(67	)		(1,739	)		(257	)
Depreciation, depletion, amortization and impairments		(2	)		(14	)		(12	)		(50	)		(272	)		(26	)		(14	)		(33	)		(137	)		(180	)
Operating profit		(9	)		23			(6	)		106			(22	)		90			31			(16	)		(106	)		(2	)
Finance (expense) income		63			1			42			(34	)		(28	)		(84	)					107			(53	)		5
Income (expense) from investments											26			(20	)											29			(7	)
Profit before income taxes		54			24			36			98			(70	)		6			31			91			(130	)		(4	)
Income taxes		2			(6	)		(28	)		(14	)		(69	)		(12	)		(9	)		(18	)		31			1
Net profit		56			18			8			84			(139	)		(6	)		22			73			(99	)		(3	)
Other comprehensive income		33						25			22			20			34						30			25			23
Total other comprehensive income		89			18			33			106			(119	)		28			22			103			(74	)		20
Net profit attributable to Eni		28			9			3			42			23			(3	)		11			29			(74	)		4
Dividends received by the joint venture					10						23			65						8						13			8

 

 

 

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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:

		2014		2015

(euro million)

Angola LNG Ltd

PetroSucre SA

United Gas Derivatives Co

Other associates

Angola LNG Ltd

PetroSucre SA

United Gas Derivatives Co

Other associates

Current assets		318			1,503			361			1,232			111			950			329			96
- of which cash and cash equivalent		167			5			171			124			11			2			234			10
Non-current assets		9,389			736			137			635			8,067			618			126			79
Total assets		9,707			2,239			498			1,867			8,178			1,568			455			175
Current liabilities		484			1,515			167			1,118			712			1,013			101			34
- current financial liabilities											86												2
Non-current liabilities		210			67			24			202						81			14			63
- non-current financial liabilities											46												13
Total liabilities		694			1,582			191			1,320			712			1,094			115			97
Net equity		9,013			657			307			547			7,466			474			340			78
Eni’s ownership interest (%)		13.60			26.00			33.33						13.60			26.00			33.33
Book value of the investment		1,226			171			102			208			1,015			123			113			50
Revenues and other operating income					824			229			1,391						466			142			178
Operating expense		(237	)		(554	)		(64	)		(1,333	)		(255	)		(449	)		(59	)		(146	)
Depreciation, depletion, amortization and impairments					(214	)		(23	)		(63	)		(3,180	)		(198	)		(28	)		(15	)
Operating profit		(237	)		56			142			(5	)		(3,435	)		(181	)		55			17
Finance (expense) income		(14	)		(6	)		3			(2	)		(10	)		(11	)		18			(1	)
Income (expense) from investments											7												1
Profit before income taxes		(251	)		50			145						(3,445	)		(192	)		73			17
Income taxes					(27	)		(50	)		(14	)					(61	)		(12	)		(4	)
Net profit		(251	)		23			95			(14	)		(3,445	)		(253	)		61			13
Other comprehensive income		1,075			82			37			3			990			71			35			9
Total other comprehensive income		824			105			132			(11	)		(2,455	)		(182	)		96			22
Net profit attributable to Eni		(34	)		6			32			(6	)		(469	)		(66	)		20			2
Dividends received by the associate					29			36			13									21			1

47 Significant non-recurring events and operations

In 2013, in 2014 and 2015, Eni did not report any non-recurring events and operations.

48 Positions or transactions deriving from atypical and/or unusual operations

In 2013, 2014 and 2015 no transactions deriving from atypical and/or unusual operations were reported.

49 Subsequent events

On January 22, 2016, the Saipem transaction was finalized with the closing of the sale of a 12.503% stake in the entity to the Fondo Strategico Italiano (FSI) and the concurrent enter into force of the shareholder agreement between the parties intended to establish joint control over the former subsidiary. Therefore, Saipem has been derecognized from Eni’s consolidated accounts and accounted for using the equity method. At the date of the loss of control, the residual interest in Saipem was aligned at the market price at closing of euro 4.2 per share with a charge through profit and loss of euro 441 million compared to the valuation at the end of 2015. Subsequently, in February 2016, Saipem’s market capitalization has fallen sharply. Under the provisions of IAS 10 these negative developments do not constitute adjusting events of the Saipem valuation made in the 2015 accounts which aligned the Saipem carrying amount to the market price at December 31, 2015. Following the successful closing of Saipem share capital increase of euro 3.5 billion before the end of February (Eni cash out of euro 1,069 million), Saipem performed the repayment of the intercompany loans granted by Eni through the proceeds of the share capital increase and new funding granted by financial institutions (euro 5,818 million as of December 31, 2015).

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Supplemental oil and gas information (unaudited)

The following information based on "International Financial Reporting Standards" (IFRS) requirements 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&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

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
2015
Consolidated subsidiaries
Proved mineral interests		14,945			14,921			25,329			34,294			3,352			10,179			14,927			1,962			119,909
Unproved mineral interests		31			402			497			3,502			48			1,712			1,657			237			8,086
Support equipment and facilities		355			42			1,758			1,318			112			34			74			15			3,708
Incomplete wells and other		954			3,189			1,858			2,911			8,708			1,375			670			92			19,757
Gross capitalized costs		16,285			18,554			29,442			42,025			12,220			13,300			17,328			2,306			151,460
Accumulated depreciation, depletion and amortization		(11,887	)		(11,402	)		(18,934	)		(25,747	)		(1,504	)		(9,985	)		(12,932	)		(1,223	)		(93,614	)
Net capitalized costs consolidated subsidiaries (a) (b)		4,398			7,152			10,508			16,278			10,716			3,315			4,396			1,083			57,846
Equity-accounted entities
Proved mineral interests					3			79			23						635			1,930						2,670
Unproved mineral interests					23												93									116
Support equipment and facilities								8												6						14
Incomplete wells and other					9			5			1,503						1			112						1,630
Gross capitalized costs					35			92			1,526						729			2,048						4,430
Accumulated depreciation, depletion and amortization					(31	)		(72	)		(441	)					(676	)		(336	)					(1,556	)
Net capitalized costs equity-accounted entities (a) (b)					4			20			1,085						53			1,712						2,874

(a)		The amounts include net capitalized financial charges totaling euro 868 million in 2014 and euro 1,029 million in 2015 for the consolidated subsidiaries and euro 46 million in 2014 and euro 92 million in 2015 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 4,804 million in 2014 and euro 4,434 million in 2015 for the consolidated subsidiaries and euro 123 million in 2014 and euro 150 million in 2015 for equity-accounted entities.

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Costs incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil&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

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)						1		22				38		375				436
Total costs incurred equity-accounted entities				2		1		22				71		376				472
2015
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration		28		176		289		196				71		54		6		820
Development (a)		207		1,006		1,574		2,957		819		1,332		745		18		8,658
Total costs incurred consolidated subsidiaries		235		1,182		1,863		3,153		819		1,403		799		24		9,478
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration				1								14		1				16
Development (b)				1		1		112				35		554				703
Total costs incurred equity-accounted entities				2		1		112				49		555				719

(a)		Includes the abandonment costs of the assets negative for euro 191 million in 2013, costs for euro 2,062 million in 2014 and negative for euro 817 million in 2015.
(b)		Includes the abandonment costs of the assets for euro 10 million in 2013, negative euro 47 million in 2014 and costs for euro 54 million in 2015.

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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 (PSAs), whereby a portion of Eni’s share of oil&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&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

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

(a)		Includes asset impairments amounting to euro 15 million in 2013.
(b)		The "Successful Effort Method" application according to Eni accounting policy would have led to an increase of euro 295 million in 2013 for the consolidated subsidiaries; a decrease of euro 6 million in 2013 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

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	)
2015
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		2,124			1,828			1,403			3,514			231			628			1,118			29			10,875
- sales to third parties					501			5,681			914			659			854			131			226			8,966
Total revenues		2,124			2,329			7,084			4,428			890			1,482			1,249			255			19,841
Operations costs		(403	)		(642	)		(948	)		(1,099	)		(239	)		(235	)		(453	)		(108	)		(4,127	)
Production taxes		(184	)					(240	)		(405	)					(30	)					(9	)		(868	)
Exploration expenses		(28	)		(214	)		(295	)		(226	)					(81	)		(86	)		(25	)		(955	)
D.D. & A. and provision for abandonment (a)		(734	)		(1,825	)		(2,878	)		(3,384	)		(111	)		(1,453	)		(1,702	)		(110	)		(12,197	)
Other income (expense)		(215	)		(138	)		(565	)		(233	)		(155	)		(277	)		(9	)		(24	)		(1,616	)
Pre-tax income from producing activities		560			(490	)		2,158			(919	)		385			(594	)		(1,001	)		(21	)		78
Income taxes		(190	)		413			(2,165	)		7			(155	)		60			406			(26	)		(1,650	)
Results of operations from E&P activities of consolidated subsidiaries (b)		370			(77	)		(7	)		(912	)		230			(534	)		(595	)		(47	)		(1,572	)
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties								19									68			248						335
Total revenues								19									68			248						335
Operations costs								(9	)								(13	)		(49	)					(71	)
Production taxes								(3	)											(82	)					(85	)
Exploration expenses					(1	)											(30	)		(1	)					(32	)
D.D. & A. and provision for abandonment					(2	)		(2	)		(432	)					(78	)		(76	)					(590	)
Other income (expense)					(3	)		(1	)		(35	)					(6	)		(48	)					(93	)
Pre-tax income from producing activities					(6	)		4			(467	)					(59	)		(8	)					(536	)
Income taxes								(3	)								8			(29	)					(24	)
Results of operations from E&P activities of equity-accounted entities (b)					(6	)		1			(467	)					(51	)		(37	)					(560	)

(a)		Includes asset impairments amounting to euro 690 million in 2014 and euro 4,341 million in 2015.
(b)		The "Successful Effort Method" application according to Eni accounting policy would have led to a decrease of euro 15 million in 2014 and euro 378 million in 2015 for the consolidated subsidiaries and an increase of euro 24 million in 2014 and euro 15 million in 2015 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&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 2015, the average price for the marker Brent crude oil was 54 $/BBL.

Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil&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&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 evaluation²⁵ 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 report²⁶.

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 2015, Ryder Scott Company and DeGolyer and MacNaughton and Gaffney, Cline & Associates²⁶ provided an independent evaluation of about 31% of Eni’s total proved reserves as of December 31, 2015²⁷, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.

In the three-year period from 2013 to 2015, 86% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2015, the principal properties not subjected to independent evaluation in the last three years are Kashagan (Kazakhstan) and Cafc-Mle (Algeria).

Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil&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&gas reserves associated with PSAs represented 51%, 50% and 52% of total proved reserves as of December 31, 2013, 2014 and 2015, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 3%, 3% and 5% of total proved reserves on an oil-equivalent basis as of December 31, 2013, 2014 and 2015, 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&gas deriving from such obligation

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represent 1.0%, 0.6% and 0.6% of total proved reserves as of December 31, 2013, 2014 and 2015, 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.

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, 2013, 2014 and 2015.

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

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
2015
Consolidated subsidiaries
Reserves at December 31, 2014		243			331			776			739			697			131			147			13			3,077
of which: developed		184			174			521			470			306			64			116			12			1,847
of which: undeveloped		59			157			255			269			391			67			31			1			1,230
Purchase of minerals-in-place
Revisions of previous estimates		10			5			139			143			94			159			64			(2	)		612
Improved recovery								2																		2
Extensions and discoveries								2			14									6						22
Production		(25	)		(31	)		(98	)		(93	)		(20	)		(28	)		(28	)		(2	)		(325	)
Sales of minerals-in-place											(16	)														(16	)
Reserves at December 31, 2015		228			305			821			787			771			262			189			9			3,372
Equity-accounted entities
Reserves at December 31, 2014								14			17						1			117						149
of which: developed								13			7									26						46
of which: undeveloped								1			10						1			91						103
Purchase of minerals-in-place
Revisions of previous estimates											(1	)								45						44
Improved recovery
Extensions and discoveries
Production								(1	)								(1	)		(4	)					(6	)
Sales of minerals-in-place
Reserves at December 31, 2015								13			16									158						187
Reserves at December 31, 2015		228			305			834			803			771			262			347			9			3,559
Developed		171			237			555			517			355			126			178			9			2,148
Consolidated subsidiaries		171			237			542			511			355			126			149			9			2,100
Equity-accounted entities								13			6									29						48
Undeveloped		57			68			279			286			416			136			169						1,411
Consolidated subsidiaries		57			68			279			276			416			136			40						1,272
Equity-accounted entities											10									129						139

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Natural gas ^(a)

(BCF)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

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

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.

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Natural gas ^(a) continued

(BCF)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2015
Consolidated subsidiaries
Reserves at December 31, 2014		1,432			1,171			5,291			2,744			2,049			846			468			807			14,808
of which: developed		1,192			887			2,110			1,271			1,553			261			393			675			8,342
of which: undeveloped		240			284			3,181			1,473			496			585			75			132			6,466
Purchase of minerals-in-place
Revisions of previous estimates		68			74			163			145			385			24			69			5			933
Improved recovery
Extensions and discoveries		4						124									114									242
Production		(200	)		(201	)		(780	)		(171	)		(80	)		(106	)		(94	)		(41	)		(1,673	)
Sales of minerals-in-place											(4	)								(4	)					(8	)
Reserves at December 31, 2015		1,304			1,044			4,798			2,714			2,354			878			439			771			14,302
Equity-accounted entities
Reserves at December 31, 2014								15			351						18			3,353						3,737
of which: developed								15			89						10			6						120
of which: undeveloped											262						8			3,347						3,617
Purchase of minerals-in-place
Revisions of previous estimates											36						3			253						292
Improved recovery
Extensions and discoveries
Production								(2	)								(9	)		(25	)					(36	)
Sales of minerals-in-place
Reserves at December 31, 2015								13			387						12			3,581						3,993
Reserves at December 31, 2015		1,304			1,044			4,811			3,101			2,354			890			4,020			771			18,295
Developed		1,051			919			2,579			1,475			1,830			194			1,668			585			10,301
Consolidated subsidiaries		1,051			919			2,566			1,390			1,830			185			373			585			8,899
Equity-accounted entities								13			85						9			1,295						1,402
Undeveloped		253			125			2,232			1,626			524			696			2,352			186			7,994
Consolidated subsidiaries		253			125			2,232			1,324			524			693			66			186			5,403
Equity-accounted entities											302						3			2,286						2,591

(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&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&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, 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

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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(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

December 31, 2015
Consolidated subsidiaries
Future cash inflows		16,760			18,692			58,390			44,114			34,589			13,027			8,101			3,519			197,192
Future production costs		(4,995	)		(5,554	)		(13,481	)		(14,645	)		(8,846	)		(4,585	)		(3,091	)		(804	)		(56,001	)
Future development and abandonment costs		(4,299	)		(4,379	)		(9,457	)		(9,359	)		(4,108	)		(4,964	)		(1,644	)		(218	)		(38,428	)
Future net inflow before income tax		7,466			8,759			35,452			20,110			21,635			3,478			3,366			2,497			102,763
Future income tax		(1,657	)		(4,349	)		(17,195	)		(8,222	)		(4,682	)		(1,230	)		(933	)		(604	)		(38,872	)
Future net cash flows		5,809			4,410			18,257			11,888			16,953			2,248			2,433			1,893			63,891
10% discount factor		(2,077	)		(817	)		(7,844	)		(4,976	)		(10,561	)		(1,276	)		(970	)		(901	)		(29,422	)
Standardized measure of discounted future net cash flows		3,732			3,593			10,413			6,912			6,392			972			1,463			992			34,469
Equity-accounted entities
Future cash inflows								313			3,047						85			18,519						21,964
Future production costs								(177	)		(1,021	)					(32	)		(5,370	)					(6,600	)
Future development and abandonment costs								(5	)		(95	)					(22	)		(2,118	)					(2,240	)
Future net inflow before income tax								131			1,931						31			11,031						13,124
Future income tax								(8	)		(251	)					(10	)		(4,088	)					(4,357	)
Future net cash flows								123			1,680						21			6,943						8,767
10% discount factor								(70	)		(1,016	)					(2	)		(4,358	)					(5,446	)
Standardized measure of discounted future net cash flows								53			664						19			2,585						3,321
Total consolidated subsidiaries and equity-accounted entities		3,732			3,593			10,466			7,576			6,392			991			4,048			992			37,790

 

 

 

 

 

 

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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, 2013, 2014 and 2015, are as follows:

(euro million)		Consolidated subsidiaries		Equity-accounted entities		Total

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
Increase (Decrease):
- sales, net of production costs		(14,846	)		(179	)		(15,025	)
- net changes in sales and transfer prices, net of production costs		(70,909	)		(2,858	)		(73,767	)
- extensions, discoveries and improved recovery, net of future production and development costs		524						524
- changes in estimated future development and abandonment costs		(1,711	)		(241	)		(1,952	)
- development costs incurred during the period that reduced future development costs		8,960			604			9,564
- revisions of quantity estimates		12,322			915			13,237
- accretion of discount		11,288			629			11,917
- net change in income taxes		29,530			530			30,060
- purchase of reserves-in-place
- sale of reserves-in-place		(114	)					(114	)
- changes in production rates (timing) and other		3,390			363			3,753
Net increase (decrease)		(21,566	)		(237	)		(21,803	)
Standardized measure of discounted future net cash flows at December 31, 2015		34,469			3,321			37,790

 

 

 

 

 

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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 12, 2016

 

 

 

 

 

 

 

 

 

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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

 

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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		The Chairman of the Board or, in his absence, the eldest director in attendance shall chair the meeting.
ARTICLE 21
21.1		For a Board meeting to be valid, a majority of serving directors must be present.
21.2		Resolutions shall be approved by a majority of the votes of the directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote.
ARTICLE 22
22.1		The resolutions of the Board of Directors shall be registered in the minutes, which shall be recorded in a book kept for that purpose pursuant to the provisions of law, and said minutes shall signed by the Chairman of the meeting and by the Secretary.
22.2		Copies of the minutes shall be considered bona fide if they are signed by the Chairman or the person acting in place of the Chairman and countersigned by the Secretary.
ARTICLE 23
23.1		The Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or these By-laws reserve to the Shareholders’ Meeting.
23.2		The Board of Directors shall decide the following matters:

-		the merger and proportional demerger of companies in which the Company owns shares or other equity holdings representing at least 90% of the share capital;
-		the establishment and closing of branches; and
-		the amendment of the By-laws to comply with the provisions of law.

23.3		The Board of Directors and the Chief Executive Officer shall promptly report to the Board of Statutory Auditors at least every three months and in any event at the time of the meetings of the Board of Directors, on the activity carried out and on the transactions with the most significant impact on performance and the financial position carried out by the Company and its subsidiaries. In particular, they shall report to the Board of Statutory Auditors those transactions in which they have an interest, either on their own behalf or on behalf of third parties.
ARTICLE 24
24.1		The Board of Directors may delegate its powers to one of its members, within the limits set forth in Article 2381 of the Italian Civil Code. The Board may, in addition, delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may revoke delegated powers at any time, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors. The Chairman and the Chief Executive Officer, within the limits of the authority attributed to them, may delegate and empower Company employees or third parties to represent the Company for individual acts or specific categories of acts. Further, acting upon proposal of the Chief Executive Officer and in agreement with the Chairman, the Board of Directors may also appoint one or more General Managers (Chief Operating Officers) and determine the powers to be conferred on them, once it has been ascertained that they fulfill the 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, 2015 – 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.

 

 

 

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(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:

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:

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The remuneration to be paid shall be exclusively proportionate to the services to be rendered and described in the contract and payments shall not be allowed to any party different from the contract party nor in a third country different from the one of the parties or where the contract has to be performed2.

5. THE MANAGEMENT, EMPLOYEES AND COLLABORATORS OF ENI

5.1. Development and protection of Human Resources People are basic components in the Company’s life. The dedication and professionalism of management and employees represent fundamental values and conditions for achieving eni’s objectives. eni is committed to developing the abilities and skills of management and employees so that their energy and creativity can have full expression for the fulfilment of their potential in their working performance, such as to protect working conditions as regards both mental and physical health and dignity. Undue pressure or discomfort is not allowed, while appropriate working conditions promoting development of personality and professionalism are fostered. eni undertakes to offer, in full compliance with applicable legal and contractual provisions, equal opportunities to all its employees, making sure that each of them receives a fair statutory and wage treatment exclusively based on merit and expertise, without discrimination of any kind. Competent departments shall:

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.

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(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:

Any form of violence or harassment, either sexual harassment or harassment based on personal and cultural diversity, is forbidden. Such harassment is for instance:

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:

 

III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS

1. INTERNAL CONTROL AND RISK MANAGEMENT SYSTEM

eni is committed to promoting and maintaining an adequate internal control and risk management system, by adopting and implementing all 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:

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:

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:

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:

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:

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:

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:

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:

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 12, 2016

 

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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 12, 2016

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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, 2015 (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 12, 2016

 

 

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, 2015 (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 12, 2016

 

 

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)

 

 

DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

 

 

February 28, 2016

 

Eni S.p.A.
Pietro G. Consonni
Vice President, Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy


Dear Mr. Consonni:

Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved oil, condensate, liquefied petroleum gas (LPG), and gas reserves, as of December 31, 2015, of certain properties in Africa and America in which Eni S.p.A. (Eni) has represented that it owns an interest. This evaluation was completed on February 28, 2016. Eni has represented that these properties account for 18.0 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2015, 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, 2015, 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, 2015. 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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Estimates of oil, condensate, LPG, and gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Eni personnel, from Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.


Methodology and Procedures

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.

Based on the current stage of field development, the development plans provided by Eni, and the analyses of areas offsetting existing wells, reserves were classified as proved.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.

 

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Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In these instances, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate.

In certain cases, elements of the reserves estimates incorporated information based on analogy with similar reservoirs where more complete data were available.

Eni has represented that its estimates of oil, 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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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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(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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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 54.25 United States dollars (U.S.$) per barrel (U.S.$/bbl) was the resulting reference price. Where appropriate, Eni supplied differentials by field to the relevant reference price, and the prices were held constant thereafter. The volume-weighted average prices in this report were as follows:

 

 

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Gas Prices

Eni has represented that the provided gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A significant quantity of the gas sold by Eni is subject to contract prices, and the range of such prices is varied. A reference price is the United Kingdom National Balancing Point Index, which was U.S.$6.06 per thousand cubic feet. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices in this report were as follows, expressed in United States dollars per thousand cubic feet (U.S.$/Mcf):

		Gas (U.S.$/Mcf)

Africa	4.93
America	2.54
Average for Total	4.38

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Eni, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

 

 

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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, 2015, estimated herein.

Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Africa and America 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 18.0 percent of Eni’s net 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, 2015

		Oil, Condensate, and LPG (MMbbl)		Gas (Bcf)		Oil Equivalent (MMboe)
Properties reviewed by DeGolyer and MacNaughton
Total Proved		869		1,937		1,222

 

In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932 235 50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

 

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DEGOLYER AND MACNAUGHTON

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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DEGOLYER AND MACNAUGHTON

 

 

 

 

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, 2016, and that I, as Senior Vice President, was responsible for the preparation of this report.
2.		That I attended 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 33 years of experience in oil and gas reservoir studies and reserves evaluations.

 

SIGNED: February 28, 2016

 

 

 

	/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, 2015

\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		Vice President
[SEAL]		[SEAL]

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

 

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March 25, 2016

 

Eni S.p.A
Mr. Pietro G. Consonni
Vice President Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

Dear Mr. Consonni,

At the request of Eni S.p.A. (Eni), Ryder Scott Company, L.P (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni’s engineering and geological staff as of December 31, 2015 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 March 8, 2016 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 13 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations:

• Americas
• Europe

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, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott’s estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The conclusions discussed in this report are related to hydrocarbon prices. Eni has informed us that in preparation of their reserve and income projections, as of December 31, 2015, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the

 

 

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March 25, 2016
Page 2

unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott.


Reserves Included in This Report

In our opinion, the proved reserves discussed herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein.

Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless 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

 

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Eni S.p.A. – Third Party
March 25, 2016
Page 3

Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.


Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable 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

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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March 25, 2016
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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 2015 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 2015. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent 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.

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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March 25, 2016
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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.

Eni furnished us with the above mentioned average prices in effect on December 31, 2015. 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

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
March 25, 2016
Page 6

 

are sold. The average dated Brent oil price of $54.13/bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. All gas prices shown below are in dollars per thousand cubic meters ($/km3). The average realized prices provided by Eni and used in our evaluation are as follows:

 

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, 2015. 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, 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,

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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2015, 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.

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.

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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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
	Herman G. Acuna, P.E.
	TBPE License No. 92254
	Managing Senior Vice President – International
[SEAL]
	\s\ GABRIELLE GUERRE
	Gabrielle Guerre, P.E.
	TBPE License No. 109935
	Vice President
	[SEAL]
HGA-GG (DPR)/pl

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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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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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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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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EXHIBIT 15.a(iii)

TG/kab/EL-15-210500/0764

7th March, 2016

Mr. Pietro Consonni
Vice President Reserves
Eni S.p.A.
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

Dear Mr Consonni,

Proved Reserves Statement (SEC Rules)
Certain Properties in Europe
as of 31st December, 2015

This proved reserves audit has been conducted by Gaffney, Cline & Associates (GCA) at the request of Eni S.p.A. (Eni or "the Client"), in certain properties located in Europe. This third party report, completed on February 16, is intended for inclusion in Eni's filings to the U.S. Securities and Exchange Commission (SEC).

This statement relates specifically and solely to the subject matter as set out herein and is conditional upon the specified assumptions. The report must be considered in its entirety and must only be used for the purpose for which it was intended.

On the basis of technical and other information made available to GCA concerning these properties, GCA has conducted an independent audit examination, as of 31^st December, 2015, of the proved crude oil and natural gas reserves as prepared by Eni in certain properties in Europe, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal register.

Reserves included herein are expressed as net reserves as represented by Eni.

Eni has advised GCA that the net proved reserves of the properties that GCA reviewed represent 0.2 percent of Eni's total net proved reserves as of December 31, 2015, on an oil-equivalent basis. GCA is not in a position to verify this statement as it was not requested to review Eni's other oil and gas assets.

 

 

 

TG/kab/EL-15-210500/0764 Eni S.p.A.

1

Registered in England, number 1122740, at the above address

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Reserves Assessment

This audit examination was based on reserves estimates and other information provided by Eni to GCA through 31^st December, 2015, and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the audit process were resolved to GCA's satisfaction. For the purposes of this assessment, Eni provided GCA with a set of data and presentation material that included production, reservoir studies and a selection of static and dynamic models. GCA audited the data provided for consistency and reasonableness. GCA also had discussions and meetings with Eni technical and commerciai personnel.

As part of the audit GCA developed independent production forecasts, employing decline curve analysis, material balance and type well methods, in addition to auditing and reviewing Eni's static, dynamic and material balance models, to ensure consistency with the volumetric and other methods performed by Eni. The properties are all mature producing fields and it is GCA's opinion that performance-based methods are appropriate for the purposes of estimating remaining recoverable volumes and reserves. The audited proved gas volumes include gas consumed in operations as reserves. GCA has also performed an economic limit test to establish the economic limit and commerciality of the properties in aggregate.

Up to the economic limit, the GCA estimates of proved reserves for the reviewed properties are, in aggregate, reasonable and within 5.0 percent of Eni's estimates, when compared on the basis of net equivalent barrels.

The economic tests for the 31^st December, 2015 net proved reserves were based on a flat oil price of US$53.20 per barrel and a flat gas price of US$4.71/Mscf, based on an unweighted average of the first day of the month realized prices over the preceding 12 months, as per SEC rules. Future capital costs were derived from development plans prepared by Eni for the fields. Recent historical operating expense data were used as the basis for operating cost projections. GCA has reviewed Eni's estimates of capital and operating costs and considers them to be reasonable. Excluding abandonment costs, GCA has found that Eni has projected sufficient capital investments and operating expenses to economically produce the projected volumes.

It is GCA's opinion that the estimates of net proved reserves as of 31^st December, 2015, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission (see Appendix I).

GCA concludes that the methodologies employed by Eni in the derivation of the proved reserves estimates are appropriate, and that the quality of the data relied upon and the depth and thoroughness of the reserves estimation process are adequate.

Basis of Opinion

This document reflects GCA's informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation.

In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual

 

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outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by, or at the direction of, the Client, and has accepted the accuracy and completeness of this data. GCA has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience, engineering and production data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report's recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

There are numerous uncertainties inherent in estimating reserves, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves prepared by other parties may differ, perhaps materially, from those contained within this report.

The accuracy of any reserves estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

GCA's review and audit involved reviewing pertinent facts, interpretations and assumptions made by Eni or others in preparing estimates of reserves and resources. GCA performed procedures necessary to enable it to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied on, depth and thoroughness of the reserves estimation process, classification and categorization of reserves appropriate to the relevant definitions used, and reasonableness of the estimates.

Definition of Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce, or a revenue interest in, the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

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GCA is not aware of any potential changes in regulations applicable to these fields that could affect the ability of Eni to produce the estimated reserves.

GCA has not undertaken a site visit and inspection because it was not requested. As such, GCA is not in a position to comment on the operations or facilities in piace, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations. Further, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation.

This report has been prepared based on GCA's understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).

Qualifications

In performing this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector. GCA's remuneration was not in any way contingent on the contents of this report.

In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with Eni. Furthermore, the management and employees of GCA have no interest in any of the assets evaluated or related with the analysis performed, as part of this report. The qualifications of the technical person primarily responsible for overseeing this audit are provided in Appendix II.

Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.

 

 

 

 

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Notice

This report was prepared for public disclosure in its entirety in conjunction with filings to the SEC by Eni S.p.A.

Yours sincerely,
Gaffney, Cline & Associates

/s/ TONY GOODEARL

––––––––––––––––––––––––––––––––––

Project Manager
Tony Goodearl, Senior Petroleum Engineer

/s/ JOHN W BARKER

––––––––––––––––––––––––––––––––––

Reviewed by
Dr. John W Barker, Technical Director

 

 

Appendices

Appendix I SEC Reserves Definitions
Appendix II Technical Qualifications of Person Responsible for Audit

 

 

 

 

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Appendix I
SEC Reserves Definitions

 

 

 

 

 

 

 

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U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)
MODERNIZATION OF OIL AND GAS REPORTING¹

Oil and Gas Reserves Definitions and Reporting

 

(a) Definitions
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:
	(i)	Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
	(ii)	Same environment of deposition;
	(iii)	Similar geological structure; and
	(iv)	Same drive mechanism.
	Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
	(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
	(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

 

______________________

1 Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235-AK00].

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(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
	(i)	Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
	(ii)	Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
	(iii)	Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
	(iv)	Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
	(i)	Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
	(ii)	Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
	(iii)	Dry hole contributions and bottom hole contributions.
	(iv)	Costs of drilling and equipping exploratory wells.
	(v)	Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

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(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producin activities.

	(i)	Oil and gas producing activities include:
		(A)	The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
		(B)	The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
		(C)	The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
			(1)	Lifting the oil and gas to the surface; and
			(2)	Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
		(D)	Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
		Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
		a.	The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
		b.	In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
		Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
		(ii)	Oil and gas producing activities do not include:
			(A)	Transporting, refining, or marketing oil and gas;
			(B)	Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
			(C)	Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
			(D)	Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be

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recovered than probable reserves.
	(i)	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
	(ii)	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
	(iii)	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in piace than the recovery quantities assumed for probable reserves.
	(iv)	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
	(v)	Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
	(vi)	Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
	(i)	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
	(ii)	Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
	(iii)	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
	(iv)	See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19)Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter

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(from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
	(i)	Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
		(A)	Costs of labor to operate the wells and related equipment and facilities.
		(B)	Repairs and maintenance.
		(C)	Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
		(D)	Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
		(E)	Severance taxes.
	(ii)	Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
	(i)	The area of the reservoir considered as proved includes:
		(A)	The area identified by drilling and limited by fluid contacts, if any, and
		(B)	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
	(ii)	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
	(iii)	Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
	(iv)	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the

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		proved classification when:
		(A)	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
		(B)	The project has been approved for development by all necessary parties and entities, including governmental entities.
	(v)	Existing economie conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
	Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

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(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
	(i)	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
	(ii)	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
	(iii)	Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.

 

 

 

 

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Appendix II
Technical Qualifications of Person Responsible for Audit

 

 

 

 

 

 

 

 

 

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Statement of Qualification
Dr. John W. Barker

Dr. John Barker is a Technical Director with Gaffney, Cline & Associates (GCA) in the UK and was responsible for overseeing the preparation of the audit. Dr. Barker has over 30 years of international industry experience as a reservoir engineer, both in major oil companies and in consulting. He has worked on conventional oil, gas and gas condensate fields of all types in many different parts of the world, including naturally fractured reservoirs and enhanced oil recovery projects, and also on some tight gas and heavy oil fields. He is an acknowledged expert in all aspects of reservoir simulation and has extensive experience in estimation, auditing and reporting of reserves and resources.

Dr. Barker is a former Executive Editor of the SPE Reservoir Engineering journal, and has authored 34 technical publications, of which 20 have appeared in peer reviewed journals. He holds an M.A. in Mathematics from the University of Cambridge and a Ph.D. in Applied Mathematics from the California Institute of Technology. He is a member of the Society of Petroleum Engineers and of the Society of Petroleum Evaluation Engineers.

 

 

 

 

 

 

 

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