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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, 2014
OR
		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____ to _____
OR
		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report

Commission file number: 1-14090
——————————
Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy
(Address of principal executive offices)
Massimo Mondazzi
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
————————————————————
Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

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Certain disclosures contained herein including, without limitation, information appearing in "Item 4 – Information on the Company", and in particular "Item 4 – Exploration & Production", "Item 5 – Operating and Financial Review and Prospects" and "Item 11 – Quantitative and Qualitative Disclosures about Market Risk" contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the "SEC"). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled "Risk factors" and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.

 

CERTAIN DEFINED TERMS

In this Form 20-F, the terms "Eni", the "Group", or the "Company" refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to "Italy" or the "State" are references to the Republic of Italy, all references to the "Government" are references to the government of the Republic of Italy. For definitions of certain oil and gas terms used herein and certain conversions, see "Glossary" and "Conversion Table".

 

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolidated Financial Statements of Eni, included in this Annual Report, have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB).

Unless otherwise indicated, any reference herein to "Consolidated Financial Statements" is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.

Unless otherwise specified or the context otherwise requires, references herein to "dollars", "$", "U.S. dollars", "US$" and "USD" are to the currency of the United States, and references to "euro", "€" and "EUR" are to the currency of the European Monetary Union.

Unless otherwise specified or the context otherwise requires, references herein to "Division" and "segment" are to Eni’s business activities: Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction, Chemicals and Other activities.

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

 

STATEMENTS REGARDING COMPETITIVE POSITION

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

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GLOSSARY

A glossary of oil and gas terms is available on Eni’s web page at the address eni.com. Below is a selection of the most frequently used terms.

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

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

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

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ABBREVIATIONS

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

 

CONVERSION TABLE

 

 

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PART I

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

 

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE

 

Item 3. KEY INFORMATION

Selected Financial Information

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

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

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

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	Year ended December 31,

	2010		2011		2012		2013		2014

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

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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 2014 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2015.
(3)		Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/US$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2010 through 2013 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively.
		The dividend for 2014 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 1.12 per ADR) at the Noon Buying Rate recorded on the payment date on September 22, 2014, while the balance of euro 1.12 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2014. The balance dividend for 2014 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 20, 2015 to holders of Eni shares, being the ex-dividend date May 18, 2015, while ADRs holders will be paid on June 5, 2015.

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	As of December 31,

	2010		2011		2012		2013		2014

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

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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 2014 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2015.
(2)		Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/US$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2010 through 2013 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively. The dividend for 2014 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 1.12 per ADR) at the Noon Buying Rate recorded on the payment date on September 22, 2014, while the balance of euro 1.12 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2014. The balance dividend for 2014 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 20, 2015 to holders of Eni shares, being the ex-dividend date May 18, 2015, while ADRs holders will be paid on June 5, 2015.

 

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Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2010, 2011, 2012, 2013 and 2014.

	Year ended December 31,

	2010		2011		2012		2013		2014

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

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(1)		Includes approximately 767 BCF of natural gas held in storage in Italy as of December 31, 2010 and 2011.
(2)		Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (318, 321, 383, 451 and 442 mmCF/d in 2010, 2011, 2012, 2013 and 2014, respectively).
(3)		Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment including also royalties) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in "Item 18 – Notes on Consolidated Financial Statements".
(4)		Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in "Item 18 – Notes on Consolidated Financial Statements" for a calculation of results of operations from oil and gas producing activities.

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Selected Operating Information continued

	Year ended December 31,

	2010		2011		2012		2013		2014

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

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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	Expressed in euro million.
(7)	i	Relating to continuing operations for all periods presented.

 

Exchange Rates

The following tables set forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board)..

	High		Low		Average (1)		At period end

(U.S. dollars per euro)

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

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(1)

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

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	High		Low		At period end

(U.S. dollars per euro)

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

Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on March 31, 2015 was $1.08 per euro 1.00.

 

Risk factors

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

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

Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni’s control. These factors include among other things:

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

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

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

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

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

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

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

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

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Competition

There is strong competition worldwide, both within the oil industry and with other industries, to supply energy to the industrial, commercial and residential energy markets

Eni faces strong competition in each of its business segments.

In the current uncertain financial and economic environment, Eni expects that prices of energy commodities, in particular oil and gas, will be very volatile, with average prices and margins influenced by changes in the global supply and demand for energy, as well as in the market dynamics. This is likely to increase competition in all of Eni’s businesses, which may impact costs and margins. Competition affects license costs and product prices, with a consequent effect on our margins and our market shares. Eni’s ability to remain competitive requires continuous focus on technological innovation, reducing unit costs and improving efficiency. It is also depends on our ability to get an access to new investment opportunities, both in Europe and worldwide.

•		In the Exploration & Production segment, Eni faces competition from both international and state-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage because of its relatively smaller size compared to other international oil companies, particularly when bidding for large scale or capital intensive projects, and may be exposed to industry-wide cost increases to a greater extent compared to its larger competitors given its potentially smaller market power with respect to suppliers. If, as a result of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control costs, its growth prospects and future results of operations and cash flows may be adversely affected.
•		In the Gas & Power segment, Eni faces strong competition from gas and energy players to sell gas to the industrial segment, the thermoelectric sector and the retail customers both in the Italian market and in markets across Europe. Competition has been fuelled by ongoing weak trends in demand due to the downturn and macroeconomic uncertainties, oversupplies which have been supported by large availability of liquefied natural gas ("LNG") on global scale, and inter-fuel competition due to rising use of coal in firing power plants due to cost advantages and a dramatic growth in the adoption of renewable sources of energy (photovoltaic and solar) which have materially impacted the use of gas in the production of electricity and hence sales of gas to the thermoelectric industry. The extensive development of shale gas in the United States was another fundamental trend that aggravated the oversupply situation in Europe. The continuing growth in the production of shale gas in the United States increased global gas supplies.
		These market imbalances in Europe were exacerbated by the fact that throughout the last decade and up to a few years ago the market consensus projected that gas demand in the continent would grow steadily till 2020 and beyond driven by economic growth and increased use of gas in firing power production. European gas wholesalers including Eni committed well in advance to purchasing large amounts of gas under long-term supply contracts with so-called "take-or-pay" clauses from the main producing countries bordering Europe (namely Russia and Algeria) and invested heavily to upgrade existing pipelines and to build new infrastructure along several European routes in order to expand gas import capacity to continental markets. Long-term gas supply contracts with take-or-pay clauses expose gas wholesalers to a volume risk as they are contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price. Due to the trends described above of the prolonged economic downturn and inter-fuel competition, the projected increases in gas demand failed to materialize, resulting in a situation of oversupply and pricing pressure. As demand contracted across Europe, gas supplies built, thus driving the development of very liquid continental hubs to trade spot gas. Spot prices at continental hubs became the main benchmarks to which selling prices are indexed in supplies to large industrial customers and thermoelectric utilities. The profitability of gas operators was negatively impacted by falling sales prices at those hubs, where prices have been pressured by intense competition among gas operators in the face of weak demand, oversupplies and the constraint to dispose of minimum annual volumes of gas to be purchased under long-tem supply contracts. We believe that those headwinds have become structural ones and therefore we do not expect any meaningful improvement in the European gas sector for the foreseeable future. Gas demand will remain weak due to macroeconomic uncertainties and unclear EU policies regarding how to satisfy energy demand in Europe and the energetic mix. Supplies at continental hubs will continue building up also in view of a possible ramp-up of LNG exports from the United States due to steady growth in gas production and ongoing projects to reconvert LNG re-gasification facilities into liquefaction export units and the start of several LNG projects in the Pacific Region and elsewhere.
		We believe that these ongoing negative trends may adversely affect the Company’s future results of operations and cash flows, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of gas in accordance to its long-term gas supply contracts with take-or-pay clauses.
•		In its Gas & Power segment, Eni is vertically integrated in the production of electricity via its gas-fired power plants which currently use the combined-cycle technology. In the electricity business, Eni competes with other producers and traders from Italy or outside of Italy who sell electricity on the Italian market. Going forward, the Company expects continuing competition due to the projections of weak economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production in the Italian market. The economics of the gas-fired electricity business have dramatically changed over the last

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

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Safety, security, environmental and other operational risks

The Group engages in the exploration and production of oil and natural gas, processing, transportation, and refining of crude oil, transport of natural gas, storage and distribution of petroleum products, production of base chemicals, plastics and elastomers. By their nature the Group’s operations expose Eni to a wide range of significant health, safety, security and environmental risks. The magnitude of these risks is influenced by the geographic range, operational diversity and technical complexity of Eni’s activities. Eni’s future results from operations and liquidity depend on its ability to identify and mitigate the risks and hazards inherent to operating in those industries.

In Exploration & Production, Eni faces natural hazards and other operational risks including those relating to the physical characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni’s personnel and risks of blowout, fire or explosion. Accidents at a single well can lead to loss of life, damage or destruction to property, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operation, liquidity, reputation and prospects of the Group.

Eni’s activities in the Refining & Marketing and Chemical segments also entail health, safety and environmental risks related to the overall life cycle of the products manufactured, and to raw materials used in the manufacturing process, such as oil-based feedstock, catalysts, additives and monomer feedstock. These risks can arise from the intrinsic characteristics of the products involved (flammability, toxicity, or long-term environmental impacts such as greenhouse gas emissions and risks of various forms of pollution and contamination of the soil and the groundwater), their use, emissions and discharges resulting from their manufacturing process, and from recycling or disposing of materials and wastes at the end of their useful life.

All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend both on the hazardous nature of the products transported, and on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road, gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, could present a significant risk to people and the environment.

The Company invests significant resources in order to upgrade the methods and systems for safeguarding the safety and health of employees, contractors and communities, and the environment; to prevent risks; to comply with applicable laws and policies; and to respond to and learn from unexpected incidents. Eni seeks to minimize these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and distribution networks, and managing its operations in a safe, compliant and reliable manner. Failure to manage these risks could effectively result in unexpected incidents, including releases or oil spills, blowouts, fire, mechanical failures and other incidents resulting in personal injury, loss of life, environmental damage, legal liabilities and/or damage claims, destruction of crude oil or natural gas wells, as well as damage to equipment and other property, all of which could lead to a disruption in operations. Eni’s operations are often conducted in difficult and/or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic. In such locations, the consequences of any incident could be greater than in other locations. Eni also faces risks once production is discontinued, because Eni’s activities require decommissioning of productive infrastructure and environmental site remediation.

Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.

Eni’s insurance subsidiary provides insurance coverage to Eni’s entities, generally up to $1.1 billion in case of offshore incident and $1.5 billion in case of incident at onshore facilities (refineries). In addition, the Company also maintains worldwide third-party liability insurance coverage for all of its subsidiaries. Management believes that its insurance coverage is in line with industry practice and sufficient to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster like BP Deepwater Horizon, for example, Eni’s third-party liability insurance would not provide any material coverage and thus the Company’s liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in the event of such a disaster would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster.

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

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

 

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

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

 

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

Eni has material operations relating to the exploration and production of hydrocarbons located offshore. In 2014, approximately 55% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Norway, Italy, Angola, the Gulf of Mexico, Congo, United Kingdom and Nigeria. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. As the Macondo accident in the Gulf of Mexico has shown, the potential impacts of offshore accidents and spills to health, safety, security and the environment can be catastrophic due to the objective difficulties in handling hydrocarbons containment and other factors. Further, offshore operations are subject to marine risks, including severe storms and other adverse weather conditions and vessel collisions, as well as interruptions or termination by governmental authorities based on safety, environmental and other considerations. Failure to manage these risks could result in injury or loss of life, damage to property, environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to Eni’s reputation and could have a material adverse effect on Eni’s operations, results, liquidity, reputation and prospects.

 

(ii) Exploratory drilling efforts may be unsuccessful

Exploration drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells have margins of uncertainty, and drilling operations may be unsuccessful as a result of a large variety of factors, including geological play failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents, and shortages or delays in the delivery of equipment. The Company also engages in exploration drilling activities offshore, also in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea). In these locations, the Company generally experiences more challenging conditions and incurs higher exploration costs than onshore or in shallow waters. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to make investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Some of these activities are high-risk high reward projects that generally involve sizeable plays located in deep and ultra-deep waters or at higher depths where operations are more challenging and costly than in other areas. Furthermore, deep and ultra-deep water operations will require significant time before commercial production of discovered reserves can commence, increasing both the operational and financial risks associated with these activities. The Company plans to conduct exploration projects offshore West Africa (Angola, Nigeria, Congo, and Gabon), East Africa (Mozambique, Kenya and South Africa), South-East Asia (Indonesia, Vietnam, Myanmar and other locations), Australia, the Norwegian Barents Sea, the Mediterranean and offshore Gulf of Mexico. In 2014, the Company spent euro 1.4 billion to conduct exploration projects and plans to spend approximately euro 1.2 billion on average in the next four-year plan on exploration activities. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas which is highly dependent on the rate of success of exploratory program.

 

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

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

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•		the outcome of negotiations with co-venturers, governments and state-owned companies, suppliers, customers or others, including, for example, Eni’s ability to negotiate favorable long-term contracts to market gas reserves;
•		the development of reliable spot markets that may be necessary to support the development of particular production projects, or commercial arrangements for pipelines and related equipment to transport and market hydrocarbons;
•		timely issuance of permits and licenses by government agencies;
•		the Company’s relative size compared to its main competitors which may prevent it from participating in large-scale projects or affect its ability to reap benefits associated with economies of scale, for example by obtaining more favorable contractual terms by suppliers of equipment and services;
•		the ability to carefully carry out front-end engineering design so as to prevent the occurrence of technical inconvenience during the execution phase;
•		timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; these events may cause cost overruns and delays impacting the time-to-market of the reserves;
•		risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
•		poor performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) – turn key contractual scheme. Eni believes this kind of risk may be due to lack of contractual flexibility, poor quality of front-end engineering design and commissioning delays;
•		changes in operating conditions and cost overruns. In recent years, the industry has been adversely impacted by the growing complexity and scale of projects which drove cost increases and delays, including higher environmental and safety costs. Due to the recent downtrend in crude oil prices, the Company will seek to renegotiate construction contracts, daily rates for rigs and other field services and costs for materials and other productive factors to preserve margins at its development projects. In case it fail to obtaining the planned cost reductions, its profitability in the Exploration & Production segment could be adversely affected;
•		the actual performance of the reservoir and natural field decline; and
•		the ability and time necessary to build suitable transport infrastructures to export production to final markets.

Events such as the ones described above of poor project execution, inadequate front-end engineering design, delays in the achievement of critical events and project milestones, delays in the delivery of production facilities and other equipment by third parties, differences between scheduled and actual timing of the first oil, as well as cost overruns may adversely affect the economic returns of Eni’s development projects. Failure to successfully deliver major projects on time and on budget could negatively impact results of operations, cash flow and the achievement of short-term targets of production growth. Finally, development and marketing of hydrocarbons reserves typically require several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commercial potential, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long-lead-time projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from the prices and costs assumed when the investment decision was actually made, leading to lower rates of return. In addition, projects executed with partners and co-venturers reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations and performance of its partners. Furthermore, Eni may not have full operation control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operation and strategic objectives due to the nature of its relationships.

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

Finally, in case the Company is unable to develop and operate major projects as planned, particularly if the Company fails to accomplish budgeted costs and time schedules, it could incur significant impairment charges of capitalized costs associated with reduced future cash flows of those projects.

 

(iv) Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition

Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. Unless the Company is able to replace produced oil and natural gas, its reserves will decline. In addition to being a function of production, revisions and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its PSAs and similar contractual schemes. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved

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reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The opposite occurs incase of lower oil prices. Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with national oil companies and other entities owners of known reserves and acquisitions. In a number of reserve-rich countries, national oil companies decide to develop portion of oil and gas reserves that remain to be developed. To the extent that national oil companies decide to develop those reserves without the participation of international oil companies or if the Company fails to establish partnership with national oil companies, Eni’s ability to access or develop additional reserves will be limited.

An inability to replace produced reserves by finding, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of production growth and reserve replacement, Eni’s future total proved reserves and production will decline and this will negatively affect future results of operations and liquidity.

 

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

The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. Following the Macondo accident in the Gulf of Mexico, governments throughout the world have enacted stricter regulations on environmental protection, risk prevention and other forms of restrictions to drilling and other well operations. These new regulations and legislation, as well as evolving practices, increase the burden of compliance costs by requiring industry participants to adopt new security and risk prevention measures and procedures. They may also require changes to Eni’s drilling operations and exploration and development plans and may lead to higher royalties and taxes.

 

(vi) Uncertainties in estimates of oil and natural gas reserves

Several uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of proved reserve estimates depend on a number of factors, assumptions and variables, among which the most important are the following:

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

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

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

Many of these factors, assumptions and variables involved in estimating proved reserves are subject to change over time therefore impacting the estimates of oil and natural gas reserves. Accordingly, the estimated reserves reported as of the end of the period covered by this filing could be significantly different from the quantities of oil and natural gas that will ultimately be recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition.

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

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

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

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

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

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

 

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

Investors should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. In accordance with U.S. SEC rules, we base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the U.S. SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:

•		the actual prices we receive for sales of crude oil and natural gas;
•		the actual cost and timing of development and production expenditures;
•		the timing and amount of actual production; and
•		changes in governmental regulations or taxation.

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

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

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

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Political considerations

A substantial portion of Eni’s oil and gas reserves and gas supplies are located in countries where the socio-political framework and macroeconomic outlook is less stable than those of the OECD countries. In those less stable countries Eni is exposed to a wide range of risks and uncertainties which could materially impact the ability of the Company to conduct its operations in a safe, reliable and profitable manner. As of December 31, 2014, approximately 79% of Eni’s proved hydrocarbon reserves were located in such countries and 60% of Eni’s supplies of natural gas derived from non-OECD countries.

Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions, inflation levels, exchange rates and similar events in any of those less stable countries may negatively affect Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues:

(i)		lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
(ii)		unfavorable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriations, nationalizations or forced divestitures of assets and unilateral cancellation or modification of contractual terms. Eni is facing increasing competition from state-owned oil companies who are partnering Eni in a number of oil and gas projects and properties in the host countries where Eni conducts its upstream operations. These state-owned oil companies can change contractual terms and other conditions of oil and gas projects in order to obtain a larger profit share from a given project, thereby reducing Eni’s profit share. Furthermore, as of the balance sheet date receivables for euro 663 million relating to cost recovery under certain petroleum contracts in a non-OECD country were the subject of an arbitration proceeding;
(iii)		restrictions on exploration, production, imports and exports;
(iv)		tax or royalty increases (including retroactive claims); and
(v)		political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar incidents. These risks could result in disruptions in economic activity, loss of output, plant closures and shutdowns, project delays, the loss of personnel or assets. They may force Eni to evacuate personnel for security reasons and to increase spending on security worldwide. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographic areas in which Eni operates. Areas where Eni operates where the Company is exposed to the political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Indonesia, Kazakhstan, Venezuela, Iraq, Iran and Russia. In addition, any possible reprisals as a consequence of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on Eni’s business, consolidated results of operations, and consolidated financial condition. In recent years, Eni’s production levels in Libya were negatively impacted by acts of local conflict, social unrest, protests, strikes, which forced Eni to temporarily interrupt or reduce its producing activities, negatively affecting Eni’s results of operations and cash flow. Also Eni’s activities in Nigeria have been impacted in recent years by continuing episodes of theft, acts of sabotage and other similar disruptions which have jeopardized the Company’s ability to conduct operations in full security, particularly in the onshore area of the Niger Delta. Looking forward, Eni expects that those risks will continue to affect Eni’s operations in those countries. Particularly, the uncertain socio-political outlook in Libya and unsafe operational conditions onshore Nigeria were factored in the Company’s projections of future production levels in these two countries. For more information about the status of Eni’s operations in Libya see “Risks associated with continuing political instability in North Africa and the Middle East” below.

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

There are certain instances where Eni is contractually obligated to finance the share of costs of the first party. This risk is mitigated by the customary default clause which states that in case of a default, the non-defaulting party is entitled to compensate its claims with the share of production of the defaulting party.

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

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

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

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

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

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

 

Risks associated with Eni’s presence in sanction targets

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

 

United States measures towards Iran

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

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

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

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

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

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

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

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

 

European Union restrictive measures towards Iran

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

 

Risks in the Company Gas & Power business

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

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

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

 

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

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

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

 

Current, negative trends in gas demands and supplies may impair the Company’s ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts

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

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

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

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

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

 

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

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

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

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

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

 

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

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

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

 

Antitrust and competition law

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

 

Environmental, health and safety regulations

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

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, refining, chemicals, hydrocarbons transportation and other activities. Generally, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining, petrochemical and other Group’s operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace and health of communities involved by the Company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees’ or communities’ health and safety resulting from oil, natural gas, refining, petrochemical and other Group’s operations.

These laws and regulations also regulate emissions of substances and pollutants, handling of hazardous materials and discharges to surface and subsurface of water resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials.

Breach of environmental, health and safety laws expose the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage, as well as damage to its reputation. Additionally, in the case of violation of certain rules regarding the safeguard of the environment and safety in the workplace, the Company can be liable for negligent or willful conduct on part of its employees as per Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations addressing the safeguard of the environment, safety on the workplace, health of employees, contractors and communities involved by the Company operations, including:

•		costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change;
•		remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below);
•		damage compensation claimed by individuals and entities, including local, regional or state administrations, in case Eni causes any kind of accident, pollution, contamination or other environmental liability involving its operations or the Company is found guilty of violating environmental laws and regulations; and
•		costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging.

 

Furthermore, in the countries where Eni operates or expects to operate in the near future, new laws and regulations, the imposition of tougher license requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause Eni to incur material costs resulting from actions taken to comply with such laws and regulations, including:

•

modifying operations;

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

As a further result of any new laws and regulations or other factors, Eni may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish Eni’s productivity and materially and adversely impact Eni’s results of operations, including profits. Security threats require continuous assessment and response measures. Acts of terrorism against Eni’s plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

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

Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for oil and natural gas and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which Eni conducts business. Because Eni’s business depends on the global demand for oil and natural gas, existing or future laws, regulations, treaties, or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on Eni’s business if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon dioxide that could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

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

Eni has incurred in the past and may incur in the future material environmental provisions in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. In Italy, environmental requirements and regulations typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, natural resource damages, and other damages as a result of Eni’s conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Also plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found guilty of having violated any environmental laws or regulations.

Eni is periodically notified of potential liabilities at Italian sites. These potential liabilities may arise from both historical Eni operations and the historical operations of companies that Eni has acquired. Many of those potential liabilities relate to certain industrial sites that the Company disposed of, liquidated, closed or shut down in prior years where Group products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities. At those industrial locations Eni has commenced a number of initiatives to restore and clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. Notwithstanding the Group’s position that it cannot be held liable for contaminations occurred in past years or (as permitted by applicable regulations in case of declaration rendered by a guiltless owner i.e. as a result of Eni’s conduct that was lawful at the time it occurred) or because Eni took over operations from third parties, nonetheless several public administrations used Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company.

Eni expects remedial and clean-up activities at Eni’s sites to continue in the foreseeable future impacting Eni’s liquidity. As of December 31, 2014, the Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amounts represent the management’s best estimates of the Company’s liability.

Management believes that it is possible that in the future Eni may incur significant environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of as yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain of Eni’s industrial sites as

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required by the applicable regulations on contaminated sites; (iii) unfavorable developments in ongoing litigation on the environmental status of certain of the Company’s sites where a number of public administrations and the Italian Ministry of the Environment act as plaintiffs; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites.

As a result of those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

 

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

Eni is the defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of December 31, 2014 to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to the amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate.

Certain legal proceedings where Eni or its subsidiaries or its officers are parties involve the alleged breach of anti-corruption laws and regulations and ethical misconduct. Ethical misconduct and non-compliance with applicable laws and regulations, including non-compliance with anti-bribery and anti-corruption laws, by Eni, its partners, agents or others that act on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation and shareholder value.

 

Risks from acquisitions

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

 

Risks deriving from Eni’s exposure to weather conditions

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

 

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

Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed time frame could prolong the impact of any disruption and could severely affect business and operations. Likewise, Eni has crisis management plans and capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, its business and operations could be severely disrupted.

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Exposure to financial risk

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

Eni’s primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil and gas reserves, volume of gas purchased under its long-term gas purchase contracts which are not covered by contracted sales, its refining margins and other activities. The Group’s risk management objectives in addressing commodity risk are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. To achieve this, Eni engages in risk management activities seeking both to hedge Group’s exposures and to profit from short-term market opportunities and trading. The Group’s risk management has evolved particularly in response to the major changes which have occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid gas spot markets.

Eni is engaged in substantial trading and commercial activities in the physical markets. Eni also uses financial instruments such as futures, options, Over The Counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage the commodity risk exposure. Eni also uses financial instruments to manage foreign exchange and interest rate risk.

The Group’s approach to risk management includes identifying, evaluating and managing the financial risk using a top-down approach whereby the Board of Directors is responsible for establishing the Group risk management strategy and setting the maximum tolerable amounts of risk exposure. The Group’s Chief Executive Officer is responsible for implementing the Group risk management strategy, while the Group’s Chief Financial and Risk Management Officer is in charge of defining policies and tools to manage the Group’s exposure to financial risk, as well as monitoring and reporting activities.

Various Group committees are in charge of defining internal criteria, guidelines and targets of risk management activities consistent with the strategy and limits defined at Eni’s top level, to be used by the Group’s business units, including monitoring and controlling activities. Although Eni believes it has established sound risk management procedures, trading activities involve elements of forecasting and Eni is exposed to the risks of market movements, of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.

 

Commodity risk

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

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

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

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

 

Exchange rate risk

Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni’s results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to, U.S. dollars, while a significant portion of Eni’s expenses are denominated in euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the Chemical segment are denominated both in euros and U.S. dollars. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact

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on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity. The Exploration & Production segment is particularly affected by movements in the U.S. dollar versus the euro exchange rates as the U.S. dollar is the functional currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations. In 2014, the Exploration & Production results of operations were marginally affected by trends in exchange rate of the euro against the U.S. dollar as the average exchange rate for the full year was substantially flat at 1 EUR = 1.33 US$. However, the decline of the euro against the U.S. dollar in the fourth quarter 2014 resulted in a appreciation of approximately 12% of the U.S. dollar at the closing rate on December 31, 2014 with respect to the closing rate at December 31, 2013 which movements boosted the Group net equity by approximately euro 5 billion as a result of the translation differences of the net assets of dollar-denominated subsidiaries. This trend has continued in the first quarter of 2015.

 

Susceptibility to variations in sovereign rating risk

Eni’s credit ratings are potentially exposed to risk in reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the Notes or other debt instruments issued by the Company could be downgraded.

 

Interest rate risk

Interest on Eni’s debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, "Euribor", and the London Interbank Offered Rate, "Libor". As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its debt. Additionally, spreads offered to the Company may rise in connection with variations in sovereign rating risks or company rating risks, as well as the general conditions of capital markets.

 

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively impact the Group results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. European and global financial markets are currently subject to volatility amid concerns over the European sovereign debt crisis and weak macroeconomic growth, particularly in the Euro-zone. If there are extended periods of constraints in the financial markets, or if Eni is unable to access the financial markets (including cases where this is due to Eni’s financial position or market sentiment as to Eni’s prospects) at a time when cash flows from Eni’s business operations may be under pressure, Eni’s ability to maintain Eni’s long-term investment program may be impacted with a consequent effect on Eni’s growth rate, and may impact shareholder returns, including dividends or share price.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation and production of oil and natural gas reserves.

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

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

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

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•

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

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

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

 

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In recent years, the Group has experienced a higher than normal level of counterparty default due to the severity of the economic and financial downturn and the amount of trade receivables overdue at the balance sheet date has increased significantly. In Eni’s 2014 Consolidated Financial Statements, Eni accrued an allowance against doubtful accounts amounting to euro 531 million (compared to euro 384 million), mainly relating to the Gas & Power business. Management believes that this business is particularly exposed to credit risks due to its large and diversified customer base which include a large number of medium and small sized businesses and retail customers who have been particularly impacted by the financial and economic downturn. However, trade receivable amounts due at the balance sheet date have also increased in relation to supplies of the Group’s products to state-owned companies, public administrations and other governmental agencies in Italy and abroad. Eni believes that the management of doubtful accounts represents an issue to the Company which will require management focus and commitment going forward. In the future we cannot exclude the recognition of significant provisions for doubtful accounts.

 

Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience and other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and other risk provisions and recognition of revenues in the oilfield services construction and engineering businesses. Although management believes these estimates to represent the best outcome of the estimation process, actual results could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information, availability of new informative elements, variations in economic conditions such as prices, costs, other significant factors including evolution in technologies, industrial practices and standards (e.g. removal technologies) and the final outcome of legal, environmental or regulatory proceedings.

 

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

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

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protect digital infrastructure could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

 

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

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

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

 

 

 

 

 

 

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Item 4. INFORMATION ON THE COMPANY

History and development of the Company

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

Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders.

Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in:

Internet address: eni.com

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

Eni’s principal segments of operations are described below.

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

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

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

Eni also engages in commodity risk management and asset-backed trading activities. Through the trading department of the parent company and its wholly-owned subsidiary Eni Trading & Shipping SpA, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. The objective of this activity is both to hedge part of the Group exposure to the commodity risk and to optimize commercial margins by entering speculative derivative transactions. Eni Trading & Shipping SpA and its subsidiaries also provide Group companies with crude oil and products supply, trading and shipping services. The results of the activity of commodity risk management and other services are reported within the Gas & Power segment with regard to the results on commodity risk management activities relating to gas and electricity; while the portion of results which pertains to oil and products trading derivatives and supply and shipping services are reported within the Refining & Marketing segment.

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

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

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

 

Strategy

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

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

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

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

For a description of risks and uncertainties associated with the Company’s outlook, and the capital expenditure program see "Item 5 – Operating and financial review and prospects – Management’s expectations of operations".

 

Significant business and portfolio developments

The significant business and portfolio developments that occurred in 2014 and to date in 2015 were the following:

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

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

In addition, Eni closed the following transactions:

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

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

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

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

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

 

 

BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 40 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2014, Eni average daily production amounted to 1,517 KBOE/d on an available-for-sale basis. As of December 31, 2014, Eni’s total proved reserves amounted to 6,602 mmBOE; proved reserves of subsidiaries totaled 5,772 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 830 mmBOE.

Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth by developing its portfolio of projects underway and by optimizing its current producing fields. We plan to achieve a production growth rate of 3.5% on average in the next 2015-2018 four-year period, based on our long-term Brent price assumptions of 90 $/BBL and certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under "Item 5 – Management’s expectations of operations".

Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations, including North Africa, Sub-Saharan Africa, Barents Sea, Kazakhstan, Venezuela and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. We plan to start 16 new large fields over the next four years which will contribute more with than 650 KBOE/d of new production by 2018; about 90% of these new projects have already been sanctioned and 84% operated.

Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion and reducing facilities downtime. This will require intense development activities of work-over and infilling and careful planning of maintenance activities. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery.

Management plans to invest some euro 36 billion to develop reserves over the next four years, with a decrease of 12% net of exchange rate effects versus the previous four-year plan to mitigate the impact of a low oil price environment. We plan to prioritize lower intensity projects, brown-field developments and infilling wells mainly in Congo, Angola and Egypt, while we plan to re-schedule spending in some large projects. This re-scheduling will account for half of the overall reduction, while the remaining will be determined by contracts renegotiations.

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

Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight control on project time schedules and costs and reducing the time span which is necessary to develop and market reserves. We plan to achieve efficient development of our reserves by: (i) in-sourcing critical engineering and project management activities also redeploying to other areas key competences which will be freed with the start-up of certain strategic projects and increase direct control and governance on construction and commissioning activities; and (ii) signing framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows. Based on these initiatives we believe that almost all of our project which we are currently developing over the next four-year plan will be completed on time and on cost schedule.

Finally we plan to achieve further cost efficiencies by: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; (ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; (iii) applying our technologies which we believe can reduce drilling and completion costs; and (iv) renegotiating contracts for oilfield services and other items to reap the benefits of the deflationary trend in the industry.

We plan to mitigate the operational risk relating to drilling activities by applying Eni’s rigorous procedures throughout the engineering and execution stages, by leveraging on proprietary drilling technologies, excellent skills and know-how, increased control of operations and by deploying technologies which we believe to be able to reduce blow-out risks and to enable the Company to respond quickly and effectively in case of emergencies.

For the year 2015, management plans to spend over euro 10 billion in reserves development and exploration projects.

 

Disclosure of reserves

Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil and gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

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

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

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

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Reserves governance

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

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

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

The head of the Reserves Department attended the "Politecnico di Torino" and received a Master of Science degree in Mining Engineering in 1985. She has more than 25 years of experience in the oil and gas industry and more than 15 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.

 

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation² of part of its proved reserves on a rotational basis. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report³. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.

In order to calculate the economic value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third-party evaluators. In 2014, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 27% of Eni’s total proved reserves at December 31, 2014⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation⁵.

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

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Summary of proved oil and gas reserves

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

HYDROCARBONS (mmBOE)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total reserves

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

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LIQUIDS (mmBBL)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total reserves

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

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NATURAL GAS (BCF)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total reserves

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

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

	Subsidiaries		Equity-accounted entities

	2012		2013		2014		2012		2013		2014

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

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(a)

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

	Subsidiaries and equity-accounted entities

	2012		2013		2014

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

113

(7)

112

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

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

Price effects were negligible, leading to an upward revision of 33 mmBOE, due to a lowered Brent price used in the reserve estimation process down to 101 $/BBL in 2014 compared to 108 $/BBL in 2013. Further information about how to determine year-end amounts of proved reserves and the relevant net present value is provided in “Item 3 – Risk factors – Risks associated with the exploration and production of oil and natural gas”.

The methods (or technologies) used in the Eni’s proved reserves assessment in 2014 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modeling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However, for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates.

The all sources reserves replacement ratio achieved by Eni’s subsidiaries and equity-accounted entities was 112% in 2014 (negative in 2013 and 113% in 2012). The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities - Oil & Gas (Topic 932) (see "Item 18 – Supplemental oil and gas information – of the Notes on Consolidated Financial Statements"). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserves replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, as well as changes in oil and gas prices, political risks, geological, reservoir performance and environmental risks. See "Item 3 – Risks associated with the exploration and production of oil and natural gas and Uncertainties in estimates of oil and natural gas reserves".

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

 

Eni’s subsidiaries

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

 

Eni’s share of equity-accounted entities

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

 

Proved undeveloped reserves

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

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

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

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

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

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

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

 

Delivery commitments

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

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 331 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria and Norway.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 77% of delivery commitments.

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

 

Oil and gas production, production prices and production costs

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

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

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

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

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

Oil and gas production sold amounted to 549.5 mmBOE. The 4.3 mmBOE difference over production on an available-for-sale basis (553.8 mmBOE) reflected mainly changes in inventories and other factors. Approximately 62% of liquids production sold (299.8 mmBBL) was destined to Eni’s Refining & Marketing segment (of which 23% was processed in Eni’s refineries). About 27% of natural gas production sold (1,371 BCF) was destined to Eni’s Gas & Power segment.

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

2012 Production available for sale (a)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

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

---

(a)

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

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2013 Production available for sale (a)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

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

---

(a)

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

 

2014 Production available for sale (a)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

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

---

(a)

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

Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 78 KBOE/d, 67 KBOE/d and 78 KBOE/d in 2014, 2013 and 2012, respectively.

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

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AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

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

Development activities

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

The table below summarizes the number of the Company’s net interests in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2014. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

DEVELOPMENT WELL ACTIVITY

		Net wells completed		Wells in progress at Dec. 31,

		2012		2013		2014		2014

(units)

Productive

Dry

Productive

Dry

Productive

Dry

Gross

Net

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

Exploration activities

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

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

The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2014. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

EXPLORATORY WELL ACTIVITY

		Net wells completed		Wells in progress at Dec. 31, (1)

		2012		2013		2014		2014

(units)

Productive

Dry

Productive

Dry

Productive

Dry

Gross

Net

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

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(1)

Includes temporary suspended wells pending further evaluation.

Oil and gas properties, operations and acreage

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

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

The table below provides certain information about the Company’s oil and gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2014. A gross acreage is one in which Eni owns a working interest.

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	December 31, 2013		December 31, 2014

Total net acreage (a)

Number of interests

Gross developed acreage (a) (b)

Gross undeveloped acreage (a)

Total gross acreage (a)

Net developed acreage (a) (b)

Net undeveloped acreage (a)

Total net acreage (a)

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

---

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

The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2014. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same bore hole are counted as one well. Productive wells are producing wells and

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

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

		Oil wells		Natural gas wells

(units)		Gross		Net		Gross		Net

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

---

(a)

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

Eni’s principal oil and gas properties are described below. In the discussion that follows, references to hydrocarbon production are intended to represent hydrocarbon production available for sale.

Italy

Eni has been operating in Italy since 1926. In 2014, Eni’s oil and gas production amounted to 171 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic and Ionian Sea, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley. Eni’s exploration and development activities in Italy are regulated by concession contracts (54 operated onshore and 64 operated offshore) and exploration licenses (12 onshore and 9 offshore).

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

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

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

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

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

Rest of Europe

Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the United Kingdom. In 2014, the Rest of Europe accounted for 12% of Eni’s total worldwide production of oil and natural gas.

Croatia. Eni has been present in Croatia since 1996. In 2014, Eni’s production of natural gas averaged 36 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula.

Exploration and production activities in Croatia are regulated by PSAs.

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

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

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

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

Eni currently holds interests in 10 production areas in the Norwegian Sea. The principal producing fields are Åsgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.17%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2014 accounted for 74% of Eni’s production in Norway.

Eni holds interests in 2 production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018, which in 2014 produced approximately 24 KBOE/d net to Eni and accounted for 21% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.

Eni is currently performing exploration and development activities in the Barents Sea. Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest). The license expires in 2042. Start-up is expected in the second half of 2015, with a production plateau at approximately 65 KBOE/d net to Eni in 2016.

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

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

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

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

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During the year Eni was awarded the operatorship of the 22/19c (Eni’s interest 50%), 22/19e (Eni’s interest 57.14%) and 30/1b (Eni’s interest 100%) exploration blocks in the North Sea. In April 2014, Eni completed the acquisition of the Liverpool Bay assets (Eni’s interest 100%). Eni currently holds interests in 5 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other fields are Elgin/Franklin (Eni’s interest 21.87%), J Block and Jasmine (Eni’s interest 33%), Jade (Eni’s interest 7%) and MacCulloch (Eni’s interest 40%), which in 2014 accounted for 66% of Eni’s production in the United Kingdom. Development activities mainly concerned: (i) production start-up of the West Franklin field (Eni’s interest 21.87%) with the completion of the Phase 2 development program by means of the installation of production platform and pipeline connection to the treatment facility in the area; and (ii) production ramp-up of the Jasmine project with the completion of commissioning and start-up of 4 additional production wells. Exploration activities yielded positive results with the Romeo North discovery, already linked to the production platform of the Jade field.

North Africa

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

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

Operated and participated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the Country: (i) blocks 403a/d (Eni’s interest from 65% to 100%); (ii) block Rom North (Eni’s interest 35%); (iii) blocks 401a/402a (Eni’s interest 55%); (iv) blocks 403 (Eni’s interest 50%); (v) block 405b (Eni’s interest 75%); and (vi) block 212 (Eni’s interest 22.38%) with discoveries already made. In addition Eni holds interest in the non-operated block 404 and block 208 with a 12.25% stake. Exploration and production activities in Algeria are regulated by PSAs and concession contracts. Production in blocks 403a/d and Rom North comes mainly from the HBN and Rom and satellites fields and represented approximately 20% of Eni’s production in Algeria in 2014. Production in blocks 401a/402a comes mainly from the ROD/SFNE and satellite fields and accounted for approximately 14% of Eni’s production in Algeria in 2014. The main fields in block 403 are BRN, BRW and BRSW which accounted for approximately 11% of Eni’s production in Algeria in 2014.

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The main fields in block 404 are HBN and HBNS and satellites which accounted for approximately 25% of Eni’s production in Algeria in 2014. Production in block 405b comes mainly from MLE-CAFC project and accounted for approximately 15% of Eni’s production in the Country in 2014. Development and optimization activities progressed at the MLE-CAFC project. Activities include an additional oil phase with start-up expected in 2017, targeting a production plateau of approximately 33 KBOE/d net to Eni. The El-Merk field is the main production project in the block 208 and accounted for approximately 15% of Eni’s production in Algeria in 2014. Production ramp-up was completed in the year with a production plateau target of approximately 18 KBOE/d net to Eni. Eni was granted three prospection permits in the Timimoun and Oued Mya areas, in Southern onshore Algeria. The agreements expire in two years and cover a total acreage of 46,837 square kilometers. The program includes studies and drilling of prospection wells to assess the mineral potential. Egypt. Eni has been present in Egypt since 1954. In 2014, Eni’s share of production in this Country amounted to 195 KBOE/d and accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Meleiha (Eni’s interest 76%) and the Ras Qattara (Eni’s interest 75%) concessions. Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (Eni’s interest 50%), Baltim (Eni’s interest 50%) and Ras el Barr (Eni’s interest 50%, non operated), located offshore the Nile Delta. In 2014, production from these large concessions accounted for approximately 94% of Eni’s production in Egypt.

Exploration and production activities in Egypt are regulated by PSAs.

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

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

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

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

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

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Libya. Eni started operations in Libya in 1959. The internal situation in Libya continues to represent an issue to Eni’s management. Following the internal conflict of 2011 and the fall of the regime, which forced the Company to shut down almost all its producing facilities including gas exports for a period of about 8 months, a period of social and political instability began which turned into disorders, strikes, protests and a resurgence of the internal conflict. These events jeopardized Eni’s ability to perform its industrial activity in safety, forcing the Company to interrupt its operations on certain occasions as precautionary measure. These events were fairly frequent in 2013 and sporadic in 2014. In 2014, Eni’s facilities in Libya produced on average 233 KBOE/d, registering a small increase compared to 2013. For further information on this matter, see "Item 3 – Risk factors". Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oilfield (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).

In the exploration phase, Eni is operator of four onshore blocks in the Kufra area (186/1, 2, 3 & 4) and in the onshore contract Areas A, B and offshore Area D.

Exploration and production activities in Libya are regulated by six Exploration and Production Sharing contracts (EPSA). The licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil and gas properties, respectively.

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

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

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

Eni’s activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet.

Exploration and production in this Country are regulated by concessions.

Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni’s interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), Djebel Grouz (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks.

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

Sub-Saharan Africa

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

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Angola. Eni has been present in Angola since 1980. In 2014, Eni’s production averaged 76 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore. The main Eni’s asset in Angola is the Block 15/06 (Eni operator with a 35% interest) where the West Hub project started up in 2014 and other development projects are underway. Eni participates in other producing blocks: (i) Block 0 in Cabinda (Eni’s interest 9.8%) North of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; and (iv) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin. Eni retains interests in other non producing concessions, particularly the Lianzi Development Area (Block 14K/A IMI Unit Area - Eni’s interest 10%), Block 35/11 (Eni operator with a 30% interest) and in Block 3/05-A (Eni’s interest 12%), onshore Cabinda North (Eni’s interest 15%) and the Open Areas of Block 2 awarded to the Gas Project (Eni’s interest 20%). Exploration and production activities in Angola are regulated by concessions and PSAs. In November 2014, Eni signed with the national oil company Sonangol a strategic agreement on future co-operation activities. In particular, the agreement includes the studies to analyze the potential of the non-associated gas present in the Lower Congo Basin and offshore Angola. The project scope is to analyze the different options both internationally and in the domestic market, also in order to sustain the local economy. In addition, the companies will asses possible projects on the mid-downstream business to be carried out in Angola.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Nigeria. Eni has been present in Nigeria since 1962. In 2014, Eni’s oil and gas production averaged 130 KBOE/d located mainly onshore and offshore the Niger Delta.

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%) and OPL 245 (Eni’s interest 50%), holding interests in OML 118 (Eni’s interest 12.5%) and in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the Country, Eni also holds a 5% interest in 21 onshore blocks and in 5 conventional offshore blocks.

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

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

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

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

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

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

Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2014, Eni’s operations in Kazakhstan accounted for 6% of its total worldwide production of oil and natural gas.

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

The participating interest in the NCSPSA has been redefined, effective as of January 1, 2008, in line with an agreement signed in October 2008 with Kazakh Authorities which proportionally diluted the participating interest of the international companies by transferring a 10% stake in the project to the Kazakh national oil company, KazMunaiGas. In addition to Eni, the partners of the consortium are the Kazakh national oil company, KazMunaiGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, CNPC with 8.33% and Inpex with 7.56%.

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

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

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

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

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

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

The Phase 1 is targeting an initial production capacity of 180 KBBL/d; when a second offshore treatment train comes online and compression facilities for gas reinjection are operational production capacity will ramp up to 370 KBBL/d. The partners are planning to further increase available production capacity up to 450 KBBL/d by installing additional gas compression capacity for reinjection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities.

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

As of December 31, 2014, Eni’s proved reserves booked for the Kashagan field amounted to 580 mmBOE, barely unchanged compared to 2013. The major part of these reserves are classified proved undeveloped. See the discussion on "Proved Undeveloped Reserves" section.

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

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

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

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In 2014, production of the Karachaganak field averaged 242 KBBL/d of liquids (52 net to Eni) and 842 mmCF/d of natural gas (181 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 50%) at the Russian gas plant in Orenburg and the remaining volumes is utilized for re-injecting in the higher layers and the production of fuel gas. Approximately 90% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 250 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining volumes of non-stabilized liquid production (approximately 16 KBBL/d) are marketed at the Russian terminal in Orenburg.

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

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

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

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

Rest of Asia

In 2014, Eni’s operations in the rest of Asia accounted for 6% of its total worldwide production of oil and natural gas.

China. Eni has been present in China since 1984 with activities located in the South China Sea. In 2014, Eni’s production amounted to 4 KBOE/d.

Exploration and production activities in China are regulated by PSAs.

In 2014, hydrocarbons were produced from the offshore Blocks 16/08 through 3 platforms connected to an FPSO. Production comes mainly from the HZ25-4 field (Eni’s interest 49%). In June 2014, Eni signed with CNOOC the PSC for exploration activity of the Block 50/34, located in the shallow water of the South China Sea. Indonesia. Eni has been present in Indonesia since 2001. In 2014, Eni’s production mainly composed of gas, amounted to 13 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 14 blocks. Exploration and production activities in Indonesia are regulated by PSAs. Main ongoing activities to feed the Bontang plant concerned: (i) the Jangkrik field (Eni operator with an 55% interest) in the Kalimantan offshore. The project includes drilling of production wells linked to a Floating Production Unit for gas and condensate treatment, as well as construction of a transportation facility. Start-up is expected in 2017; and (ii) the Bangka project (Eni’s interest 20%) in the Eastern Kalimantan, with start-up expected in 2016. Exploration activities yielded positive results with a gas discovery through the Merakes 1 NFW exploration well in the East Sepinggan offshore block (Eni operator with an

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85% interest). This discovery is located in proximity of the operated field of Jangkrik, and will supply additional gas volumes to the Bontang LNG plant. Iran. Eni has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the NIOC between 1999 and 2001, and no other exploration and development contracts have been entered into since then. All above mentioned projects have been completed or substantially completed. The formal hand over of operations to local partners at the Darquain project was completed in the course of 2014, marking termination of Eni’s direct operations in the Country. Going forward, Eni’s involvements will consist of finalizing the reimbursement of its past investments. In 2014, Eni’s contractual reimbursements were equivalent to a production of 1 KBOE/d, lower than 1% of the Group’s worldwide production. Eni believes that its activities in Iran are marginal to the Group’s results of operations and cash flow. For further information on this matter, see "Item 3 – Risk factors". Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companies and the national oil company Missan Oil, holds a 41.6% interests in the Zubair oilfield. Development and production activities at the Zubair field are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to production sharing contracts. In 2014, production of the Zubair field averaged 21 KBBL/d net to Eni. In 2014, phase one of the Rehabilitation Plan of the Zubair field progressed. The project includes the construction of an oil treatment plant for a capacity of 300 KBBL/d, the revamping of existing treatment facilities and the drilling of production and water injection wells. In March 2014, the national oil company South Oil Company sanctioned the Enhanced Redevelopment Plan to achieve a production plateau of 850 KBBL/d. The main contracts to build new facilities were awarded in the first half of 2014. Pakistan. Eni has been present in Pakistan since 2000. In 2014, Eni’s production mainly composed of gas amounted to 43 KBOE/d. Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore). Eni’s main permits in the Country are Bhit/Bhadra (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2013 accounted for 75% of Eni’s production in Pakistan. Russia. The drilling exploration program was halted due to the sanctions enacted by European Union and the United States. Eni is closely monitoring developments of

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the situation and has required all relevant authorizations to continue the exploration activities in compliance with the current sanction regime against Russia. For further information on this matter, see "Item 3 – Risk factors".

Turkmenistan. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the Country. In 2014, Eni’s production averaged 9 KBOE/d.

Exploration and production activities in Turkmenistan are regulated by PSA.

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

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

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

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

Americas

In 2014, Eni’s operations in America area accounted for 8% of its total worldwide production of oil and natural gas.

Ecuador. Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni’s interest 100%) located in the Oriente Basin, in the Amazon forest. In 2014, Eni’s production averaged 12 KBBL/d.

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

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

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

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

Trinidad & Tobago. Eni has been present in Trinidad & Tobago since 1970. In 2014, Eni’s production averaged 60 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block located offshore North of Trinidad.

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

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

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

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

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

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

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

The main operated fields are Allegheny and Appaloosa (Eni’s interest 100%), Pegasus (Eni’s interest 85%), Longhorn, Devils Towers and Triton (Eni’s interest 75%). Eni also holds interests in Europa (Eni’s interest 32%), Medusa (Eni’s interest 25%) and Thunder Hawk (Eni’s interest 25%) fields.

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

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

To achieve the highest safety standards of operations, Eni became a member of the HWCG consortium of Gulf of Mexico operators. The HWGC provides resources, coordination and performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. For further information on this matter see "Item 3 – Risk factors".

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

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

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

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

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

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

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

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

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

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

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

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

Australia and Oceania

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

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

Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs.

The main production blocks in which Eni holds interests are WA-33-L (Eni’s interest 100%), JPDA 03-13 (Eni’s interest 10.99%) and JPDA 06-105 (Eni operator with a 40% interest). In the appraisal and development phase Eni holds interests in NT/P68 (Eni’s interest 50%) and NT/RL7 (Eni’s interest 32.5%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA.

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

 

Capital expenditures

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

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

The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. Disclosure responsive to this requirement is presented under "Item 3 – Political considerations – Risks associated with our presence in sanction targets" and below in this section.

In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes.

The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. We do not believe that any of the transactions or activities listed below violated U.S. sanctions also considering the waiver that we were granted by relevant U.S. Authorities, including the U.S. Department of State, in relation to certain Iran-related activities. For more information please refer to "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets".

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

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

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

 

Gas & Power

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

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

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

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competition and pricing pressure, which are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses whereby wholesaler operators are forced to compete aggressively on pricing in order to limit the financial exposure dictated by the contracts in case of volumes off-taken below the minimum take.

Against this backdrop, Eni’s main focus is on profitability and sustainable cash flow generation, according to the following guidelines: (i) alignment of the supply portfolio to market conditions starting from 2016, leveraging on further renegotiations; (ii) the full streamlining of operations and optimization of logistic costs; and (iii) development and growth in the value added segments, in particular in the retail segment, developing the client base also through the sale of extra-commodity products, as well as in the LNG segment, leveraging on the marketing opportunities in premium markets and upstream integration.

Supply of natural gas

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

The table below sets forth Eni’s purchases of natural gas by source for the periods indicated.

Natural gas supply		2012		2013		2014

(BCM)

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

Sales of natural gas

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

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

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

Natural gas sales by entity		2012		2013		2014

(BCM)

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

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(a)

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

 

Natural gas sales by market		2012		2013		2014

(BCM)

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

European markets

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

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

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

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

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

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

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

 

The LNG business

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

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

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

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

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

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LNG sales		2012		2013		2014

(BCM)

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

Electricity sales and power generation

Electricity sales

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, at industrial sites and on the Italian Stock Exchange for electricity. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value chain leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and middle to large industrial users, the Company has been developing a commercial offer that provides the combined supply of gas, power and fuels. In 2014, power sales (33.58 TWh) were directed to the free market (74%), the Italian Power Exchange (14%), industrial sites (9%) and others (3%). Compared with 2013, electricity sales were down by 4.2%, due to lower sales to large clients and wholesalers partially offset by higher volumes traded on the Italian Power Exchange.

Power availability		2012		2013		2014

(TWh)

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

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(a)

Include positive and negative imbalances.

 

Power generation

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

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

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

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

 

Power generation		2012		2013		2014

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

International transport

Eni has transport rights on a large European network of integrated infrastructures for transporting natural gas, which links key consumption markets with the main producing areas (Russia, Algeria, Libya and the North Sea). Eni pays the transport capacity under ship-or-pay contracts which are similar to take-or-pay contracts.

Eni also retains ownership interests in certain pipeline companies which run and operate the facility by selling transportation capacity to long-term ship-or-pay contracts to both shareholders and third party shippers. The main assets of Eni transport activities are provided in the table below.

International transport infrastructure

Route

Lines

Total length

Diameter

Transport capacity (1)

Transit capacity (2)

Compression stations

(units)

(km)

(inch)

(BCM/y)

(BCM/y)

(No.)

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

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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.

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International transport activities

The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.

The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 BCM/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.

The GreenStream pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 BCM/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system.

Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.

 

The South Stream project

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

 

Capital expenditures

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

 

Refining & Marketing

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

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

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

Supply

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

Refining

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

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

Refining system in 2014

Ownership share (%)

Distillation capacity (total) (KBBL/d)

Distillation capacity (Eni’s share) (KBBL/d)

Primary balanced refining capacity (1)(Eni’s share) (KBBL/d)

Conversion index (%)

Fluid catalytic cracking - FCC (KBBL/d)

Residue conversion (KBBL/d)

Go-Finer/ Mild Hydro- cracking/ (KBBL/d)

Mild Hydro- cracking/ Hydro- cracking (KBBL/d)

Visbreaking/ thermal cracking (KBBL/d)

Coking (KBBL/d)

Distillation capacity utilization rate (Eni’s share) (%)

Balanced refining capacity utilization rate (Eni’s share) (%)

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

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

 

Italy

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

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

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

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

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

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

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

 

Outside Italy

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

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

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

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

Availability of refined products		2012		2013		2014

(mmtonnes)

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

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

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

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

 

Logistics

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

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

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

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Marketing

Eni markets a wide range of refined petroleum products, primarily in Italy, through an extensive operated network of service stations, franchises and other distribution systems.

The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.

Oil products sales in Italy and outside Italy		2012		2013		2014

(mmtonnes)

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

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

 

Retail sales in Italy

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

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

 

Retail sales in the rest of Europe

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

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

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

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

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

 

Other businesses

Wholesale

Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Along with traditional products provided with the Eni’s high quality standards, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. Customer care and product distribution is supported by a widespread commercial and logistical organization presence throughout Italy and articulated in local marketing offices and a network of agents and concessionaires.

In 2014, sales volumes on wholesale markets in Italy (7.57 mmtonnes) declined by approximately 800 ktonnes, down 9.6%, mainly due to lower sales of all products, in particular gasoil for heating reflecting the mild climate registered in the period, as well as fuel oil and bunkering due to declining demand. Average market share in 2014 was 26.7% (28.8% in 2013). Supplies to the petrochemical industry (0.97 mmtonnes) decreased from 2013 (down 354 ktonnes) due to lower feedstock supplies. Wholesale sales in the Rest of Europe of approximately 4.60 mmtonnes increased by 8.7% from 2013 due to increased sales in Czech Republic, Hungary and France. Other sales (21.63 mmtonnes) increased by 2.18 mmtonnes, or 11.2%, mainly due to higher sales to the other oil companies.

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

 

LPG

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

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

 

Lubricants

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

 

Oxygenates

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

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

 

Capital expenditures

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

 

 

Chemicals

Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production sites are located in Italy and Western Europe. These are predominantly oil-based businesses with a history of losses and poor growth prospects. We face structural headwinds in our legacy basic petrochemical and plastic businesses due to the commoditized nature of our products, low entry barriers, lack of scale, exposure to the volatility in the costs of oil-based feedstock, cyclicality in demand, and strong competitive pressures from operators with lower cost structure especially from the Middle and Far East and other weaknesses. Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. See "Item 3 – Risk factors".

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

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

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

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

	Year ended December 31,

		2012		2013		2014

(ktonnes)

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

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

 

Intermediates

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

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

 

Polymers

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

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

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Capital expenditures

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

 

 

Engineering & Construction

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

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

		2012		2013		2014

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

 

Offshore Engineering & Construction

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

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

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

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

 

Onshore Engineering & Construction

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

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

 

Offshore Drilling

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

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

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

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Onshore Drilling

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

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

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

 

Capital expenditures

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

 

 

Corporate and Other activities

These activities include the following businesses:

•		the "Other activities" segment comprises results of operations of Eni’s subsidiary Syndial which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and
•		the "Corporate and financial companies" segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. Through Eni’s subsidiaries Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance Ltd, Eni carries out cash management activities, administrative services to its foreign subsidiaries, lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an intercompany basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations.

 

Seasonality

Eni’s results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months and lowest in the third quarter, which includes the warmest months. Moreover, year-to-year comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residential space heating. In colder years that are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa.

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Research and development

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

The Company believes that the oil&gas industry will have to face several challenges:

•		uncertainty about oil&gas prices and demand;
•		limited access to new hydrocarbon resources, with increasing role of frontier oil&gas basins;
•		need of a more efficient exploitation of conventional fossil sources and of viable solutions for energy production from renewable and lower greenhouse gas emission sources; and
•		safety of operations as a crucial point for business success.

In order to address the above challenges, Eni will pursue the following technological targets in the next future:

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

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

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

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

 

Exploration & Production

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

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

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

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

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

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

 

Refining & Marketing

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

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

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

 

Versalis

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

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

 

 

Insurance

In order to control the insurance costs incurred by each of Eni’s business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance Ltd, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market.

Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni uses insurance companies who it believes are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.1 billion for offshore events and $1.5 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1 billion for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment and FPSOs used by the Exploration & Production segment for developing offshore fields; $500 million for time charters.

Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one occurred in the Gulf of Mexico in 2010 which

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

 

 

Environmental matters

Environmental regulation

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

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

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

 

Italy

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

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

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

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

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

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

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

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

The legislative framework on SISTRI, an automated tracking system of hazardous waste, was updated by Ministerial Decree April 24, 2014, which provided new rules about intermodal transport and communication with the administration service of SISTRI. While SISTRI obligation are currently mandatory, the sanctions, according to Decree No. 192/2014 and Law No. 11/2015, shall be applied only from January 1, 2016, except the ones for obligations about signing up and payment of annual contributions, which enter in force by April 1, 2015. Legislative Decree No. 81/2008 concerned the protection of health and safety in the workplace and was designed to regulate the work environments, equipments and individual protection devices, physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees.

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

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

European Union

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

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

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

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

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

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

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

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

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

The original F-gas Regulation (Regulation No. 842/2006) was replaced by a new Regulation (No. 517/2014) adopted in 2014 which applies from January 1, 2015. A new Regulation strengthens the existing measures and introduces a number of far-reaching changes. By 2030, it will cut the EU’s F-gas emissions by two-thirds compared with 2014 levels.

This represents a fair and cost-efficient contribution by the F-gas sector to the EU’s objective of cutting its overall greenhouse gas emissions by 80-95% of 1990 levels by 2050.

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

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

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

On June 1, 2007, the REACH regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed caused by chemicals, while enhancing the competitiveness of the EU chemical industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to European Chemicals Agency (ECHA) how the substance can be safely used and they must communicate the risk management measures to the users. If the risks cannot be managed, authorities can restrict the use of substances in different ways. Over time, the hazardous substances should be substituted with less dangerous ones. The deadline of REACH registration depends on the tonnage

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band of a substance and the classification of a substance; next and last deadline is 2018. Eni recognizes the importance of the Regulation CE 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA that regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspects that concerns the exchange of information between producers and importers, as well as the users of chemical substances ("downstream users").

The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation EC No. 1272/2008 on the classification, labeling and packaging of substances and mixtures), and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. The Regulation will replace two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. There is a transition period until 2015. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them.

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

Following the incident at the Macondo well in the Gulf of Mexico, the U.S. Government and other governments have adopted more stringent regulations targeting safety and reliable oil and gas operations in the United States and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. Italian Authorities as well have passed legislation with Law Decree No. 128 on June 29, 2010 that introduces certain restrictions to activities for exploring and producing hydrocarbons, that have been confirmed and further geographically limited by the successive Law Decree No. 134 of August 7, 2012 and by the Ministerial Decree of September 4, 2013.

European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction.

At the European level on June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The main elements of the EU directive are the following:

•		The Directive introduces licensing rules for effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil and gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas.
•		Independent national competent authorities, responsible for the safety of installations, are in charge to verify the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties applies in case of non-compliance with the minimum set standards.
•		Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans need be submitted to national authorities.
•		Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation.
•		Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents.

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•		Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and national authorities.
•		Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore).
•		Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.

We believe that Eni operations are currently in compliance with all those regulations in each European country whose they have been enacted.

Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbons reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will likely increase in future years.

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

As to major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Member States have to transpose and implement the Directive by June 1, 2015.

The main changes in comparison to the previous Seveso Directive are:

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

Eni is starting the initial activities aimed at guaranteeing the compliance of its own industrial sites.

 

HSE activity for the year 2014

Eni is committed to continuously improving its model for managing health, safety and environment issues across all its businesses in order to minimize risks associated with its industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations.

In 2014, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 341 (down from 2013 because of amalgamations of different site certificates into a single certificate), of which 113 certifications according to the ISO 14001 standard, 10 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union), 11 certifications according to the ISO 50001 standard (certification for an energy management system) and 119 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

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

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

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

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

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

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

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

Health. Eni’s activities for protecting health aim to continuously improve work conditions. We believe that we achieved a good performance in this area due to:

•		plant and facility efficiency and reliability;
•		promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment;
•		certification programs of management systems for production sites and operating units;
•		identified indicators in order to monitor exposure to chemical and physical agents;
•		strong engagement in health protection for workers operating outside Italy also with the support of international health centers capable of guaranteeing a prompt and adequate response to any emergency;
•		identification of an effective organization of health centers, in Italy and abroad; and
•		training programs for medics and paramedics.

To protect the health and safety of its employees, Eni relies on a network of 413 health care centers located in its main operating areas. A set of international agreements with the best local and international health centers ensures efficient services and timely responses to emergencies.

Eni is engaged to the elaboration of HIA and relative standards to be applied to all new projects of evaluation of working exposure to environment, in Italy and abroad. The main aim of HIA is to avoid any negative impacts and maximize any positive impacts of the project on the host community and it is usually carried out as part of/or in conjunction with the Environmental and a Social Impact Assessment process. Its results are used to develop appropriate mitigation measures and an improvement plan with the host community.

In 2014, Eni incurred total expenses of euro 49.4 million, down by 2.8% from 2013, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health which will be in line or above with 2014 levels in future years.

 

Managing GHG emissions

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

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

Regarding Eni’s own GHG emissions management, with the aim of ensuring a comprehensive, transparent and accurate reporting for GHG emissions, Eni introduced in 2005 its own Protocol for accounting and reporting greenhouse gas emissions (GHG Accounting and Reporting Protocol), integrated by a procedure on reporting and accounting methodologies on indirect emissions scope 3 types update in 2014; both documents are an essential requirement for emissions certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the assessment of progress. Eni GHG Protocol has been updated in 2014 to be in compliance with the National and European Guidelines (Regulation No. 601/2012) and with the best practices reference document (American Petroleum Industry Compendium). For safer and more accurate management of GHG emissions and more effective reporting, Eni provided all its business units with a dedicated database, in order to gather and report GHG emissions according to the Protocol and to ensure completeness, accuracy, transparency and consistency of GHG accounting as required by certification needs. In order to improve the Eni accounting and reporting process, Eni confirmed independent verification of its 2013 equivalent CO₂ emissions data (scope 1, 2 and 3 emissions), as submitted to the Carbon Disclosure Project, and obtained the verification statement in accordance with ISO 14063-3.

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

In Europe, Eni is subject to the European Union Emission Trading Scheme (EU-ETS) that was established by Directive No. 2003/87/EC. Effective from January 1, 2005, EU-ETS is the largest carbon market in the world for exchanging emission allowances targeting industrial installations with high carbon dioxide emissions. The EU-ETS Directive states that any operator, who produces GHG emissions in excess of the amounts allowed on the base of national allocation plan, is required to acquire allowances on the market to cover the excess emissions or to pay a penalty. On January 1, 2013 the third phase (2013-2020) of EU-ETS has started. In this period the main instrument for allowances allocation is represented by sales auctioning and no more by the historical emissions. During this phase no more free allowances will be given to power plants (exception on few particular cases). Conversely, for all the other industrial sectors, the free allocation has been determined with the adoption of European benchmarks linked to the carbon intensity of each industrial process.

Currently, Eni participates in the ETS scheme with 37 plants in Italy and 7 outside Italy, which collectively represent 45% of all direct GHG emissions generated by Eni’s plants worldwide. Due to stricter allocation rules in the third phase (2013-2020) of the Emissions Trading Scheme, Eni is been receiving a lower amount of free allowances in comparison with the second phase (2008-2012). As a consequence, in the next four-year period (2015-2018), Eni shall buy on the market an amount of allowances to cover GHG emissions of its industrial plants. The large majority of the deficit is concentrated in the power sector.

 

 

Regulation of Eni’s businesses

Overview

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

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Regulation of exploration and production activities

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

 

Regulation of the Italian hydrocarbons industry

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

 

Exploration & Production

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

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

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

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Gas & Power

Natural gas market in Italy

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

In 2011, Legislative Decree No. 130 of August 13, 2010 titled "New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers" became effective. This new regulation replaced the previous system of gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 by introducing a 40% ceiling to the wholesale market share of each Italian gas operator who inputs gas into the Italian backbone network. In the frame of Legislative Decree No. 130/2010 Eni has committed itself to build new storage capacity for 4 BCM within five years from the enactment of the Decree; as a consequence the above mentioned cap to its market share in Italy rises from 40% to 55%. In the case of violations of the mandatory threshold, Eni is obliged to execute gas release measures at regulated prices up to 4 BCM over a two-year period following the ascertainment of the breach. Access to the new storage capacity was reserved to industrial customers and their consortium (3 BCM) and to gas-fired power plants (1 BCM).

Law Decree of December 23, 2013 converted to Law on February 21, 2014 establishes that any operator with a wholesale market share higher than 10% is obliged to offer on the natural gas future market a volume of natural gas corresponding to 5% of the annual imported volumes. The obligation should be combined with a corresponding buy request on the same market; the spread between bid and ask prices has to be lower than an amount defined by the Minister of Economic Development, based on a proposal by the AEEGSI. AEEGSI also defines the modalities for the fulfillment of the above mentioned obligation.

Eni’s management is monitoring these issues with a view of assessing any possible financial or economic impact associated with the enacted measures and their evolution. Management also believes that these regulations will increase competition in the wholesale natural gas market in Italy leading to further margin pressures.

 

Law Decree No. 1 of January 24, 2012 for new liberalization measures in Italy

Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so-called Liberalization Decree was converted to Law No. 20 on March 24, 2012. This Law aimed to:

•		enhance competitiveness in gas tariffs to residential customers and in the distribution of refined products. The AEEGSI, in charge with setting pricing mechanisms for supplies to users, starting from the second quarter of 2012 updated the indexation mechanism by increasing the weight of spot prices in the indexation of the supply costs of gas. In particular, spot prices have represented a share of 3% and 4% of the cost of gas in the second and third quarter 2012, respectively, and 5% in the period October 2012-March 2013, with the remaining part indexed to the supply cost provided by a panel of oil-linked long-term contracts; and
•		reform the storage system introducing market-based mechanisms for the allocation of storage capacity, moving away from the traditional "pro-rata"/tariff system, and with the aim to reduce the cost of natural gas for industrial customers. In particular:

		-		for a space determined by the Ministry itself, storage capacity is reserved for the offer to industrial sector of an integrated service (international transport, re-gasification and storage) allowing them to supply of natural gas from abroad; and
		-		every year is determined the space of storage devoted to the needs of modulation assigned with auction procedures.

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

 

Negotiation platform for gas trading

In compliance with the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry of Economic Development published a decree that implements a trading platform for natural gas from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform are entrusted to an independent operator, the Gestore dei Mercati Energetici (GME), an Italian agency. On this platform are traded also volumes of gas corresponding to the legal obligations on part of Italian importers and producers as per Law Decree No. 7/2007. Since December 2010, the GME is also trader’s counterparty in transactions on the spot market for natural gas (divided into day-ahead market and intraday market).

Management believes that these measures have increased the level of liquidity in the Italian spot market of gas.

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Natural gas prices

Following the liberalization of the natural gas sector introduced in 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the AEEGSI holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the AEEGSI) and Legislative Decree No. 164/2000. Furthermore, the AEEGSI is still entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by AEEGSI beside their own price proposals.

In 2013, a new tariff regime was enacted for Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the AEEGSI are residential clients (including residential buildings consuming less than 200,000 CM/y). With Resolution No. 196 effective from October 1, 2013, the AEEGSI reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices versus the previous regime that provided a mix between an oil-based indexation and spot prices. This new tariff mechanism negatively affected Eni’s results of operations in the Gas & Power segment in 2014 due to the fact that Eni was unable to pass onto to the residential customers the cost increases in the oil-linked supply contracts still present in its portfolio. The new tariff regime intends to partially offset the negative impact born by wholesalers by introducing a pricing component intended to cover the risks and costs of the supplies to wholesalers. Furthermore, it has been provided a stability mechanism whereby a wholesaler part of a long-term, take-or-pay gas supply contract may opt for being reimbursed of the negative difference between the oil-linked costs of gas supplies and spot prices in the two thermal years following the new regime implementation. Conversely, in case spot prices fall below the oil-linked cost of gas supplies in the following two thermal years, the same wholesaler is obliged to refund customers of the difference. Based on this compensation mechanism Eni recognized a gain of euro 60 million in its 2014 results of operations. However, due to the current downturn in crude oil prices, Eni is projecting that the oil-linked index of the procurement costs set by the Authority could determine a loss to Eni up to euro 480 million next year. This contingent liability reflects the fact that the Authority index is not reflective of the current setup of Eni’s portfolio of gas supply costs which due to the renegotiations achieved in 2014 is largely indexed to hub prices and therefore Eni’s procurement costs are not expected to benefit from a fall in oil-linked gas procurement costs. It is still possible that the AEEGSI updates its index of procurement costs to better reflect the status of the gas portfolio of those wholesalers who achieved new pricing terms for their gas supplies. Alternatively, Eni might file an administrative appeal against any deliberations of the AEEGSI on this matter which might possibly lead to unfair results to Eni.

The new tariff regime reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed.

Similarly other regulatory authorities in European countries where Eni is present have issued regulations introducing a hub component in the pricing formulas related to retail clients, as well as measures to boost liquidity and competitiveness in the gas market.

 

Refining and marketing of petroleum products

Refining. The regulations introduced with Law No. 9/1991 and No. 239/2004 (Article 1, paragraphs 56, 57 and 58) significantly changed the norms introduced in the 1930’s which required any refining activity be handled under a concession from the State. Today an authorization is required to set up new processing and storage plants and for any change in the capacity of mineral processing plants, while all other changes that do not affect capacity can be freely implemented. Another simplification measure has been introduced by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as "strategic settlements" that need authorization from the State, in agreement with the relevant Region, and imposes a single process of authorization that must be closed within 180 days. Management expects no material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium term.

Marketing. Following the enactment of the above mentioned Law Decree No. 1 of January 24, 2012, as converted in Law No. 27 of March 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012 principals will be allowed to supply freely up to 50% of their requirements. In such case the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also

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provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing Eni’s market share in Italy.

Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by City authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions.

From 2000 onwards, a number of administrative measures have been enacted in Italy with the goal of modernizing and making more efficient the Italian network. A Ministerial Decree of October 31, 2001 established the criteria for the closing down of incompatible stations, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities. Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012 all service stations must be provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. Law Decree No. 1/2012 also allowed the installation of fully-automated service stations with prepayment, but only outside City areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations which might prejudice the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours. Management believes that those measures have supported competition in the Italian retail market.

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

Compulsory stocks. According to Legislative Decree of December 31, 2012, No. 249, enacting Directive No. 2009/119/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of net import, including 10% deduction for minimum operational requirements. Decree No. 249/2012 states that compulsory stocks are determined each year by a decree of the Minister of Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company.

The Legislative Decree No. 249/2012 sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry of Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain.

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

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

 

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 ("Article 101" and "Article 102", respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU

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that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self assessment by the undertakings that such conducts does not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:

•		requiring that an infringement be brought to an end;
•		ordering interim measures;
•		accepting commitments; and
•		imposing fines, periodic penalty payments or any other penalty provided for in their national law.

National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the "EEA Agreement"), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the "Italian Antitrust Law"). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers.

 

 

Property, plant and equipment

Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’ worldwide proved oil and gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See "Exploration & Production" above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas.

 

 

Organizational structure

Eni SpA is the parent company of the Eni Group. As of December 31, 2014, there were 252 fully-consolidated subsidiaries and 51 associates, joint ventures and joint operations that were accounted for under the equity or cost method or in accordance to Eni’s share of revenues, costs and assets of the joint operations calculated based on Eni’s working interest. For a list of subsidiaries of the Company, see “Exhibit 8. List of Eni’s fully-consolidated subsidiaries for year 2014”.

 

 

Item 4A. UNRESOLVED STAFF COMMENTS

None.

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Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

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

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

 

Executive summary

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

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

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

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

Eni Group	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

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

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

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

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

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

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

We also plan to preserve our liquidity by leveraging on the timely development of capital projects in the Exploration & Production in order to achieve the scheduled time-to-market of our reserves, on cost efficiencies across all businesses and on completing the turnaround process of our Gas & Power, Refining & Marketing and Chemical segments. We plan to generate additional euro 8 billion of funds through our asset disposal program which will mainly comprise the divestment of participating interest in certain of our exploratory leases.

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

 

Trading environment

		2012		2013		2014

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

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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 USD per barrel FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.

When the term margin is used in the following discussion, it refers to the difference between the average selling price and reflect the trading environment and are, to a certain extent, a gauge of industry profitability.

Eni’s results of operations and the year-to-year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest

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rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. See “Item 3 – Risk factors”.

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

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

 

Key consolidated financial data

		2012		2013		2014

(euro million)

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

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Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the oilfield services

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

 

Oil and gas activities

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be categorized as "proved", the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgment. Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision. Upward or downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense. Depreciation and depletion rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation and depletion expense. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which are used to assess any impairment loss. The larger is the volume of estimated reserves, the lower is the likelihood of asset impairment.

 

Impairment of assets

Assets are impaired when there are events or changes in circumstances that indicate that carrying values of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced utilization of the plants and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply and demand conditions. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred costs - see also the accounting policy for "Inventories") related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses, as well as for the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the book value of an asset with its recoverable amount. The recoverable amount is the greater of fair value net of disposal cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil and gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent specialized analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows. Goodwill and other intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets at the cash generating unit level on an annual basis and whenever there is an indication that they may be impaired In particular, goodwill impairment is based on the lowest level (cash generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash generating unit is the smallest aggregate

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

 

Decommissioning and restoration liabilities

Obligations to dismantle and remove items of property plant and equipment and restore land or seabed require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded presently in the Consolidated Financial Statements. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The complexity of these estimates is also due to the accounting that requires the initial recognition of the present value of the decommissioning and restoration liabilities as a part of the cost of property, plant and equipment. Then the carrying amount of decommissioning and restoration liabilities is adjusted to reflect the passage of time and any change in the estimates following the modification of amount and timing of future cash flows and discount rates adopted. The discount rate used to determine the provision is based on managerial judgments.

 

Business combinations

Accounting for business combinations requires the allocation of the purchase price to the identifiable assets and liabilities of the acquired business generally at their fair values. Any positive residual difference is recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors.

 

Environmental liabilities

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

 

Employee benefits

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds). The inflation rates reflect market conditions observed country by country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization and

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

 

Provisions

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

 

Revenue recognition

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

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

 

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2012-2014 Group results of operations

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

The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS.

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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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,

		2012		2013		2014

(%)

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

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

(i)

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

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(ii)

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

These decreases were partly offset by:

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

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

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

These increases were partly offset by:

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

 

Discontinued operations

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

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

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

 

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

a) Total revenues

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

 

Net sales from operations from continuing operations

The table below sets forth, for the periods indicated, the net sales from operations from continuing operations generated by each of Eni’s business segments including intragroup sales, together with consolidated net sales from operations.

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

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

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

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

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

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

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

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

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

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

 

b) Operating expenses

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

.

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

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

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

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

 

c) Depreciation, depletion, amortization and impairments

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

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

 

d) Operating profit by segment

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

	Year ended December 31,

		2012		2013		2014

(%)

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

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

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

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

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

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

	Year ended December 31,

		2012		2013		2014

Exploration & Production

(euro million)

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

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

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

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

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

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

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

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

	Year ended December 31,

		2012		2013		2014

Gas & Power

(euro million)

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

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

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

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

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

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

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

Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.

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

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

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

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

	Year ended December 31,

		2012		2013		2014

Refining & Marketing

(euro million)

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

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

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

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

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

	Year ended December 31,

		2012		2013		2014

Chemicals

(euro million)

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

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

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

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

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

	Year ended December 31,

		2012		2013		2014

Engineering & Construction

(euro million)

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

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

Other activities. This reporting segment includes the results of operations of Eni’s subsidiary Syndial which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or liquidated in past years.

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

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

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e) Net finance expense

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

 

f) Net income from investments

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

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

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

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

 

g) Taxes

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

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

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

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

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

 

h) Non-controlling interest

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

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

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Liquidity and capital resources

Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures and acquisitions over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of non-strategic assets. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and well-balanced financing structure.

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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		(euro million)		2012		2013		2014

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

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

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

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

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

 

a) Changes in working capital related to operations

In 2014, changes in working capital generated cash flows amounting to a positive euro 2,668 million as a result of: (i) decreasing inventories (a positive euro 1,524 million) as a result of the alignment of the book value of crude oil and products to market prices (this item being an adjustment of the inventory loss recorded in net profit and as such is not a cash item); (ii) net cash generated by a positive balance between trade receivables collected and trade payables paid (a net inflow of euro 1,091 million). This was driven by a reduced exposure in the Exploration & Production segment towards certain state-owned oil companies and other local agencies mainly in Egypt where the Company cashed in significant amounts of overdue trade payables thanks to finalization of industrial and commercial agreements with the counterparties. Also the Engineering & Construction segment recorded a reduction in trade receivables; and (iii) a positive inflow related to other current assets and liabilities (up by euro 240 million) which mainly reflected a net positive inflow in the Gas & Power segment due to the collection of pre-paid volumes of gas under take-or-pay contracts and the collection of receivables from supplied long-term customers.

In 2013, changes in working capital generated cash flows amounting to a positive euro 456 million as a result of: (i) decreasing gas and petroleum products inventories (a positive euro 350 million) as a result of destocking oil and products inventories, the effect of which were partly offset by higher contract work in progress in the Engineering & Construction segment albeit of a lower magnitude than in 2012; and (ii) a positive balance of other current assets and liabilities (up by euro 723 million) which mainly reflected a net positive inflow in the Gas & Power segment due to the collection of pre-paid volumes of gas under take-or-pay contracts and the collection of receivables from supplied

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

 

b) Investing activities

	Year ended December 31,

		2012		2013		2014

(euro million)

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

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

For a discussion of capital expenditures by business segment and a description of year-on-year changes see below "Capital expenditures by segment".

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

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

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

 

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

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

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

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

 

Financial condition

Management assesses the Group capital structure and capital condition by tracking net borrowings, which is a non GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. From 2013, the Company has been maintaining a cash reserve comprised of very liquid investments (mainly sovereign and corporate securities which management has selected based on their creditworthiness) by investing part of the proceeds from the disposal plan carried out in 2012 and 2013 and the proceeds from the reimbursement of certain financing receivables towards the former subsidiary Snam which was divested at the end of 2012. Those securities amounted to euro 5,037 million as of end of 2014 and were accounted as mark-to-market financial instruments. For further information see “Item 18 – note 9 – Financial assets held for trading – of the Notes on Consolidated Financial Statements”. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced compared to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

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

	As of December 31,

		2012		2013		2014

Short-term

Long-term

Total

Short-term

Long-term

Total

Short-term

Long-term

Total

(euro million)

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

	As of December 31,

		2012		2013		2014

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

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

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

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

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

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

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

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

 

Capital expenditures by segment

Exploration & Production. In 2014, capital expenditures of the Exploration & Production segment amounted to euro 10,524 million, representing a slight increase of euro 49 million, or 0.5%, from 2013 mainly due to the development of oil and gas reserves (euro 9,021 million). Significant expenditures were directed mainly outside Italy, in particular Norway, Angola, Congo, the United States, Nigeria, Egypt, Indonesia and Kazakhstan. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri, as well as sidetrack and infilling activities in mature fields. About 98% of exploration expenditures that amounted to euro 1,398 million were directed outside Italy, in particular in Libya, Mozambique, the United States, Nigeria, Angola, Indonesia, Cyprus, Norway and Gabon.

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

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

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

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

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

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

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

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

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

 

 

Recent developments

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

		Three months ended March 31,

		2014		2015

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

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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 USD per barrel FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.

 

Significant transactions

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

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Management’s expectations of operations

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

 

Exploration & Production

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

Oil price assumptions are particularly significant when it comes to assessing the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. The Company estimates that production entitlements in its current portfolio of PSAs will increase on average by approximately 1,000 BBL/d for each $1 decrease in oil prices compared to current Eni’s assumptions for oil prices. We note that in case oil prices differ significantly from our own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.

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

Management also plans to increase the share of operated production in the Company’s portfolio. We expect to operate 84% of the planned new field start-ups in the plan period. Project operatorship enables the Company to better schedule and control project execution, expenditures and timely achievement of project milestones and to mitigate the operational risk associated with drilling activities at high pressure-high temperature wells and at deep waters well by deploying our technologies and competences. Eni estimates that risky wells will represent approximately 24% of the planned wells to be drilled in 2015.

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

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

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

 

Gas & Power

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

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

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

Against this scenario the Company priority in its Gas & Power business is to preserve the economic and financial sustainability in the long term. In order to achieve this goal, our strategy in the Gas & Power sector will leverage on the renegotiations of our long-term gas supply contracts in order to align pricing and volume terms to current market conditions, the development of highly profitable segments and cost efficiencies and operational streamlining.

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

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

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However, management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will ultimately be achieved and the timing of recognition in profit. Furthermore in case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration procedure could be started to solve the commercial dispute. This potentially adds to the level of uncertainty surrounding the outcome of those renegotiations. Considering also ongoing price renegotiations with Eni long-term customers, future results of the Gas Marketing activities are subject to increasing volatility and unpredictability.

In addition to contract renegotiation, the Company intends to grow its presence in market segments where margins can be sustained in the long run. As part of this plan, we intend to strengthen our role as a global player in LNG trading where we plan to achieve steady profitability in line with our past performance. In the long run, we will leverage integration with our upstream operations by marketing equity gas, particularly with the start of the gas projects in Mozambique. We will seek to preserve margins on sales to large accounts by leveraging on the Company’s multiple presence across various markets and expertise in delivering innovative and tailor-made offering structures to best suit customers’ needs by providing complex pricing formulas and flexibility in volumes collection (see “Item 4 – Gas & Power”). The second leg of the Company’s marketing effort will address retail customers across Europe with a view to enhancing the existing customer base. The drivers to achieve this will be a strategy of customer retention centered on brand identity, the administrative advantages of the dual offer of gas and electricity and a competitive cost to serve; a wide range of sale channels and continuing innovation in processes, promotion and customer care and post-sale assistance. We believe that offering a wide range of valuable services with the selling of the commodity will underpin the profitability of our retail operations considering that the regulatory modifications to the indexation of the raw material cost have substantially flatten the margin on the commodity. Management will also seek to improve profitability by means of cost efficiencies particularly by streamlining business support activities and reducing marketing and general and administrative costs. Finally, the Company intends to capture margins improvements by means of trading activities by entering derivative contracts both in the commodity and the financial trading venues in order to capture possible favorable trends in market prices, within the limits set by internal policies and guidelines that define the maximum tolerable level of market risk. As part of this strategy, the Company intends to improve results of operations by effectively managing the flexibilities associated with the Company’s assets (gas supply contracts, transportation rights, storage capacities). This can be achieved through strategies of asset-backed trading by entering into derivative contracts to leverage on commodity price volatility, the risks of which might be absorbed in part or entirely by the natural hedge granted by the asset availability. By this way, the Company also intends to rationalize its logistic cost structure by better exploiting available transport capacity. Asset-backed activities may lead to gains, as well as losses the amount of which could be significant. For further information on the market risk and how the Company manages it see “Item 11 – Quantitative and Qualitative Disclosures about Market Risk”.

Based on the above outlined trends and industrial actions, management expects that we will retain profitable, cash-positive operations in the Company’s gas marketing business over the plan period. Our profitability outlook factors in the expected benefits of ongoing renegotiations of the Company long-term supply contracts which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3. As part of the risks which management considered in its profitability outlook, there is also a regulatory risk relating to the Italian market as disclosed in "Item 3 – Risk factors" in the section "Risk in the Company’s Gas & Power business", under the heading "Risks associated with sector-specific regulations in Italy".

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

These projections could be subject to the risks of further contraction in demand or the total addressable market and the risks related to the outcome of contract renegotiations. For more information see the specific risk paragraph in "Item 3 – Risk factors".

 

Refining & Marketing

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

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

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

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

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

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

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

 

Chemicals

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

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

 

Engineering & Construction

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

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

 

Capital expenditure plans

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

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

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

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

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

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

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

Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 90 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2019 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital to the Group. In 2014, management assessed that the cost of capital to the Group decreased from the previous year mainly reflecting a reduction in the premium for the sovereign risk incorporated into the yields on Italian ten-year bonds, and, to a lower extent, a reduced market risk premium of the Eni share. The other financial parameters used for assessing the cost of capital: the cost of borrowings to Eni determined by expected trends in borrowing spreads and management’s estimates about the composition of the Company’s financial debt and ratio of net borrowings to equity, were substantially unchanged from the previous reporting period; (ii) an appreciation of the country risk which factors in the perceived level of risk associated with each country of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework, as well as the

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

 

Liquidity and leverage

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

For planning purposes, management assumes a declining scenario of Brent crude oil prices from approximately 100 $/BBL in 2014 to 63 $/BBL on average in the years 2015-2016, and expects a recovery in the years 2017-2018 up to the Company’s long-term Brent price of 90 $/BBL. Our recovery assumption is supported by the industry reaction to the current weak oil price. Based on the announcement and plans declared by other oil companies which point to spending reductions, we believe that an oil shortage could emerge sometime in the medium to long term, assuming a 5% per annum declining rate at existing fields, whereas oil demand could be stimulated by low oil prices and then could start growing again.

In the short to medium term, management plans to mitigate the effects of projected lower revenues in the Exploration & Production segment on the expected cash flows from operation by reducing capital expenditures, the level of which was reset at euro 12 billion per year, and by achieving efficiencies in the Exploration & Production operating costs and in corporate general and administrative costs. The planned reduction in capital expenditures, which will foresee a 17% reduction versus the previous plan at constant exchange rate assumptions, will leverage on:

•		a reduction in exploration expenditures which will be mainly focused on low-risk activities, particularly on replacing produced reserves in proven areas and nearby producing assets;
•		a reduction in development expenditures by rescheduling the activities at certain large projects without jeopardizing the achievement of the Company’s targets of production growth;
•		a reduction of capital expenditures in refining and chemicals due to the shutdown of certain plants which will require fewer investments than in the past and the disposal of certain assets under development like the divestment of our interest in the South Stream project which was defined at the end of 2014; and
•		renegotiations of contracts for oilfields services and other supplies in our Exploration & Production segment.

We expect that in the years 2015-2016 our cash flow from operations will be able on average to fund our projected capital expenditures. In the subsequent years, under our planning assumption of a recovery in crude oil prices and considering our industrial actions, we will able to increase our cash flow from operations by 40% thus generating a significant surplus over the projected level of capital expenditures. Furthermore, management expects to deliver approximately euro 8 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of excess stakes in our exploration assets. We believe that the market value of our discoveries has only been impacted by the current weak price environment and that many operators may be interested in acquiring stakes in certain of our assets thanks to their robustness in terms of size, location, cost structure and other industry parameters. These additional cash flows will put the Company in the position to retain degrees of flexibility in order to achieve certain Company’s corporate purposes including support to a high credit rating and payment of dividends to shareholders. In addition, we expect that our disposals will be completed in large part within 2015-2016. Overall, we believe that the Group leverage will remain within the 0.30 ceiling across the weakest years of our financial plans and then improve in line with the expected trends in the price scenario and our planned improvement in cash generation. This forecast factors in our pricing assumptions and considers the planned actions in terms of capital discipline, cost control, restructuring of our Gas & Power, Refining & Marketing and Chemical businesses which will turn cash positive in the plan period due to contract renegotiations, expansion in profitable market segments and reduced exposure to the commodity risk, as well as asset disposal.

Our cash flow projections are exposed to the risks of further deterioration in the oil price environment. Currently, based on our portfolio of oil&gas properties, we estimates that, holding all other factors constant, our net profit and cash flow changes by approximately euro 0.15 billion for each dollar variation in Brent prices on a yearly basis compared to our price forecasts. We note that the Brent price in the period January 1 to March 31, 2015 was 54 $/BBL on average. We retain additional levels of flexibility that we may use in case the current decline in oil prices may result sharper or more prolonged than our assumptions. Particularly, approximately half of the investment in the four-year plan have been allocated to projects yet to be sanctioned. In addition, we retain cash reserves and committed and uncommitted borrowing facilities.

For planning purposes, management assumed an average exchange rate of 1.185 U.S. dollars per euro in the 2015-2018 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty, as well as a potential positive

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driver of the Group results of operations, cash flow and balance sheet in case the current appreciation of the U.S. dollar versus the euro continues. We note that in the first quarter of 2015 the euro vs. the U.S. dollar exchange rate was 1.13. This trend will favorably impact the reported amounts of operating profit and operating cash flow in our Exploration & Production segment. However, the net impact of the U.S. dollar appreciation on the Group liquidity and net borrowings is uncertain as our capital expenditures are mainly denominated in U.S. dollars. See "Item 3 – Risk factors".

 

Dividend policy

Management plans to pay a dividend of euro 1.12 per share for fiscal year 2014 subject to approval from the General Shareholders’ Meeting scheduled in May 2015. Of this, euro 0.56 per share was paid in September 2014 as an interim dividend with the balance of euro 0.56 per share expected to be paid in late May 2015.

Considering the current weak oil price scenario, the Company decided to rebase the annual dividend at euro 0.8 per share in relation to 2015 fiscal year, while confirming in the following years a progressive distribution policy taking into account our expected underlying earnings growth.

The dividend is based on management’s planning assumptions of a declining Brent scenario down from 100 $/BBL in 2014 to 55 $/BBL in 2015 and of a recovery in the subsequent years up to the long-term price of 90 $/BBL.

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

The expectations described above are subject to risks, uncertainties and assumptions associated with the oil and gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, political instability in Libya and other countries, crude oil and natural gas prices; demand for oil and gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to "Item 3 – Risk factors".

 

Off-balance sheet arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in "Item 18 – note 36 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements". Eni’s principal contractual obligations, including commitments under take-or-pay or ship-or-pay contracts in the gas business, are described under "Contractual Obligations" below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses.

Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources.

Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in "Item 18 – note 36 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements".

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Contractual obligations

Amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

	Maturity year

	Total		2015		2016		2017		2018		2018		2020 and thereafter

(euro million)

Total debt		29,912		10,360		3,327		3,234		1,462		2,820		8,709
Long-term finance debt		22,942		3,533		3,226		3,217		1,462		2,795		8,709
Short-term finance debt		2,716		2,716
Fair value of derivative instruments		4,254		4,111		101		17				25
Interest on finance debt		4,775		792		702		609		478		413		1,781
Guarantees to banks		173		173
Non-cancelable operating lease obligations (1)		2,985		606		468		398		314		242		957
Decommissioning liabilities (2)		16,570		217		191		194		326		264		15,378
Environmental liabilities (3)		1,665		300		283		234		298		177		373
Purchase obligations (4)		223,926		19,317		16,346		15,622		15,201		14,645		142,795
Natural gas to be purchased in connection with take-or-pay contracts (5)		210,798		16,479		14,725		14,034		14,078		13,616		137,866
Natural gas to be transported in connection with ship-or-pay contracts (5)		9,562		1,771		1,212		1,184		934		843		3,618
Other take-or-pay and ship-or-pay obligations		965		123		118		106		98		97		423
Other purchase obligations (6)		2,601		944		291		298		91		89		888
Other obligations (7)		130		3		3		3		3		2		116
of which:
- Memorandum of intent relating to Val d’Agri		130		3		3		3		3		2		116
Total		280,136		31,768		21,320		20,294		18,082		18,563		170,109

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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 re-gasification facilities in the United States of euro 1,317 million.
(7)		In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans; see “Item 18 – note 30 – of the Notes on Consolidated Financial Statements”.

The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment as of December 31, 2014. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown.

	Total		2015		2016		2017		2018		2019 and thereafter

Committed projects

32,126

10,376

8,188

5,039

3,103

5,420

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term finance requirements and to settle obligations.

Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as

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a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. The Group has also established a cash reserve which consists of cash on hand and very liquid financial assets (short-term deposits and securities) the amount of which according to management plans can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or ensure the funding of the Group contractual obligations with respect to the repayment of financing debt at maturity over a 24-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – note 36 of the Notes on Consolidated Financial Statements”.

As of December 31, 2014, Eni maintained short-term unused borrowing facilities of euro 12,698 million, of which euro 41 million committed. Long-term committed borrowing facilities amounted to euro 6,598 million, of which euro 647 million were due within 12 months, which were completely undrawn at the balance sheet date. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 13.3 billion were drawn as of December 31, 2014.

 

Working capital

Management believes that, taking into account unutilized credit facilities, Eni’s credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements.

 

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amount due. For a description of how the Company manages the credit risk see "Item 18 – note 36 of the Notes on Consolidated Financial Statements".

For information about credit losses in 2014 and the allowance for doubtful accounts see "Item 18 – note 11 of the Notes on Consolidated Financial Statements".

 

Market risk

In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see "Item 18 – note 36 of the Notes on Consolidated Financial Statements".

 

Research and development

For a description of Eni’s research and development operations in 2014, see "Item 4 – Research and development".

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Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

The following table lists the Company’s Board of Directors as at April 2015⁶:

Name		Position		Year elected or appointed		Age
Emma Marcegaglia		Chairman		2014		49
Claudio Descalzi		CEO		2014		60
Andrea Gemma		Director		2014		41
Pietro A. Guindani		Director		2014		57
Karina A. Litvack		Director		2014		52
Alessandro Lorenzi		Director		2011		66
Diva Moriani		Director		2014		46
Fabrizio Pagani		Director		2014		48
Luigi Zingales		Director		2014		52

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

The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on May 8, 2014, which also established the number of Directors at nine for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2016.

The Board of Directors is appointed by means of a slate voting system: slates may be presented by the shareholders representing at least 0.5% of share capital. According to the Eni By-laws, three out of nine Directors are appointed from among the candidates of the non-controlling shareholders.

Emma Marcegaglia, Claudio Descalzi, Andrea Gemma, Diva Moriani, Fabrizio Pagani and Luigi Zingales were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina Litvack and Alessandro Lorenzi were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Emma Marcegaglia as the Chairman of the Board of Directors and, on May 9, 2014, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.

The provisions designed to ensure gender balance were applied for the first time in the afore mentioned elections. Three Directors out of nine, including the Chairman, were drawn from the less represented gender, thereby already reaching the ratio of one-third of the Directors, instead of the ratio of one-fifth as provided by the law for the first relevant election of the Board. The ratio of one-third of the Directors belonging to the less represented gender shall also apply to the next two subsequent terms of the Board of Directors.

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

Emma Marcegaglia has been Chairman of Eni since May 2014. She was born in Mantua in 1965. She graduated in Business Economics at the Bocconi University in Milan and attended a Master in Business Administration at New York University. She is President of Businesseurope and Luiss Guido Carli University, Deputy Chairman and CEO of Marcegaglia SpA, Member of the Board of Directors of Bracco SpA, Italcementi SpA and Gabetti Property Solutions SpA. She is Chairman of Fondazione Eni Enrico Mattei, appointed in November 2014. From May 2008 to May 2012, she was President of Confindustria. She was also a Member of the Management Board of Banco Popolare and Director of FinecoBank SpA. From May 2004 to May 2008, she was appointed as Deputy Vice President of Confindustria for infrastructures, energy, transport and environment, also acting as the Italian Representative for the High Level Group established by the European Commission for energy, competitiveness and environment. From 2000 to 2002, she was Vice President of Confindustria for Europe; from 1996 to 2000, President of the Young Italian Entrepreneurs Association of Confindustria; from 1997 to 2000, President of the European Confederation of the Young Entrepreneurs (YES) and from 1994 to 1996, she was National Vice President of the Young Italian Entrepreneurs Association of Confindustria.

Claudio Descalzi has been CEO of Eni since May 2014. He was born in Milan in 1955 and he graduated in physics in 1979 from the University of Milan. He is currently Vice President of Confindustria Energia and Director of Fondazione Teatro alla Scala. He joined Eni in 1981 as oil&gas field petroleum engineering and project manager, for the development of North Sea, Libya, Nigeria and Congo. In 1990, he was appointed Head of reservoir and operating

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activities for Italy. In 1994, he was named Managing Director of Eni subsidiary in Congo and in 1998 Vice Chairman & Managing Director of Naoc, Eni subsidiary in Nigeria. From 2000 to 2001, he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005, he was Executive Vice President for Italy, Africa, Middle East covering also the role of Chairman of the board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of Eni - Exploration & Production Division. From 2006 to 2014, he was President of Assomineraria. From 2008 to 2014, he was Chief Operating Officer of Eni - Exploration & Production Division. From 2010 to 2014, he held the position of Chairman of Eni UK. In 2012, Claudio Descalzi was the first European in the field of oil&gas to receive the prestigious "Charles F. Rand Memorial Gold Medal 2012" award by the Society of Petroleum Engineers and the American Institute of Mining Engineers.

Andrea Gemma has been Director of Eni since May 2014. He was born in Rome in 1973. He is Professor of Private Law at The Third University of Rome, Department of Law, Member of the Strategic Board of the American University of Rome. Cassationist Lawyer and Partner of the Law and Tax Firm Gemma & Partners. He is a Member of the Banking and Financial Ombudsman (ABF) at the Rome College appointed by Bank of Italy, Member of the Studies Centre of the Chamber of Arbitration of Rome, Arbitrator at the Chamber of Arbitration of Public Works. He is Chairman of Immobiliare Strasburgo Srl, Deputy Chairman of Serenissima SGR SpA and Chairman of the Watch Structure of Sorgent-e SpA. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA, Sequoia Partecipazioni SpA, Suditalia Compagnia di Assicurazioni e Riassicurazione SpA and Alpi Assicurazioni SpA, Liquidator of Corit SpA and Sigrec SpA (Unicredit Group). He was Official Receiver of Dima Costruzioni SpA and Progress Assicurazioni SpA. In 2012, he was Member of the Ministerial Commission for the reform of the bankruptcy proceedings and extraordinary administration procedures. In 2010-2012, he was appointed by the Minister of Justice as implementer of the Prison Plan and, in 2008-2009, Expert of the working group of the Commission appointed by the Premiership and officiated by the Minister for the European policies for the implementing of the European legislation.

Pietro A. Guindani has been Director of Eni since May 2014. He was born in Milan in 1958. He graduated in Business at the Bocconi University in Milan. From 1982 to 1986, he was Relationship Banker of Citibank N.A. Subsequently, he became Director International Finance Department of Montedison SpA (Enimont SpA) until 1992. He was Group Finance, Budget and Reporting Manager of European Vinyls Corporation SA/NV (1992-1993). In 1993, he became International Finance Director of Olivetti SpA. From 1995 to 2004, he was Chief Financial Officer of Vodafone Italy and of Vodafone South Europe, Middle East & Africa Region. From 2004 to 2008, he was Chief Executive Officer of Vodafone Omnitel NV. Currently, he is Chairman of the Board of Directors of Vodafone Omnitel BV, Board Member of FINECOBank SpA, of Salini-Impregilo SpA and of the Italian Institute of Technology, President of the Bocconi University Alumni Association, Board Member of Civita Foundation, Assonime and Confindustria, Vice President for Universities, Innovation and Human Capital of Assolombarda. He was also Director of Pirelli & C SpA (2011-2014), Carraro SpA (2009-2012) and Sorin SpA (2009-2012).

Karina A. Litvack has been Director of Eni since May 2014. She was born in Montreal in 1962. She graduated in Political Economy at the University of Toronto. She is currently a Member of the Global Advisory Council of Cornerstone Capital Inc, a Member of the Advisory Board of Bridges Ventures Llc, a Member of the CEO Sustainability Advisory Panel of SAP AG, a Member of Business for Social Responsibility and of Yachad, and a Member of the Advisory Council of Transparency International UK. From 1986 to 1988, she was a member of the Corporate Finance team of PaineWebber Inc. From 1991 to 1993, she was a Project Manager of the New York City Economic Development Corp. In 1998, she joined F&C Asset Management plc where she held the position of Analyst Ethical Research, Director Ethical Research and Director Head of Governance and Sustainable Investments (2001-2012). She was also a Member of the Board of the Extractive Industries Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012).

Alessandro Lorenzi has been a Director of Eni since May 2011. He was born in Turin in 1948. He is currently a founding partner of Tokos Srl, consulting firm for securities investment, Chairman of Società Metropolitana Acque Torino SpA, Director of Ersel SIM SpA and Millbo SpA. He began his career at SAIAG SpA, in the Administration and Control area. In 1975, he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat VI SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983, he joined the GFT Group, where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of the GFT Group (1984-1988), Head of Finance and Control of the GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995, he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998, he was appointed Central Manager and subsequently, Director of Ersel SIM SpA until June 2000. In 2000, he became Central Manager of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003, he was appointed CFO of Coin Group. In 2006, he became Central Corporate Manager at Lavazza SpA, becoming member of the Board of Directors from 2008 to June 2011.

Diva Moriani has been Director of Eni since May 2014. She was born in Arezzo in 1968. She graduated in Economics at the University of Florence. She is actually Executive Vice Chairman of Intek Group SpA, CEO of KME AG Vorstand, German holding company of KME Group, Member of the Supervisory Board of KME Germany GmbH and Director of Moncler SpA, Ergycapital SpA, Dynamo Academy, KME Srl, Dynamo Foundation and Associazione

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Dynamo. From 2007 to 2012, she was CEO of I2Capital Partners, private equity fund sponsored by Intek SpA, with an investment strategy focused on Special Situation.

Fabrizio Pagani has been Director of Eni since May 2014. He was born in Pisa in 1967. He graduated in International Studies at the Scuola Superiore Sant’Anna, Pisa, and received a Master from the European University Institute, Florence. He has been visiting scholar at the Columbia University, New York. Currently, he is the Head of the Office of the Minister of Finance. He has been Senior Economic Counsellor of the Prime Minister and G20 Sherpa from 2013 to 2014; Director of the G8/G20 Office at the OECD from 2011 to 2013; Political Counsellor of the OECD General Secretary from 2009 to 2011; Director of SACE from 2007 to 2008; Head of the Office of the State Undersecretary, within the Prime Minister Office; Senior Advisor at the OECD from 2002 to 2006; Counsellor for International Affairs of the Minister of Industry and Foreign Trade from 1999 to 2001; Deputy Chief of the Legislative Office at the Department of European Affairs from 1998 to 1999; Professor of International Law at the School of Political Science at the University of Pisa from 1993 to 2001; Deputy Director of the International Training Programme for Conflict Management at the School S. Anna of Pisa, from 1995 to 1998; he has been NATO Fellow.

Luigi Zingales has been Director of Eni since May 2014. He was born in Padua in 1963. He graduated in Economics at the Bocconi University in Milan and earned a doctorate in Economics at the Massachusetts Institutes of Technology of Cambridge. He is actually “Robert C. McCormack Professor of Entrepreneurship and Finance” at the University of Chicago Booth School of Business. He is also Research Associate at the National Bureau of Economic Research, Research Fellow at the Center for Economic Policy Research, Fellow at the European Corporate Governance Institute, Member of the Committee on Capital Market Regulation, Member of the American Academy of Arts and Sciences and Past President of the American Finance Association. He was Taussig Research Professor at the Harvard University of Cambridge from 2005 to 2006 and from 2014 to 2015; Assistant, Associate and Full Professor of Finance “Robert C. McCormack Professor of Entrepreneurship and Finance” at the University of Chicago Booth School of Business from 1992 to 2005; Director of the American Finance Association from 2005 to 2008; Member of the United Nation Commission on Microfinance from 2006 to 2007; Director of Telecom Italia SpA from 2007 to 2014 and Lead Independent Director of Telecom Italia SpA from 2011 to 2014. He is also author of many publications in economic and financial matters.

 

Senior Management

The table below sets forth the composition of Eni’s Senior Management as at December 31, 2014. It includes the CEO, as General Manager of Eni SpA, as well as the Chief Officers and the Executives who report directly to the CEO and to the Board, and on its behalf, to the Chairman in compliance with the new organizational structure, approved by the Board of Directors on May 28, 2014 and in effect as from July 1, 2014.

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Name		Management position		Year first appointed to current position		Total number of years of service at Eni		Age
Claudio Descalzi		General Manager of Eni		2014		34		60
Marco Alverà		Chief Midstream Officer (1)		2013		10		39
Luca Bertelli		Chief Exploration Officer		2014		30		56
Roberto Casula		Chief Development, Operations & Technology Officer		2014		26		52
Claudio Granata		Chief Services and Stakeholder Relations Officer		2014		31		54
Massimo Mantovani		Chief Legal & Regulatory Affairs (2)		2005		21		51
Massimo Mondazzi		Chief Financial and Risk Management Officer (3)		2012		23		51
Salvatore Sardo		Chief Downstream & Industrial Operations Officer (4)		2014		10		62
Antonio Vella		Chief Upstream Officer		2014		31		57
Marco Petracchini		Internal Audit Department (5) Senior Executive Vice President		2011		16		50
Roberto Ulissi		Board Secretary and Corporate Governance Counsel (6) Corporate Affairs and Governance Department Senior Executive Vice President		2006		9		52
Angelo Zaccari		Retail Market G&P Department Senior Executive Vice President		2014		6		61
Rita Marino (7)		Procurement Department Executive Vice President		2014		9		50
Camilla Alessandra Palladino (8)		Media Relations Senior Vice President		2014		8		36
Pasquale Salzano		Government Affairs Department Senior Vice President (9)		2014		3		41

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The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief Midstream Officer⁷, the Chief Downstream & Industrial Operations Officer⁸, the Senior Executive Vice President Retail Market G&P Department, the Chief Financial and Risk Management Officer, the Chief Services & Stakeholder Relations Officer, the Chief Legal & Regulatory Affairs, the Senior Executive Vice President Internal Audit Department, the Senior Executive Vice President Corporate Affairs and Governance Department, as well as the Executive Vice President Procurement Department, the Senior Vice President Media Relations⁹, the Senior Vice President Government Affairs¹⁰ and the Chief Executive Officer of Versalis SpA are members of the Management Committee, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend

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meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of Committee Secretary are performed by the Senior Executive Vice President Corporate Affairs and Governance.

The Chief Financial and Risk Management Officer has been appointed as Officer in charge of preparing Company’s financial reports pursuant to Italian law by the Board of Directors, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors.

The Senior Executive Vice President of the Internal Audit Department is appointed by the Board of Directors, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer (in his capacity as Director in charge of the internal control and risk management system), following consultation with the Board of Statutory Auditors and the Nomination Committee and with the favorable opinion of the Control and Risk Committee.

The Board Secretary and Corporate Governance Counsel is appointed by the Board of Directors upon a proposal of the Chairman.

Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause.

 

Senior Managers

Marco Alverà was born in New York in 1975. Graduated in Philosophy and Economics from the London School of Economics in 1997, he is currently an Associate Fellow at the Oxford University Centre for Corporate Reputation. He began his career at Goldman Sachs in London in 1996, working in M&A and Private Equity. In 2000, he founded Netesi, Italy’s first broadband ADSL company. From 2002 to 2005, he worked at Enel as Director of Group Corporate Strategy, becoming Chief Financial Officer of Wind Telecom in 2004 and overseeing the sale of Wind to Orascom. He joined Eni in 2005 as Assistant to the Chief Executive Officer for special projects. In 2006, he was appointed Director of Supply & Portfolio Development at Eni’s Gas & Power Division and Chief Executive Officer of Bluestream and Promgas. In 2008, he moved to Eni’s Exploration & Production Division as Executive Vice President for Russia, North Europe and North and South America. In these countries he managed operations and led negotiations with governments and other international oil companies. Since 2010, he has been Chief Executive Officer of Eni Trading and Shipping SpA, which manages all the commodity Trading and Shipping activities for Eni. In January 2012, he was appointed Senior Executive Vice President of Eni Trading and, in March 2013, Senior Executive Vice President of Optimization and Trading. In July 2013, in his role as Senior Executive Vice President, he took on responsibility for the business unit Midstream, which brings together all of the commodity supply and trading activities, the development and optimization of the assets portfolio, the integrated management of commodity risks, the commercial development of the LNG portfolio and large gas & power accounts, the management and development of gas transport assets and primary logistics. He has also been a Board member of Gazprom Neft and since July 2014, a Board member of Eni Foundation. Since July 1, 2014, he has been Eni’s Chief Midstream Officer. Since February 19, 2015, he has been Chief Midstream Gas & Power Officer.

Luca Bertelli was born in Sesto Fiorentino in 1958. He graduated cum laude in geology in 1983 from the University of Florence. In 1984, joined Eni’s geophysics division where he worked first as a researcher in the development of 3D seismic prospecting technology and subsequently as a manager of 3D seismic prospecting programs, and specializing in seismic-stratigraphy. In 1994, he was appointed Manager of seismic-stratigraphy applications and in 1999 expanded the technical-managerial scope of his activities becoming Eni’s Manager of geological and geophysical services. At the end of 2001, his career took a new international turn with roles of increasing managerial complexity over a period of eight years, starting in Norway where he was Technical Director and Deputy Managing Director of Norsk Agip. In 2003, he was appointed Managing Director of Eni Indonesia and in 2006, moved to Egypt as General Manager and Managing Director, a role he covered also at Eni Angola in 2007. In 2009, he returned to Eni’s headquarters as Senior Vice President Global Exploration. At the beginning of 2010, he was appointed Executive Vice President of Exploration and Unconventional. Since July 1, 2014, he has been Eni’s Chief Exploration Officer.

Roberto Casula was born in Cagliari in 1962. He graduated in mining engineering from the University of Cagliari and joined Eni in 1988 as a reservoir engineer. He spent the first years of his professional life working at oilfields in Italy before moving to west Africa where he was appointed Chief Development Engineer. He returned to headquarters in 1997 as coordinator business development activities for Africa and the Middle East, contributing to a number of new initiatives and portfolio activities. In 2000, he became Project Technical Services Manager and in 2001, moved to the Middle East as Project Director on a giant gas production project. From 2004 to 2005, he held a number of managerial positions in the Exploration & Production Division, becoming Chief Executive Officer of Eni Mediterranea Idrocarburi SpA, engaged in oil and gas exploration and production in Sicily. At the end of 2005, he was appointed Managing Director of Eni’s activities in Libya, where he remained for two years and concluded the renegotiation of oil contracts and launched an important program of social projects. In October 2007, he became head of operational and business activities in Sub-Saharan Africa as Senior Vice President, based in Nigeria. In December 2011, he was appointed

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Executive Vice President of Eni’s Exploration & Production Division and extended his responsibilities to include the whole of Africa and the Middle East and coordinating the Mozambique program for the development of the Mamba and Coral discoveries. Since July 2014, he has been a Board member of Eni Foundation. Since July 1, 2014, he has been Eni’s Chief Development, Operations & Technology Officer.

Claudio Granata was born in Rome in 1960. Graduated in economics, he joined the Eni Group in 1983. From 1983 to 1994, he worked as a labor market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999, he continued his experience with Eni Corporate as an expert in industrial relations. In 2000, he was given responsibility for Staff and Organization within Eni Servizi Amministrativi, a company that was set up to centralize Eni’s administrative activities. In 2001, he took over the management of Eni’s territorial divisions, for which he structured the management of the staff by geographical area and, in 2003, he took on the role of Business HR for Eni Corporate, ensuring support for Departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), characterized by the mergers by incorporation of Snam and AgipPetroli and the redefinition of the organizational structures for the staff. In the same year he was also appointed as director of personnel and organization of Sofid (Eni’s financial services company). In 2006, he was appointed Human Resources Director of the Exploration & Production Division, where he oversaw the Planning, Management, Development and Compensation processes for the human resources and organization activities. He also collaborated with the top management in the reorganization of macro processes for the Division and promoted Change Management initiatives. From 2006, he has been a Board member of Eni International Resources Ltd, and from 2012 to 2013, he has been appointed as Chairman of the board of Eni International Resources Ltd. From 2012 to March 2015, he has been a Board member of Eni UK Ltd. Since 2013, he has been Executive Vice President Sustainable Development, Safety, Environment and Quality at Exploration & Production Division, with responsibility for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in time to market and efficiency. Since July 2014, he has been a Board member of Eni Foundation. Since November 2014, he has been Chairman of the Board of Eni Corporate University. Since July 1, 2014, he has been Eni’s Chief Services & Stakeholder Relations Officer.

Massimo Mantovani was born in Milan in 1963. He graduated in Law from the University of Milan and has a Master in Law (LLM) from the University of London. He was admitted to practice law in Italy as Avvocato and in England as Solicitor. He practiced law at a number of Legal offices in Milan and London for around 5 years and joined Eni’s Legal Department in 1993 where he was mostly involved in international issues. In October 2005, he was appointed Eni’s Senior Executive Vice President Legal Affairs, since when he has also been a member of the Company’s Supervisory Board. He is a member of the ICC Paris corporate responsibility and anti-corruption commission and, since 2011, he has been involved in the work of the B20 anti-corruption group. He was a member of the Board of Snam SpA¹¹ from 2005 to 2012 and of University of Bologna from 2011 to 2012. He is the author of numerous publications and he also carries out teaching activities. Since July 1, 2014, he has been Eni’s Chief of Legal and Regulatory Affairs.

Massimo Mondazzi was born in Monza in 1963. He graduated in Economics and Business Administration from Bocconi University in 1987 and he joined Eni in 1992, after a number positions in industrial companies as a management consultant. He worked in the Administration and Control area of the Exploration & Production Division until 2006, where he reached the level of Director. From 2006 to 2009, he was the Director of Planning and Control for the Eni Group, before returning to the Exploration & Production Division as the Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration & Production Division, to the launch of new development projects and to Eni’s entry into new countries. On December 5, 2012, he was appointed Chief Financial Officer of Eni and Manager charged with preparing Company’s financial reports pursuant to Article 154-bis of Italian Legislative Decree No. 58/1998. Since July 1, 2014, he has been Eni’s Chief Financial and Risk Management Officer.

Salvatore Sardo was born in Turin in 1952. He graduated in economics from the University of Turin. He is also a chartered Auditor. From September 1976 to 1981, he worked for Coopers & Lybrand as an auditor, rising to the level of supervisor. In 1981, he moved to Stet where he was initially responsible for management control for manufacturing activities, becoming central co-director in 1992 and, from 1996, Central Director of Planning & Control. In 1997, he joined Telecom Italia as Deputy General Manager of Administration & Control and from 1998 to June 2001, he was chairman of Seat Pagine Gialle SpA. From October 1999, he was operational head of Telecom Italia’s Real Estate Department, Chairman of EMSA, Chairman and Managing Director of EMSA Servizi and Chairman and Managing Director of IMMSI, a company listed on the Milan stock exchange, as well as Operating Chairman of TELIMM, IMSER and Telemaco, companies in the same sector. From October 1, 2001, he was head of the Real Estate and General Services unit of the Telecom Italia Group, reporting directly to the Chief Executive, and from November 2000, he was head of the Telecom Italia Real Estate and Service BU. In February 2003, he joined Enel as Head of Group Procurement, Services and Security, reporting directly to the Chief Executive. He joined Eni in 2005 as Director of Human Resources and Business Services, reporting directly to the Chief Executive, and also overseeing the operational guidelines and control of the Information & Communication Technology unit and the EniServizi subsidiary. From November 2008 to June 2014, he was appointed Eni’s chief corporate operations officer, reporting directly to the Chief

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Executive, overseeing the operational guidelines and control of procurement, Human Resources and Organization, Information & Communication Technology, Health, Safety, Environment & Quality, Security, Compensation & Benefits and the EniServizi subsidiary. From April 2009 to November 25, 2014, he was also appointed Chairman of Eni Corporate University. From April 2010 to October 2012, he was Chairman of Snam. From April 2013 to July 2014, he was a member of the Board of the Eni Foundation. In April 2013, he was appointed Chairman of Versalis From April 2008 to April 2011, he was a member of the Board and member of the Remuneration Committee of Saipem. On June 2, 2008, he was made a Commendatore dell’Ordine al Merito della Repubblica Italiana and on July 8, 2011, a Grande Ufficiale dell’Ordine al merito della Repubblica Italiana, two of the Country’s highest institutional honors. He has also been a standing statutory auditor of Italtel, Finsiel and Telecom Italia. From July 2014 to February 2015, he was Eni’s Chief Downstream & Industrial Operations Officer, reporting directly to the Chief Executive Officer. Versalis, Syndial and EniPower report to the Chief Downstream & Industrial Operations Officer. Since February 19, 2015, he has been Chief Refining & Marketing and Chemicals Officer.

Antonio Vella was born in 1957. He is currently Chief Upstream Officer of Eni SpA. From December 2012 to May 2014, Antonio Vella held the position of Eni Exploration & Production Division Executive Vice President Central Asia, Far East and Pacific Area. In 2009, he was appointed Executive Vice President Operations of Eni Exploration & Production Division. From 2006 to 2009, he was Regional Senior Vice President North Africa and Middle East Area (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) of Eni Exploration & Production Division. From 2002, he was Regional Vice President for Australasia, Russia, Azerbaijan and then in 2005 Board Member & Managing Director of Eni Algeria. In 1999, he held the position of District General Manager of Nigerian Agip Oil Co (NAOC), and in 2000, he became Vice Chairman and Managing Director of NAOC, NAE (Nigerian Agip Exploration) and AENR (Agip Energy), Eni’s affiliated companies in Nigeria. In 1991, he was appointed Project Manager for the development of the Libyan fields, and in 1993, he moved to Egypt first as Operations Manager and then as General Manager and Managing Director of Petrobel in charge of all Eni upstream operations in Egypt. From 1988 to 1991, he worked as Project Manager in EniChem’s petrochemical plants and refineries in Italy. Antonio Vella joined the Eni Group in 1983, where he started his professional career as Petroleum Engineer in Agip Name, a subsidiary of the Eni Group in Libya, in onshore and offshore upstream operations. Antonio Vella graduated in Petroleum Engineering from the Polytechnic of Turin in 1982.

Marco Petracchini was born in Rome in 1964. He graduated Cum Laude in Economics from La Sapienza University in Rome in 1989. After graduation, he was hired by Esso Italiana where he held various positions in the IT, Finance and Auditing sectors. He joined Eni in 1999 in the Internal Audit Department, gradually taking on positions of increasing responsibilities: Head of Downstream Audit activities and Head of Support Process Audit activities (in particular IT and Fraud Audit). He is also a member of the Watch Structure of Eni SpA and Secretary of the Control and Risk Committee of Eni SpA. He holds international qualifications as well, in detail: Certified Internal Auditor (CIA), Certified Fraud Examiner (CFE), Certified Risk Management Assurance (CRMA). He is currently a Board member of AiiA (Italian Internal Auditors Association). He is Eni’s Senior Executive Vice President Internal Audit Department.

Roberto Ulissi was born in Rome in 1962. Lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance, head of the Banking and financial System and Legal Affairs Department. He has been a Board member of Telecom Italia (and Chairman of the Audit Committee), Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He is a Board member of Banor SIM. He was also a member of numerous Italian and European committees representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law (Commission "Vietti") and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also Special Professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel.

Angelo Zaccari was born in Naples in 1953. He has a degree in political science and after extensive experience in the oil business, in refining, supply, sales and international trading at Mobil Oil, from December 2003 to September 2006, he was marketing and sales Director and Chief Executive of Edison Energia, with responsibility for sales of natural gas and electricity. From October 2006 to April 2007, he was head of fuel procurement at Alitalia, with responsibility for a new Business Unit reporting directly to the Chairman and Chief Executive. From May 2007 to August 2008, he was Director of the market division and Chief Executive of Enìa Energia, with responsibility for sales, marketing, procurement, risk management and development of the company formerly own by the municipalities of Piacenza, Parma and Reggio Emilia. In September 2008, he was hired by Eni in the Gas & Power Division as Director of the Retail and Power Department, with responsibility for the management and development of Gas & Power sales activities for the Italian retail market and marketing. Since 2009, he continued his experience in the Gas & Power sector as market director for Italy, with responsibility for the management and development of all commercial activities and, from March 2013, as Executive Vice President of the Gas & Power Retail and Mid Market Europe Department. Since July 1, 2014, he has been Eni’s Senior Executive Vice President Retail Market Gas & Power Department.

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Rita Marino was born in Salerno in 1964. Graduated with honors in Economics from LUISS Guido Carli University in Rome in 1987, she gained twenty-five years of experience in major national industrial groups. In 2011, she was appointed Head of Procurement at Eni, after having served, since 2005, as Internal Audit Director, Internal Control Officer and Secretary of the Internal Control Committee. From 1987 to 2002, she held various positions in the Telecom Italia group, in the Planning and Management Control and Mergers & Acquisitions departments. Appointed Director in 1997, that same year she served on the team working on the privatization of Telecom Italia, and in 1999 she was the team’s M&A point of reference to counter the takeover bid for Telecom Italia launched by Olivetti. From 2003 to 2005, she worked in Enel as Manager of the Strategies, Control and Procurement Processes Department, as well as Chief Operating Officer of a company in the group. Between 2000 and 2005, she served as a member of the Board of Directors of various Telecom Italia and Enel group companies. From 2005 to 2010, she served on the Supervisory Board of Eni, and from 2009 to 2010, she was also a Board member of Associazione Italiana Internal Auditor (AIIA). Since April 2013, she is a Board member of Syndial. In 2010, she won the Bellisario "Woman Manager" prize, and since 2011, she has been on the list of "Ready For Board Women". Since July 1, 2014, she has been Eni’s Executive Vice President Procurement Department.

Camilla Alessandra Palladino was born in Milan in 1978. Graduated in modern history and English at the University of Oxford in 1999. From 2001 to 2006, she was a journalist in London at Breakingviews.com, a financial comment and analysis service syndicated across a number of European newspapers, including the Wall Street Journal Europe and La Repubblica. She joined Eni in 2006 as head of Internal Communications. From November 2010 to September 2013, she was Senior Vice President Investor Relations, with responsibility for providing mandatory financial information and relations with investors. Since October 1, 2013, she has been Eni’s Senior Vice President Media Relations.

Pasquale Salzano was born in Pomigliano d’Arco (Naples) in 1973. In 1996, he graduated with Honors in Law from the University “Federico II” in Naples and in 2000 obtained a PhD in international law from the University of Siena. From 1996 to 1999, he collaborated with Prof. Benedetto Conforti at the Chair of International Law at the University of Naples and in 2000, qualified as a Lawyer at the Naples Court of Appeals. He began his career as a diplomat in December 1999 and from January 2000 to July 2001, worked on legal and institutional issues regarding the European Union at the General Directorate for European Integration of the Italian Ministry of Foreign Affairs. In 2001, in the aftermath of the Balkan conflict, Pasquale Salzano was appointed Chief of Staff of the international OSCE Mission in Belgrade and the following year was posted by the Italian Government to Pristina to establish and manage the Italian Liaison Office at the Special Representative of the Secretary-General of the United Nations in Kosovo, which subsequently became the Italian Embassy. From 2005, he was in New York at the Permanent Mission of Italy to the United Nations and, after about two years, was posted to Rome to the Office of the Diplomatic Adviser to the Prime Minister where, in view of the Italian Presidency of the G8, was appointed by the Prime Minister as Head of the Sherpa Office for the G8/G20. In 2009, he was selected by the OECD Secretary-General as Director of the Heiligendamm/L’Aquila Process in Paris. From January 2011, he was seconded by the Ministry of Foreign Affairs to Eni, where he was appointed Vice President, International Institutional Relations in the Department of Institutional Relations and Communications and Vice President of Eni USA’s Representative office. From July 2012, he was Vice President, International Institutional Relations within the Office for Institutional and Regulatory Affairs. He is a Young Global Leader of the World Economic Forum, is a member of the Board of the European Council on Foreign Relations (ECFR) Italy, the Scientific Committee of the Rome-Mediterranean Foundation and the National Assembly of UNICEF Italy. He is a member of the Institute for International Affairs (IAI) and the Institute for International Political Studies (ISPI). From July 1, 2014, he was Eni’s Senior Vice President Government Affairs. Since February 19, 2015, he has been Eni’s Executive Vice President Government Affairs Department.

 

 

Compensation

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

Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter of Legislative Decree No. 58 of February 24, 1998 and Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications) and in line with the Corporate Governance Code recommendations for Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy Guidelines adopted for Directors and other Managers with strategic responsibilities¹².

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The main elements of the 2015 remuneration policy and of the compensation paid in 2014 to the Chairman, the CEO, other Board members and Eni’s Chief Operating Officer and of other Managers with strategic responsibilities, are described below.

 

2015 Remuneration Policy Guidelines

The guidelines for the 2015 Remuneration Policy for Executive Directors reflect the decisions made by the Board of Directors on May 28, 2014 following the renewal of the corporate bodies, based on the shareholders’ resolutions of May 8, 2014 reducing remuneration under Article 84-ter of Law No. 98/2013 and approving the 2014-2016 Long-Term Monetary Incentive Plan under Article 114-bis of Legislative Decree No. 58/1998.

For Managers with strategic responsibilities, the 2015 Guidelines provide for the same instruments used in 2014 and in particular the short and long-term incentive plans strictly in line with those of Chief Executive Officer and General Manager, to better guide and align managerial actions with the targets defined in the Company’s Strategic Plan.

 

Market references

The market references used for remuneration benchmarks are: (i) for the Chairman, Non-executive Directors and the Chief Executive Officer and General Manager, similar roles in the main international companies in the Oil sector, as well as in the national and European listed companies of greatest capitalization; and (ii) for Managers with strategic responsibilities, the roles with the same level of responsibility and managerial complexity in large national and international industrial companies.

 

General principle of clawback

A clawback mechanism will be adopted, through a specific regulation, allowing to reclaim the variable remuneration components already paid, or to withhold those subject to deferral, whose achievement took place on the basis of data that subsequently proved to be manifestly misstated, or allowing the recoupment of all the incentives of the year (or the years) for which fraudulent alteration was detected in the results data used in order to achieve the right to incentives, and/or the commission of serious and deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to the employment and trust relationship, without prejudice to any other action permitted by law and regulations to protect the interests of the Company.

 

CHAIRMAN OF THE BOARD OF DIRECTORS AND NON-EXECUTIVE DIRECTORS

Chairman of the Board of Directors

Remuneration of the Chairman for the delegated powers
The Policy Guidelines for the Chairman of the Board of Directors reflect the decisions taken by the Board of Directors on May 28, 2014, which defined a fixed remuneration for the delegated powers amounting to euro 148,000, in addition to remuneration for the position determined by the Shareholders’ Meeting on May 8, 2014, amounting to euro 90,000, in compliance with the maximum of euro 238,000 defined by the same Shareholders’ Meeting. These Guidelines do not provide for variable remuneration.

 

Payments due in the event of termination of office or employment
No specific term end payments are envisaged for the Chairman, nor do any agreements exist for indemnities in the case of early termination of the mandate.

 

Benefits
For the Chairman, the Remuneration Policy Guidelines provide, in line with the decisions taken by the Board of Directors on May 28, 2014, insurance coverage for the risk of death and permanent disability.

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Non-executive Directors

•		for the Control and Risk Committee, the remuneration amounts to euro 45,000 for the Chairman and euro 35,000 for the other members; and
•		for the Compensation Committee, the Sustainability and Scenario Committee and the Nomination Committee the remunerations amount to euro 30,000 for the Chairman and euro 20,000 for the other members.

The Policy Guidelines subsequently approved by the Board on March 12, 2015 provide for, in relation to the growing and significant commitment required of Committee members and to the results of the remuneration benchmarks, the increase in remuneration for participation in the Control and Risk Committee, proposing a remuneration of euro 60,000 for the Chairman and euro 40,000 for the other members, and the elimination, starting in 2015, of the criterion of remuneration reduction by 10% set forth in the 2014 Policy in the case of participation in several Committees, a reduction that was not objectively justified by the mode of performance of multiple roles.

 

Payments due in the event of termination of office or employment
No specific payments are provided for the term end of non-executive Directors nor do any agreements exist that provide for indemnities in the case of early termination of the mandate.

 

CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER

For the Chief Executive Officer and General Manager, the remuneration structure in 2015 defined by the Board of Directors for a full term takes into account the specific powers delegated in accordance with the Articles of Association, and with principles and general purposes of Eni Remuneration Policy, as well as the 25% reduction of the maximum payable overall remuneration of the previous mandate, in accordance with the Shareholder’s resolution of May 8, 2014. The remuneration envisaged by the Board in relation to the delegated powers includes both the compensation for Directors determined by the Shareholders’ Meeting on the May 8, 2011, as well as any compensation that may be due for participating in the Board of Directors of Eni’s subsidiaries or associated companies.

 

Fixed remuneration
The total fixed remuneration is set at a gross annual amount equal to euro 1,350,000, of which euro 550,000 for the position of Chief Executive Officer and euro 800,000 for the position of General Manager.

In his capacity as Eni Senior Manager, the General Manager is also entitled to receive an indemnity for travel, in Italy and abroad, in line with the applicable provisions provided by the relevant national collective labor agreement for senior managers and complementary Company level agreements.

 

Annual variable incentives
The 2015 annual variable incentive Plan is linked to the achievement of the predefined targets for 2014 as described in the 2014 Remuneration Report, measured according to a performance scale 70÷130, in relation to the weight assigned to each target (below 70 points, the performance of each target is considered to be zero). For the purposes of the incentive, the minimum overall performance is 85 points. This Plan provides for remuneration calculated pro-rata based on the time in office in 2014, with reference to a minimum incentive level (performance = 85), target (performance = 100) and maximum (performance = 130), respectively equal to 85%, 100% and 130% of the total fixed remuneration, in connection to the results achieved by Eni in the previous year.

The 2015 targets approved by the Board Meeting of March 12, 2015 for the 2016 annual variable incentive Plan provide for a structure focused on the essential goals, consistent with the strategies outlined for the new term and balanced against the prospects of interest to the various stakeholders, in terms of: economic and financial results (25%), operating results and sustainability of the economic performance (25%), environmental sustainability and human capital (25%), efficiency and financial strength (25%).

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•		Deferred Monetary Incentive Plan (DMI), also envisaged for all the managers of the Company, with three annual assignments, starting in 2015 and linked to the Company performance measured in terms of Earnings Before Taxes (EBT). The conditions of the Plan include in particular: (i) incentive to be given each year based on the EBT results achieved by the Company in the previous year, measured on a performance scale 70÷130, for a minimum, target and maximum value, respectively equal to 34.4%, 49.2% and 64% of the total fixed remuneration. If the results are below the minimum level of performance, no assignment is made; and (ii) the incentive to be paid at the end of the three-year vesting period set on the basis of the average annual EBT results achieved during the vesting period, as a percentage between zero and 170% of the assigned value, according to a scale between 70% and 170%. Where results are below the minimum level of 70%, the performance is considered to be zero.
•		Long-Term Monetary Incentive Plan (IMLT), approved by the Shareholders’ Meeting of May 8, 2014, also provided for managerial resources critical to the business, with three annual assignments from 2014 and linked to the performance parameters measured in relative terms compared to the peer group of reference. These parameters, in line with international best practices, are designed to ensure greater alignment with the interests of shareholders in the medium to long term, through the use of the "Total Shareholder Return"14, and a more sustainable value creation in the medium to long term, through the use of the "Net Present Value" of proved reserves. The conditions of the Plan include, in particular: (i) incentive to be given every year equal to 100% of the overall fixed remuneration; and (ii) incentive to be paid at the end of the three-year vesting period determined in relation to the results achieved in terms of variation of the identified parameters (TSR with a weighting of 60% and NPV of proved reserves15 with a weighting of 40%) in the three-year period in question in relative terms compared to a peer group consisting of the following international oil companies: Exxon, Chevron, Shell, BP, Total and Repsol. The amount to be paid is defined as a percentage of the amount assigned according to the average annual placements achieved during the vesting period, compared with those achieved by the companies in the peer group according to the following scale: 1st place = 130%; 2nd place = 115%, 3rd place = 100%; 4th place = 85%; 5th place = 70%; 6th and 7th place = 0%. The minimum incentive threshold involves reaching 5th place for both indicators in at least one year of the three-year vesting period.

Both Plans envisage that, should the current office not be renewed, the payment of each incentive assigned will occur at the natural expiry of the related vesting period, in accordance with the performance conditions defined in the Plan.

 

•		upon termination of the management employment relationship, due to non-renewal or early termination of the 2014-2017 administrative mandate, even for resignations caused by a reduction of delegated powers, there is a provision to pay an indemnity supplementing the severance pay, with mutual exemption from notice, of two years of total fixed remuneration (equal to euro 1,350,000), for a total gross amount equal to euro 2,700,000. Also with reference to the recommendation in criterion 6.C.1 subparagraph g) of the Corporate Governance Code, it is stated that, in relation to the applicable contractual provisions, such compensation is not paid in case of dismissal for "just cause" under Article 2119 of the Italian Civil Code or in cases of resignations as Chief Executive Officer before the expiry of the mandate, not justified by an essential reduction of delegated powers, as well as in the event of death governed by Article 2122 of the Italian Civil Code; and
•		non-competition agreement that can be activated by the Board of Directors through an option right, to be exercised within a possible second administrative term, against a specific consideration of euro 500,000 gross to be paid in three annual installments. If the option is exercised by the Board and the agreement is implemented, the consideration is paid against a commitment undertaken by the Chief Executive Officer and General Manager not to perform, for the twelve months following the expiry of the mandate, any activities of Exploration & Production that could be in competition with Eni in key markets worldwide. This amount will be set by the Board of Directors to a linearly varying degree from euro 1,500,000 to a maximum of euro 2,250,000 based on the performance of the previous three years, making reference to the total annual remuneration, and will be paid at the expiry of the term of the agreement. Any violation of the non-competition agreement will involve the non-payment of the consideration (or its restitution, where the violation has come to Eni’s awareness after the payment), and the obligation to pay damages consensually and conventionally set at an amount equal to twice the amount of the non-competition agreement, without prejudice to Eni’s right to seek fulfillment in specific form.

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Benefits
For the Chief Executive Officer and General Manager, the Policy Guidelines provide for insurance coverage for the risk of death or permanent disability, and in compliance with what is provided for in the national collective labor agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the complementary pension plan (FOPDIRE), as well as in the supplementary health plan (FISDE) are also provided, together with a company car for business and personal use.

 

OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES

Fixed remuneration
The fixed remuneration is based on the assigned role and responsibilities, taking into consideration a graduated and possibly inferior positioning compared to the limits set by the median references of the national and international executive markets for roles with similar levels of managerial responsibility and complexity, and it may be updated periodically during the annual salary review that involves all managerial resources.

The 2015 Guidelines, in consideration of the context of reference and current market trends, provide for selective criteria, while maintaining appropriate levels for competitiveness and motivation. In particular, the proposed actions will cover measures to adapt the selective fixed/one-off for holders of positions that have increased the scope of responsibility or the level of coverage of the role, and in consideration of retention needs and excellent quality performance.

In addition, as Eni officers, the Managers with strategic responsibilities are entitled to receive the indemnities due for travel in Italy and abroad, in line with the applicable provisions of the relevant national collective labor agreement for senior managers and in the corporate complementary agreements.

 

Annual variable incentives
The annual variable incentive Plan provides for remuneration to be awarded in 2015, calculated with reference to Eni performance results, for the business areas and individuals, achieved in the previous year and measured in accordance with a performance scale of 70÷130 with a minimum incentive level equal to 85 points, below which no incentive is due, as already described for the Chief Executive Officer and General Manager. The target incentive level (performance = 100) differs by up to a maximum of 60% of the fixed remuneration, based on the role.

The targets of the Managers with strategic responsibilities are based on those assigned to the Senior Management and are focused for each business area on the economic/financial, operational and industrial performance, on internal efficiency and on sustainability issues (in terms of health and safety, environmental protection, stakeholder relations), as well as on individual targets assigned in relation to the scope of responsibilities of the role, consistent with the provisions of the Company’s Strategic Plan.

 

•		2015-2017 Deferred Monetary Incentive Plan, designed solely for the managerial resources who have delivered the performance results established in the annual Variable Incentive Plan (threshold target). The Plan provides for three annual assignments, starting in 2015, with the same performance conditions and characteristics as those described above for the Chief Executive Officer and General Manager. For the Managers with strategic responsibilities, the incentive to be assigned each year is set in relation to the EBT results achieved by the Company in the previous year, measured on a performance scale of 70÷130. The target incentive level differs, based on the role, by up to a maximum of 40% of the fixed remuneration. The incentive to be paid at the end of the three-year vesting period is determined on the basis of the average annual EBT results achieved during the three-year period, as a percentage between zero and 170% of the assigned value; and
•		2014-2016 Long-Term Monetary Incentive Plan, scheduled for the managerial resources critical for the business with three annual assignments, starting in 2014, with the same performance conditions and characteristics already described for the Chief Executive Officer and General Manager. For the Managers with strategic responsibilities, the incentive to be assigned each year differs depending upon the level of the role up to a maximum of 75% of the fixed remuneration. The incentive to be paid at the end of the three-year vesting period is set in relation to the results of the identified parameters (TSR with a weighting of 60% and

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NPV of proved reserves with a weighting of 40%) in the three-year period in question in relative terms compared to the peer group, as a percentage between zero and 130% of the assigned value.

Both Plans include clauses aimed at promoting employee retention, envisaging, in the case of consensual contract termination or transfer and/or loss of control on the part of Eni of the company of which the individual in question is an employee during the course of the vesting period, that the employee in question maintains the right to the incentive in a smaller measure based on the period between the assignment of the incentive and the occurrence of these events and in relation to the actual results for the period; no payment is envisaged in the case of unilateral termination of employment.

 

Payment due in the event of termination of employment
For Managers with strategic responsibilities, as for Eni Senior Managers, the payment due for employment termination as per the relevant national collective labor agreement is envisaged, together with any other additional severance indemnity agreed upon on an individual basis upon termination, according to the criteria established by Eni for cases of early resolution and/or retirement. These criteria take into account the retirement age and the actual age of the manager at the time when the employment is terminated and the annual remuneration received. For cases of termination that present high competitive risks relating to the criticality of the position held by the Manager, non-competition agreements may also be entered into with payments defined in relation to the remuneration received and the conditions of duration and efficacy of the agreement.

 

Benefits
For Managers with strategic responsibilities, in line with the policy implemented in 2014 and in line with what is provided for in the national collective labor agreement and the complementary company level agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE), as well as in the complementary health plan (FISDE), insurance coverage for the risk of death or disability, together with a company car for business and personal use, and the possible assignment of housing based on operational and mobility requirements.

 

PAY MIX

The 2015 Remuneration Policy Guidelines lead to a remuneration mix in line with the managerial role held, with greater weight placed upon the variable component, in particular in the long term, for roles characterized by a greater impact on Company results, as highlighted in the pay-mix diagram below, calculated by considering the value of short and long-term incentives offered for results within the target values.

 

COMPENSATION AND OTHER INFORMATION

Implementation of the 2014 remuneration policies

There follows a description of the remuneration decisions taken in 2014 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, Chief Operating Officers of Eni’s Divisions, and other Managers with strategic responsibilities, in relation to their time in office.

The implementation of the 2014 Remuneration Policy, as verified by the Compensation Committee at the regular assessment required by the Corporate Governance Code, was found to be consistent with the 2014 Remuneration Policy, approved by the Board of Directors on March 17, 2014, as further provided for by the resolutions passed by the Board of Directors on May 9 and 28, 2014 on the remuneration of Non-executive Directors called to be part of the Board Committees and on the definition of the remuneration of Executive Directors, in accordance with the resolutions passed at the Shareholders’ Meeting in accordance with Law No. 98/2013.

 

Directors in office until May 8, 2014

Chairman of the Board of Directors - Giuseppe Recchi

Fixed compensations
The Chairman Giuseppe Recchi was paid a fixed remuneration, pro-rated until May 8, 2014, approved, for the office and in relation to the delegated powers, respectively by the Shareholders’ Meeting of May 5, 2011 and by the Board of Directors Meeting of June 1, 2011.

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Variable compensation set by shareholders
In 2014, according to what was verified by the Board of Directors on March 17, 2014 as proposed by the Compensation Committee, the conditions required to pay the variable component of the remuneration approved by the Shareholders’ Meeting of May 5, 2011 to the Chairman were not met.

 

Annual variable incentives
In 2014, as verified by the Board of Directors on March 17, 2014 as proposed by the Compensation Committee, an actual performance of 114 points earned the outgoing Chairman Giuseppe Recchi the payment of a bonus equal to 68.4% of the fixed remuneration, equal to a gross amount of euro 342,000, taking into account the target (60%) and maximum (78%) levels of incentive assigned.

 

Severance indemnity for end of office or termination of employment
No severance indemnities for end of office were resolved in favor of the Chairman.

 

Benefits
Forms of welfare insurance coverage, including for risk of death and permanent disability were recognized in favor of the Chairman Giuseppe Recchi, in office until May 8, 2014.

 

Non-executive Directors

Outgoing Directors were paid the pro-rated fixed remunerations resolved by the Shareholders’ Meeting on May 5, 2011, as well as additional remunerations payable for participation in the Board Committees, as resolved by the Board of Directors on June 1, 2011.

According to that which was verified by the Board of Directors on March 17, 2014 as proposed by the Compensation Committee, the conditions required to pay the variable component of the remuneration approved by the Shareholders’ Meeting of May 5, 2011 were not met.

 

Chief Executive Officer and General Manager - Paolo Scaroni

Fixed compensations
The Chief Executive Officer and General Manager Paolo Scaroni, in office until May 8, 2014, was paid the pro rated fixed remunerations approved by the Board of Directors Meeting of June 1, 2011, which absorb the remunerations approved by the Shareholders’ Meeting for the Directors.

 

Annual variable incentives
The 2014 annual incentive was paid, based on the actual results regarding the targets set for 2013 in line with the Strategic Plan and the annual budget, assessed on a constant basis and approved by the Board, as proposed by the Compensation Committee, at its meeting on March 17, 2014. The approved figures led to determining a performance score of 112 points in the measurement scale used, which provides for target and maximum performance levels of 100 and 130 points, respectively.

For the purposes of the variable remuneration, the actual performance determined for the Chief Executive Officer and General Manager Paolo Scaroni the payment of a bonus equal to 128% of the gross annual fixed remuneration, amounting to euro 1,430,000, given the target (110%) and maximum (155%) incentive levels assigned, for a gross amount of euro 1,831,000.

 

Deferred Monetary Incentive Plan
The Board of Directors, at its meeting of March 17, 2014, based on verification and a proposal made by the Compensation Committee, resolved the achievement of a 2013 EBITDA result (measured on a constant basis) below the target level, which determines for the 2014 assignment the application of a 70% multiplier to the defined target percentage (55% of the fixed remuneration).

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For the outgoing Chief Executive Officer and General Manager Paolo Scaroni, the Board ruled to assign a 2014 incentive (third and last assignment) equal to euro 550,500.

The deferred monetary incentive assigned in 2011 therefore reached maturity in 2014, based on Eni’s actual EBITDA results during the 2011-2013 period, and as proposed by the Compensation Committee, the Board of Directors at its Meeting of March 17, 2014 approved the multiplier to be applied to the amount assigned, for the purposes of calculating the amount to be paid. This was set at 110%. As a result, an incentive of euro 865,000 was paid to the Chief Executive Officer (equal to 110% of the base incentive of euro 786,500 assigned in 2011).

 

Long-Term Monetary Incentive Plan
In 2014, the Long-Term Monetary Incentive assigned in 2011 to the Chief Executive Officer and General Manager reached maturity. The Board of Directors, at its meeting of March 17, 2014, on the basis of the results related to the change in adjusted net profit + DD&A actually achieved in the period 2011-2013 and the annual placements with the peer group of reference, verified, as proposed by the Compensation Committee, the absence of the conditions for granting such an incentive.

 

Stock option Plans
Eni has not approved any stock option Plans since 2009. For more details on the existing Plans, please refer to the documents published in the “Governance” section of the Eni website and the information contained in the “Notes to the Financial Statements” in the 2014 Annual Report. The stock options assigned in 2008, the last assignment performed, were not exercised and expired on July 31, 2014 in relation to the end of the exercise period set in the Plan.

 

•		Additional indemnity to the severance pay with exemption from any notice obligation: total gross amount set at euro 5,202,000, as the sum of the fixed component amounting to euro 3,200,000 and the variable component linked to the average performance of the 2011-2013 period (average score of 120 points), calculated with reference to an amount of euro 2,002,000.
•		Term-end severance indemnity: gross amount equal to euro 748,376 set with reference to the fixed remuneration and 50% of the maximum variable remuneration provided for administrative employment to guarantee social security contributions and severance pay equal to that paid by Eni for management employment.

As for the non-competition agreement, any payment of the related gross consideration, set at euro 2,219,000, will be made only at the end of the term of the agreement, after verification of compliance with the relevant conditions.

As for the long-term incentives assigned during the term of office and still outstanding, in accordance with the provisions of the resolution of the Board of Directors on June 1, 2011, their disbursement will take place at the natural expiry, according to the general and performance conditions set for each Plan and on the basis of the related actual results that will from time to time be resolved by the Board of Directors on the basis of a verification and proposal of the Compensation Committee.

Based on a proposal by the Compensation Committee, the Board ordered the formalization of the consensual termination of the executive employment of Mr. Paolo Scaroni at the standard terms and conditions set forth in the employment resolutions for Eni executives.

 

Benefits
For the outgoing Chief Executive Officer and General Manager, the Policy Guidelines provide for insurance coverage for the risk of death or permanent disability, and in compliance with what is provided for in the national collective labor agreement and the supplementary company level agreements for Eni Senior Managers, enrolment in the complementary pension plan (FOPDIRE), as well as in the supplementary health plan (FISDE) are also provided, together with a company car for business and personal use.

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Directors appointed on May 8, 2014

Chairman of the Board of Directors - Emma Marcegaglia

Fixed compensations
The Chairman Emma Marcegaglia, appointed on May 8, 2014, was paid the pro-rated fixed remuneration approved for the office and in relation to the delegated powers, respectively by the Shareholders’ Meeting of May 8, 2014 and by the Board of Directors Meeting of May 28, 2014.

 

Benefits
The Chairman Emma Marcegaglia, appointed on May 8, 2014, was recognized forms of insurance coverage against the risk of death and permanent disability, in accordance with the resolutions of the Board of Directors Meeting of May 28, 2014.

 

Non-executive Directors

The new Directors were paid pro-rated fixed remuneration resolved strictly as a fixed amount by the Shareholders’ Meeting of May 8, 2014. Additional remuneration was also paid for participation in the Board Committees, as resolved by the Board of Directors Meeting of May 9, 2014, which confirmed the remuneration already set for the Control and Risk Committee and the other Board Committees, including the Nomination Committee, supplementing the provisions of the 2014 Remuneration Policy.

 

Chief Executive Officer and General Manager - Claudio Descalzi

Fixed compensations
The Chief Executive Officer and General Manager Claudio Descalzi, appointed on May 9, 2014, was paid the pro-rated fixed remunerations approved by the Board of Directors Meeting of May 28, 2014, which also absorb the remunerations approved by the Shareholders’ Meeting for all the Directors¹⁶.

 

Annual variable incentives
To Claudio Descalzi, solely in relation to the previous role as COO of the Exploration & Production Division, the Company paid an annual monetary incentive determined in accordance with the Remuneration Policy defined for Chief Operating Officers of Eni’s Divisions and other Managers with strategic responsibilities and with the actual performance for 2013 of the Exploration & Production Division.

 

Deferred Monetary Incentive Plan
Claudio Descalzi, solely in relation to the previous role as COO of the Exploration & Production Division, was assigned the 2014 deferred monetary incentive, determined in accordance with the Remuneration Policy defined for Chief Operating Officers of Eni’s Divisions and other Managers With Strategic Responsibilities, as well as on the basis of the 2013 EBITDA results resolved by the Board of Directors. Furthermore, in 2014 the Deferred Monetary Incentive assigned in 2011 to Claudio Descalzi, as COO of the Exploration & Production Division, reached maturity.

 

Long-Term Monetary Incentive Plan
For the Chief Executive Officer and General Manager Claudio Descalzi, the Board of Directors at its meeting of September 17, 2014, as proposed by the Compensation Committee, approved the assignment of the 2014 incentive of the 2014-2016 Long-Term Monetary Incentive Plan equal to euro 1,350,000 (100% of the fixed remuneration).

In 2014, the Long Term Monetary Incentive assigned in 2011 to Claudio Descalzi also reached maturity, as COO of the Exploration & Production Division, for which, according to the figure approved by the Board of Directors, the performance conditions for payment have not been met.

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Stock option Plans
The stock options assigned in 2008 to Claudio Descalzi, the last assignment performed, were not exercised and expired on July 31, 2014 in relation to the end of the exercise period envisaged by the Plan.

Consideration for the emption right of the Board of Directors for the activation of the non-competition agreement
In 2014, the first tranche was disbursed, amounting to euro 167,000 gross out of the euro 500,000 gross for the emption right at activation of the Agreement reserved for the Board of Directors.

 

Benefits
For the Chief Executive Officer and General Manager Claudio Descalzi appointed on May 9, 2014, in line with the resolution of the Board of Directors Meeting on May 28, 2014, insurance coverage was also recognized for the risk of death or permanent disability, and in compliance with what is provided for in the national collective labor agreement and the supplementary corporate agreements for Eni Senior Managers, enrolment in the complementary pension plan (FOPDIRE), as well as in the supplementary health plan (FISDE) are also provided, together with a company car for business and personal use.

 

Chief Operating Officers of Eni’s Divisions and other Managers with strategic responsibilities

Fixed compensations
For the current Managers with strategic responsibilities, within the context of the annual salary review process envisaged for all managers, in 2014 selective adjustments were made to fixed remuneration, in cases of promotion to more senior levels, or in relation to the necessity to adjust remuneration levels with respect to the market references identified.

 

Annual variable incentives
In March 2014, annual monetary incentives were paid to the Division Chief Operating Officers and the other Managers with strategic responsibilities, as determined in accordance with the defined Remuneration Policy, with reference to the actual performance of 2013. In particular, the incentive is linked to business performance and a number of individual targets in relation to the scope of responsibilities of the role, consistent with the provisions of the 2013 Eni Performance Plan, and on the basis of economic and operational performance achieved by the respective business sectors, also considering the achievement of specific targets of sustainability (in terms of health and safety, environmental protection, and stakeholder relations).

 

Deferred Monetary Incentive Plan
For Division Chief Operating Officers and other Managers with strategic responsibilities, the assignment of the 2014 deferred monetary incentive was made, determined in line with the defined Remuneration Policy, and based on the 2013 EBITDA results approved by the Board of Directors that determined an assignment multiplier of 70% to be applied to the target incentive to be assigned (differentiated by role level up to a maximum of 40% of the fixed remuneration).

In 2014, the Deferred Monetary Incentive assigned in 2011 also reached maturity.

 

Long-Term Monetary Incentive Plan
For Chief Operating Officers of Eni’s Divisions and the other Managers with strategic responsibilities, the assigned amounts were determined in accordance with the target incentive level, differentiated by role level up to a maximum of 75% of the fixed remuneration. In 2014, the Long Term Monetary Incentive assigned in 2011 also reached maturity, for which, according to the figure approved by the Board of Directors, the performance conditions for payment have not been met.

 

Stock option Plans
The stock options assigned in 2008, the last assignment performed, were not exercised and expired on July 31, 2014 in relation to the end of the exercise period set in the Plan.

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Severance indemnity for end of office or termination of employment
During 2014, the Managers with strategic responsibilities who terminated their employment were paid, in order to supplement the legal and contractual dues, the amounts defined in line with the Company policy on early retirement incentives.

 

Benefits
For Managers with strategic responsibilities, in line with that which is provided for in the national collective labor agreement and the complementary corporate agreements for Eni Managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE), as well as in the complementary health plan (FISDE), insurance coverage for the risk of death or disability, together with a company car for business and personal use.

 

COMPENSATION PAID IN 2014

The individual amounts of compensation paid in 2014 to each member of the Board of Directors, to Chief Operating Officers and to each member of the Board of Statutory Auditors, as well as the overall amounts paid to other Managers with strategic responsibilities, are reported in the table below, pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications. The remunerations received from subsidiaries and/or affiliates, except those waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year.

In particular:

•		based on the criteria of competence, the column "Fixed remuneration" reports the fixed remuneration and fixed salary from employment due for the year, gross of the social security contribution and tax expenses to be paid by the employee; it excludes attendance fees, as these are not provided for. Details of the compensation are provided in the notes, and any indemnities or payments with reference to the employment relationship are indicated separately;
•		based on the criteria of competence, the "Committee membership remuneration" column reports the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately;
•		the column "Variable non-equity remuneration" under the item "Bonuses and other incentives" shows the incentives paid during the year due to rights vested following the assessment and approval of the related performance results by the relevant corporate bodies, in accordance with that specified, in greater detail, in the Table "Monetary incentive Plans for Directors, General Managers, and other Managers with strategic responsibilities"; the column "Profit sharing" does not show any figures since there are no provisions for profit sharing;
•		based on the criteria of competence and taxability, the "Non-monetary benefits" column reports the value of the fringe benefits awarded;
•		based on the criteria of competence, the "Other remuneration" column reports any other remuneration deriving from other services provided;
•		the "Total" column details the sum of the amounts of all the previous items;
•		the "Fair value of equity remuneration" column reports the relevant fair value for the year related to the existing stock option Plans, estimated in accordance with international accounting standards, which assign the related cost in the vesting period; and
•		the "Severance indemnity for end of office or termination of employment" column reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of the financial year in question, or in relation to the end of the mandate and/or employment.

 

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Remuneration paid to Directors, Statutory Auditors, Chief Operating Officers and other Managers
with strategic responsibilities

(euro thousand)

Name

Notes

Office

Term of office

Office expiry (*)

Fixed remuneration

Committee membership remuneration

Bonuses and other incentives

Variable non-equity remuneration

Other remuneration

Total 2014

Fair value of equity remuneration

Severance indemnity for end of office or termination of employment

Profit sharing

Non-monetary benefits

Board of Directors
Giuseppe Recchi	(1)		Chairman		01.01-05.08		05.2014		272	(a)					342	(b)				4					618
Emma Marcegaglia	(2)		Chairman		05.08-12.31		05.2017		154	(a)															154
Paolo Scaroni	(3)		CEO and General Manager		01.01-05.08		05.2014		505	(a)					2,696	(b)				8					3,209				8,361	(c)
Claudio Descalzi	(4)		CEO and General Manager		05.09-12.31		05.2017		874	(a)										9		500	(b)		1,383
			COO E&P Division (**)		01.01-05.08

Remuneration in the company that prepares the Financial Statements		273	(c)					1,218	(d)				4					1,495
Remuneration from subsidiaries and associates															479	(e)		479

Total

1,147

1,218

13

979

3,357

Carlo Cesare Gatto	(5)		Director		01.01-05.08		05.2014		41	(a)		18	(b)												59
Paolo Marchioni	(6)		Director		01.01-05.08		05.2014		41	(a)		17	(b)												58
Roberto Petri	(7)		Director		01.01-05.08		05.2014		41	(a)		13	(b)												54
Alessandro Profumo	(8)		Director		01.01-05.08		05.2014		41	(a)		16	(b)												57
Mario Resca	(9)		Director		01.01-05.08		05.2014		41	(a)		16	(b)												57
Francesco Taranto	(10)		Director		01.01-05.08		05.2014		41	(a)		18	(b)												59
Andrea Gemma	(11)		Director		05.08-12.31		05.2017		52	(a)		49	(b)												101
Pietro Angelo Guindani	(12)		Director		05.08-12.31		05.2017		52	(a)		29	(b)												81
Karina A. Litvack	(13)		Director		05.08-12.31		05.2017		52	(a)		44	(b)												96
Alessandro Lorenzi	(14)		Director		01.01-12.31		05.2017		92	(a)		59	(b)												151
Diva Moriani	(15)		Director		05.08-12.31		05.2017		52	(a)		23	(b)												75
Fabrizio Pagani	(16)		Director		05.08-12.31		05.2017		52	(a)		29	(b)												81
Luigi Zingales	(17)		Director		05.08-12.31		05.2017		52	(a)		32	(b)												84

Board of Statutory Auditors

Ugo Marinelli	(18)		Chairman		01.01-05.08		05.2014		40	(a)															40
Francesco Bilotti	(19)		Statutory Auditor		01.01-05.08		05.2014		28	(a)															28
Paolo Fumagalli	(20)		Statutory Auditor		01.01-05.08		05.2014		28	(a)															28
Renato Righetti	(21)		Statutory Auditor		01.01-05.08		05.2014		28	(a)															28
Giorgio Silva	(22)		Statutory Auditor		01.01-05.08		05.2014		28	(a)															28
Matteo Caratozzolo	(23)		Chairman		05.08-12.31		05.2017		52	(a)															52
Paola Camagni	(24)		Statutory Auditor		05.08-12.31		05.2017		45	(a)															45
Alberto Falini	(25)		Statutory Auditor		05.08-12.31		05.2017		45	(a)															45
Marco Lacchini	(26)		Statutory Auditor		05.08-12.31		05.2017		45	(a)															45
Marco Seracini	(27)		Statutory Auditor		05.08-12.31		05.2017		45	(a)															45

Chief Operating Officers

Angelo Fanelli

(28)

R&M Division

01.01-06.30

300

(a)

396

(b)

7

703

Other Managers with strategic responsibilities (***)	(29)		Remuneration in the company that prepares the Financial Statements		5,945						5,777					161		120			12,003				4,990
			Remuneration from subsidiaries and associates		737						115					261		47			1,160
			Total		6,682	(a)					5,892	(b)				422	(c)	167	(d)		13,163				4,990	(e)

10,094

363

10,544

454

1,146

22,601

13,351

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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.
(**)		The position of COO E&P Division has been covered ad interim from May 9 to June 30, 2014 without any remuneration.
(***)		Managers who were permanent members of the Company’s Management Committee, during the course of the year together with the Chief Executive Officer and Division Chief Operating Officers, or who reported directly to the Chief Executive Officer (twenty managers).
(1)		Giuseppe Recchi - Chairman of the Board of Directors
		(a) The amount includes the pro-rata until May 8, 2014, respectively of the fixed remuneration of euro 265 thousand set by the Shareholders’ Meeting on May 5, 2011 (euro 94 thousand) and the fixed remuneration for the delegated powers of euro 500 thousand approved by the Board on June 1, 2011 (euro 178 thousand).
		(b) The amount corresponds to the annual variable incentive.
(2)		Emma Marcegaglia - Chairman of the Board of Directors
		(a) The amount includes the pro-rata from May 8, 2014, respectively of the fixed remuneration of euro 90 thousand set by the Shareholders’ Meeting on May 8, 2014 (euro 58 thousand) and from May 9, 2014 of the fixed remuneration for the delegated powers of euro 148 thousand approved by the Board on May 28, 2014 (euro 96 thousand).
(3)		Paolo Scaroni - Chief Executive Officer and General Manager
		(a) The amount includes the pro-rata until May 8, 2014, respectively of the fixed remuneration of euro 430 thousand for the position of Chief Executive Officer (euro 153 thousand), which incorporates the remuneration set by the Shareholders’ Meeting on May 5, 2011 for the position of Director, and the fixed remuneration of euro 1 million for the position of General Manager (euro 352 thousand); indemnities due for transfers, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and of the Company’s complementary agreements and other fees attributable to the employment for the period 2011-2014 are added to this amount for a total of euro 255 thousand.
		(b) The amount includes the variable annual incentive of euro 1,831 thousand, the deferred monetary incentive of euro 865 thousand awarded in 2011 and paid in 2014.
		(c) Amount approved by the Board of Directors Meeting on April 28, 2014, including the additional severance indemnity (euro 5,202 thousand), the economic treatment for the term of office end (euro 748 thousand), the non-competition agreement to be paid in May 2015 on the expiry of the term of the agreement (euro 2,219 thousand), the severance indemnity provided for the applicable Italian laws (euro 187 thousand), as well as the amount of euro 5 thousand for the novation transaction.

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(4)		Claudio Descalzi - Chief Executive Officer and General Manager
		(a) The amount includes the pro-rata from May 9, 2014, respectively of the fixed remuneration of euro 550 thousand for the position of Chief Executive Officer (euro 355 thousand), which incorporates the remuneration set by the Shareholders’ Meeting on May 8, 2014 for the position of Director, and the fixed remuneration of euro 800 thousand for the position of General Manager (euro 519 thousand); to this amount are added the indemnities owed for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and by the Company’s additional agreements, for a total amount of euro 9 thousand.
		(b) Amount relating to the consideration provided for the option right of the Board of Directors for the activation of the non-competition agreement. This amount, although quoted in full in the table, is paid in three annual installments starting in 2014.
		(c) The amount includes the pro-rata until May 8, 2014 of the fixed gross remuneration of the COO of the E&P Division; to this amount are added the indemnities due for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and by the Company’s additional agreements, for a total amount of euro 5 thousand.
		(d) The amount includes the payment of euro 879 thousand for the variable annual incentive and of euro 339 thousand for the deferred monetary incentive assigned in 2011 and paid in 2014.
		(e) The amount corresponds to the pro-rata until May 8, 2014 of the remuneration for the position of Chairman of Eni UK.
(5)		Carlo Cesare Gatto - Director
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes the pro-rata until May 8, 2014, respectively of euro 11.2 thousand for participating in the Control and Risk Committee and euro 6.4 thousand for the Compensation Committee.
(6)		Paolo Marchioni - Director
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes the pro-rata until May 8, 2014, respectively of euro 11 thousand for participating in the Control and Risk Committee and euro 6.3 thousand for the Oil-Gas Energy Committee.
(7)		Roberto Petri - Director
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes the pro-rata until May 8, 2014, respectively of euro 6.4 thousand for participating in the Compensation Committee and euro 6.4 thousand for the Oil-Gas Energy Committee.
(8)		Alessandro Profumo - Director
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes the pro-rata until May 8, 2014, respectively of euro 6.4 thousand for participating in the Compensation Committee and euro 9.6 thousand for the Oil-Gas Energy Committee.
(9)		Mario Resca – Director
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes the pro-rata until May 8, 2014, respectively of euro 9.6 thousand for participating in the Compensation Committee and euro 6.4 thousand for the Oil-Gas Energy Committee.
(10)		Francesco Taranto - Director
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes the pro-rata until May 8, 2014, respectively of euro 11.2 thousand for participating in the Control and Risk Committee and euro 6.4 thousand for the Oil-Gas Energy Committee.
(11)		Andrea Gemma - Director
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
		(b) The amount includes the pro-rata from May 9, 2014, respectively of euro 20.3 thousand for participating in the Control and Risk Committee, euro 11.6 thousand for the Sustainability and Scenario Committee and euro 17.4 thousand for the Appointment Committee.
(12)		Pietro Angelo Guindani - Director
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
		(b) The amount includes the pro-rata from May 9, 2014, respectively of euro 17.4 thousand for participating in the Compensation Committee and euro 11.6 thousand for the Sustainability and Scenario Committee.
(13)		Karina A. Litvack - Director
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
		(b) The amount includes the pro-rata from May 9, 2014, respectively of euro 20.3 thousand for participating in the Control and Risk Committee, euro 11.6 thousand for participating in the Compensation Committee and euro 11.6 thousand for the Sustainability and Scenario Committee.
(14)		Alessandro Lorenzi - Director
		(a) The amount includes the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting on May 5, 2011 (euro 41 thousand) and from May 9, 2014 for the fixed annual remuneration set by the Shareholders’ Meeting on May 8, 2014 (euro 51 thousand).
		(b) The amount includes euro 40.5 thousand for participating in the Audit and Risk Committee and the pro-rata until May 8, 2014 of euro 6.4 thousand for the Oil-Gas Energy Committee and from May 9, 2014 of euro 11.6 thousand for the Compensation Committee.
(15)		Diva Moriani - Director
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
		(b) The amount includes the pro-rata from May 9, 2014, respectively of euro 11.6 thousand for participating in the Compensation Committee and euro 11.6 thousand for the Appointment Committee.
(16)		Fabrizio Pagani - Director
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
		(b) The amount includes the pro-rata from May 9, 2014, respectively of euro 17.4 thousand for the Sustainability and Scenario Committee and euro 11.6 thousand for the Appointment Committee.
(17)		Luigi Zingales - Director
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
		(b) The amount includes the pro-rata from May 9, 2014, respectively of euro 20.3 thousand for participating in the Control and Risk Committee and euro 11.6 thousand for the Appointment Committee.
(18)		Ugo Marinelli - Chairman of the Board of Statutory Auditors
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(19)		Francesco Bilotti - Statutory Auditor
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(20)		Paolo Fumagalli - Statutory Auditor
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(21)		Renato Righetti - Statutory Auditor
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(22)		Giorgio Silva - Statutory Auditor
		(a) The amount corresponds to the pro-rata until May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 5, 2011.
(23)		Matteo Caratozzolo - Chairman of the Board of Statutory Auditors
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(24)		Paola Camagni - Permanent Auditor
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(25)		Alberto Falini - Permanent Auditor
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(26)		Marco Lacchini - Permanent Auditor
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(27)		Marco Seracini - Permanent Auditor
		(a) The amount corresponds to the pro-rata from May 8, 2014 of the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(28)		Angelo Fanelli - Chief Operating Officer R&M Division
		(a) The amount corresponds to the pro-rata until June 30, 2014 of the Gross Annual Salary (euro 300 thousand) to which are added the indemnities due for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and the Company’s additional agreements, as well as other indemnities related to the employment contract, for a total amount of euro 850.
		(b) The amount corresponds to the annual variable incentive.
(29)		Other Managers with strategic responsibilities
		(a) To the amount of euro 6,682 thousand as Gross Annual Salary, as the indemnities owed for the transfers performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and with the Company’s additional agreements, as well as other indemnities related to the employment contract for a total amount of euro 456 thousand.
		(b) The amount includes the payment of euro 2,464 thousand relating to the deferred monetary incentive assigned in 2011 and the pro-rata amounts of the Long-Term Incentive Plans (DMI and LTMI) paid upon consensual employment contract resolution, for the vesting period expired as defined in the respective Plan Regulations.
		(c) The amount includes the taxable value of insurance and welfare coverage, complementary pensions, the car for business and personal use, as well as the housing provided for senior managers in international mobility assignment.
		(d) Amounts due for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231, to the role of Manager responsible for the preparation of the Company’s Financial Statements and to the remuneration received for positions held in subsidiaries or associated companies of Eni.
		(e) The amount includes the severance indemnity and early retirement incentives paid in relation to the termination of the employment.

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OTHER INFORMATION

Accrued compensation
Total compensation accrued in the year 2014 pertaining to all the Board members amounted to euro 10.1 million; it amounted to euro 0.419 million in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company.

For the year ended December 31, 2014, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, Chief Operating Officers and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2014 period, filled said roles, even if only for a fraction of the year) amounted to euro 43 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2014. The breakdown is as follow:

	2014
	(euro million)

Fees and salaries		25
Post-employment benefits		2
Other long-term benefits		10
Indemnity upon termination of the office		6
		43

The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay.

As of December 31, 2014, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the 2014 period, filled said roles, even if only for a fraction of the year), was euro 1,648 thousand.

Name				(euro thousand)
Claudio Descalzi		Chief Executive Officer		343
Angelo Fanelli		Chief Operating Officer of the R&M Division		248
Senior managers (a)				1,057
				1,648

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Stock options

The Company discontinued any stock-based compensation scheme in 2009; as such, options outstanding as of the end of the year pertained to stock options schemes adopted in previous reporting periods. At December 31, 2014, no options were outstanding for the purchase of an equal amount of Eni ordinary shares without nominal value.

The following table shows the evolution of stock option activity in 2013 and 2014.

	2013		2014

	Number of shares		Weighted average exercise price (euro)		Market price (euro)		Number of shares		Weighted average exercise price (euro)		Market price (euro)

Options as of January 1		8,259,520			23.545		18.457		2,980,725			22.540		17.533
Options exercised in the period
Options cancelled in the period		(5,278,795	)		24.112		16.278		(2,980,725	)		22.540		19.766
Options outstanding as of December 31		2,980,725			22.540		17.533
of which exercisable as of December 31		2,969,450			22.540		17.533

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Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the table below indicates, by name, the stock options assigned to the Chief Executive Officer and General Manager, to the Chief Operating Officers of the Divisions and, at an aggregate level, to other Managers with strategic responsibilities (including all those individuals who, during the course of the 2014 period, filled said roles, even if only for a fraction of the year).

In particular, the purchase rights (options) for Eni shares or for subsidiaries, which can be exercised after three years from the date granted are indicated, in relation to the existing stock incentive plans, the last of which was granted in 2008. The data are shown in accordance with the criteria of aggregate representation, as there are no options outstanding at December 31, 2014.

 

Stock options granted to Directors, Chief Operating Officers and other Managers with strategic responsibilities

Name		Paolo Scaroni		Claudio Descalzi		Angelo Fanelli		Other Managers with strategic responsibilities (1)
Office		CEO and General Manager		Chief Operating Officer of E&P Division		Chief Operating Officer of R&M Division
Plan		Eni Stock Option Plans		Eni Stock Option Plans		Eni Stock Option Plans		Eni Stock Option Plans

Options held at the start of the year
Number of options			348,975		47,025		27,500		377,300
Average exercise price	(euro)		22.540		22.540		22.540		22.540
Average maturity	(months)		7		7		7		7
Options granted during the year
Number of options
Exercise price	(euro)
Period of possible exercise	(from-to)
Fair value on grant date	(euro)
Grant date
Market price of underlying shares upon granting of options	(euro)
Options exercised during the year
Number of options
Exercise price	(euro)
Market price of underlying shares on exercise date	(euro)
Options expired during the year
Number of options			348,975		47,025		27,500		377,300
Options held at the end of the year
Number of options
Options relevant to the year
Fair value	(euro thousand)

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Board practices

Corporate Governance
The Corporate Governance structure of Eni SpA follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. Eni complies with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) of December 2011 (hereinafter "Corporate Governance Code" or "Code"). On July 14, 2014, the Italian Corporate Governance Committee approved a few amendments to the Corporate Governance Code. At its Meeting held on December 11, 2014, the Board adopted the new recommendations of the Code, acknowledging that Eni’s Corporate Governance model was already broadly compliant with the new recommendations. Some of the solutions previously adopted by Eni have been updated to include and specify the role assigned by the Board of Directors to the Chairman of the Board on May 9, 2014, regarding the Internal Audit function.

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

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

In the same resolution, the Board of Directors resolved to attribute to the Chairman a role as guarantor and not operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code, the Senior Executive Vice President of the Internal Audit Department reports to the Board, and on its behalf, to the Chairman. In addition, the Chairman carries out her statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer.

Finally, the Board of Directors entrusted the Board Secretary with the role of Corporate Governance Counsel, who reports hierarchically to the Chairman. He lends assistance and independent legal advice (regarding the management) to the Board and the Directors and presents annually to the Board of Directors a report on the functioning of Eni’s Corporate Governance system.

On May 9, 2014, the Board reserved to itself the following strategic, operational and organizational powers:

•		defines the system and rules of Corporate Governance for the Company and the Group;
•		establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets;
•		expresses the general criteria for determining the maximum number of offices that a Company Director may hold in other companies;
•		delegates and revokes the powers of the CEO and the Chairman, establishing the limits and procedures for exercising those powers and determining the compensation associated with these duties;
•		establishes the basic structure of the organizational, administrative and accounting arrangements of the Company (including the internal control and risk management system), of its strategically important subsidiaries and of the Group as a whole. It evaluates the adequacy of these arrangements;
•		establishes the guidelines for the internal control and risk management system, so that the main risks facing the Company and its subsidiaries are correctly identified and adequately measured, managed and monitored, determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives. It sets the financial risk limits of the Company. It also examines the main business risks, which are identified taking into account the characteristics of the activities carried out by the Company and its subsidiaries and which are reported by the Chief Executive Officer at least quarterly. Moreover, it evaluates, every six months, the adequacy of the internal control and risk management system with respect to the characteristics of the Company and its risk profile, as well as the system’s effectiveness;
•		approves at least annually the Audit Plan drawn up by the Senior Executive Vice President of the Internal Audit Department. It also evaluates the findings contained in the recommendation letter, if any, of the Audit Firm and in its statement on the key issues that arose during the statutory audit;
•		defines the strategic guidelines and objectives of the Company and the Group, including sustainability policies. It examines and approves the budgets and strategic, industrial and financial plans of the Group, periodically monitoring their implementation, as well as agreements of a strategic nature for the Company;
•		examines and approves the annual financial report including the individual and Consolidated Financial Statements and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report;
•		receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers;
•		receives a report from the Board’s internal committees on at least a semi-annual basis;
•		assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts;
•		evaluates and approves transactions of the Company and its subsidiaries with related parties17, as well as transactions in which the CEO has an interest;
•		evaluates and approves any transaction executed by the Company and its subsidiaries that has a significant strategic, economic, financial or asset impact on the Company;
•		appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the Senior Executive Vice President of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of a manager responsible for shareholder relations;
•		examines and approves the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting. It also defines the criteria for remunerating the senior executives of the Company and of the Group and takes steps to implement compensation plans based on shares or other financial instruments approved by the Shareholders’ Meeting;

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•		resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries;
•		formulates the proposals to present to the Shareholders’ Meeting; and
•		examines and resolves on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity.

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

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

 

Directors’ independence
On the basis of statements made by the Directors and other information available to the Company, during its meeting of May 9, 2014 and, after an investigation by the Nomination Committee, at its meeting of February 17, 2015, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code. Chairman Marcegaglia, in compliance with the Corporate Governance Code, could not be deemed independent as she is a significant representative of the Company. During its meeting of February 26, 2015, the Board of Statutory Auditors ascertained that the Board of Directors correctly applied the assessment criteria and procedures for evaluating the independence of its members.

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

 

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

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

All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. In the exercise of their functions, the Committees have the right to access any information and Company functions necessary to perform their duties. They are also provided with adequate financial resources, in accordance with the terms established by the Board of Directors, and can avail themselves of external advisers.

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

The CEO and the Chairman can attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they can attend Control and Risk Committee meetings, except when the meetings are addressing issues regarding them. Finally, they can attend Compensation Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their remuneration.

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

Minutes of all committee meetings are drafted by their respective secretaries. The current members of the Control and Risk Committee, Compensation Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on May 9, 2014.

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Compensation Committee
Members: Pietro A. Guindani (Chairman), Karina Litvack, Alessandro Lorenzi and Diva Moriani.

The Compensation Committee is made up of non-executive, independent Directors. All the members possess adequate professional requirements and expertise for carrying out the duties assigned to the Committee. In particular, at his appointment, the Director Guindani was identified by the Board as the member with "adequate knowledge and experience in finance or remuneration policies" as recommended by the Corporate Governance Code.

Established by the Board of Directors for the first time in 1996, in accordance with the By-laws, the Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee: a) submits to the Board of Directors for its approval the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting called to approve the financial statements, as provided for by applicable law; b) presents proposals for the remuneration of the Chairman of the Board and the Chief Executive Officer, covering the various forms of compensation and benefits awarded; c) presents proposals for the remuneration of members of the Board’s internal committees; d) examines the CEO’s indications and presents proposals for: (i) general criteria for the compensation of Managers with strategic responsibilities; (ii) annual and long-term incentive plans, including equity-based plans; and (iii) establishing performance targets and assessing results for performance plans in connection with the determination of the variable portion of the compensation for Directors with delegated powers and with the implementation of incentive plans; e) monitors the execution of Board resolutions regarding remuneration matters; f) periodically evaluates the adequacy, overall consistency and actual implementation of the adopted policy, as described in letter a) above, formulating proposals on the topic for the Board of Directors; g) performs the tasks required under the Company’s procedures for handling related party transactions; h) reports to the Board, at least once every six months and no later than the deadline for the approval of the annual financial statements and the semi-annual financial report, on its activities at the Board Meeting indicated by the Chairman of the Board of Directors; and i) reports through its Chairman or another Committee member designated by the Chairman on its operational procedures to the Shareholders’ Meeting called to approve the financial statements.

During 2014, the Compensation Committee met twelve times, with an attendance rate: (i) of 94% of its members in the four meetings held before the expiration date of the previous Board of Directors (May 8, 2014); and (ii) of 97% of its members in the eight meetings held after the appointment of the current Committee.

In 2014, the main topics discussed during the first part of the year were: (i) the periodical evaluation of the Remuneration Policy conducted in 2013, including defining the proposal guidelines for the 2014 Remuneration Policy; (ii) the definition of the proposal for reviewing the Long-Term Monetary Incentive Plan; (iii) the evaluation of Eni’s 2013 results and determination of the 2014 performance targets for the purposes of the variable Incentive Plans; (iv) the establishment of the proposals regarding the Deferred Monetary Incentive Plan for the CEO and General Manager and for other executives; (v) the examination of the 2014 Remuneration Report; and (vi) the recognition of compensation for retiring Directors with delegated powers at the end of their terms.

Following the renewal of the Board of Directors, on May 28, 2014 the Committee submitted to the Board of Directors a proposal for amending its operating rules. In the same meeting the Committee also submitted to the Board proposals on compensation for Directors with delegated powers for the 2014-2017 term, taking into account the principles and criteria set out in the 2014 Remuneration Report, the resolution approved by the Shareholders’ Meeting for reducing the compensation of Directors with delegated powers in compliance with law, as well as domestic and international market benchmarks for similar positions or roles, while complying with provisions on related parties transactions.

During the second part of the year, the Committee examined the results of the vote of the Shareholder’s Meeting on the 2014 Remuneration Policy, comparing Eni with major Italian listed companies and its peer companies, as well as looking at the Company’s practice of handling relations with shareholders and investors, with emphasis on communication pertaining to compensation issues. The Committee also formulated the proposal concerning the fulfillment ("2014 attribution") of the Long-Term Monetary Incentive Plan for the CEO and General Manager and for critical management personnel. Furthermore, the Committee examined the proposals for the adoption of the new Corporate Governance Code recommendations (July 14, 2014) on compensation and proposed to the Board of Directors that they be fully adopted. The Board resolved to adopt them in December 2014. It also completed an extensive analysis of the system of objectives relating to Eni’s incentive Plans, sharing in particular the criteria for identifying annual and long-term performance indicators (for the Long Term Monetary Incentive Plan) for the purposes of the proposed 2015 Remuneration Policy. Finally, the Committee examined the regulatory framework, Company practices and market practices concerning "clawback" for the purposes of defining the proposed guidelines for the 2015 Remuneration Policy.

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

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

The Control and Risk Committee is entrusted with supporting, on the basis of an appropriate control process, the Board of Directors in evaluating and making decisions concerning the internal control and risk management system and in approving the annual and semi-annual financial reports. It is entirely made up of non-executive and independent Directors¹⁸ who possess the necessary expertise consistent with the duties they are required to perform¹⁹.

In particular, at their appointment, the Directors Lorenzi, Litvack and Zingales were identified by the Board as members with "adequate experience in the area of accounting and finance or risk management", as recommended by the Corporate Governance Code.

The Committee advises the Board of Directors and specifically issues its prior opinion: a) and drafts recommendations concerning the guidelines for the internal control and risk management system so that the main risks faced by the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored and also supports the Board in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives; b) on the evaluation, performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, at least once every six months it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the internal control and risk management system at the meeting of the Board of Directors indicated by the Chairman of the Board of Directors; c) on the approval, at least once a year, of the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; d) on the description, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, providing its evaluation of the overall adequacy of the system itself; e) on the evaluation of the findings reported by the Audit Firm in any recommendations letter it may issue and in the latter’s report on the main issues arising during the audit; f) on specific aspects concerning the identification of the main risks faced by the Company, as well as on the design, implementation and management of the internal control and risk management system; and g) on the adoption and amendment of the rules on the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or Statutory Auditor holds a personal interest or an interest on behalf of a third party, while performing additional duties assigned it by the Board of Directors, including examining and issuing an evaluation on specific types of transactions, except for those relating to compensation.

In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the Consolidated Financial Statements, prior to their approval by the Board of Directors; b) examines and evaluates the appropriateness of the powers and resources assigned to the officer in charge of preparing financial reports and, as well as for the purposes of overseeing the proper application of accounting standards and their consistency, performs the duties assigned it under the MSG on "Eni’s internal control system over financial reporting", including examining the report on the internal control system for financial reporting prepared by the officer in charge of preparing financial reports at the time of the approval of the consolidated annual and semi-annual financial statements; and c) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and oversees its activities with respect to the duties of the Board of Directors in this area, and on its behalf, of the Chairman, ensuring that they are performed with the necessary independence and required level of objectivity, competence and professional diligence, in accordance with the Code of Ethics of Eni SpA and international standards.

A favorable opinion of the Committee is required for the approval to the Board on proposals by the Chairman in agreement with the CEO concerning the appointment, the removal and, consistent with the Company’s policies, the structure of the fixed and variable compensation of the Senior Executive Vice President of the Internal Audit Department, as well as on the adequacy of the resources provided to the latter to perform his duties.

The Committee also: a) evaluates, on the occasion of his appointment, whether the Senior Executive Vice President of the Internal Audit Department meets the integrity, professionalism, competence and experience requirements and, on an annual basis, assesses whether they continue to be met; b) examines the results of the audit activities performed by the Internal Audit Department; c) examines the periodic reports prepared by the Senior Executive Vice President of the Internal Audit Department as to whether it contains adequate information on the activities carried out, on the manner in which risk management is conducted and on compliance with risk containment plans, as well as assesses the appropriateness of the internal control and risk management system. It also examines the reports prepared promptly by the Senior Executive Vice President of the Internal Audit Department on events of

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particular importance; and d) examines the information received from the Senior Executive Vice President of the Internal Audit Department and promptly reports its assessment to the Board of Directors in the case of: (i) significant deficiencies in the system for preventing irregularities and fraudulent acts, and irregularities or fraudulent acts committed by management personnel or by employees that perform important roles in the design or operation of the internal control and risk management system; and (ii) circumstances that may affect the maintenance of the independence of the Internal Audit Department and of auditing activities.

The Committee may also ask the Internal Audit Department to perform audits of specific operational areas, providing simultaneous notice to the Chairman of the Board of Statutory Auditors. The Committee also examines and assesses: (a) communications and information received from the Board of Statutory Auditors and its members regarding the internal control and risk management system, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports; (b) half yearly reports issued by Eni’s Watch Structure, including in its capacity as Guarantor of the Code of Ethics, as well as the timely updates provided by the Structure, after the updates have been given to the Chairman of the Board and to the CEO, about any particular material or significant situation detected in the performance of its duty; (c) information on the internal control and risk management system, including that provided in the course of periodic meetings with the competent Company structures; and (d) enquiries and reviews concerning the internal control and risk management system carried out by third parties.

Furthermore, the Committee oversees the activities of the Legal Affairs Department in case of judicial inquiries, carried out in Italy and/or abroad, in relation to which the CEO and/or the Chairman of the Company and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, have received a notice of investigation for crimes against the Public Administration and/or corporate crimes and/or environmental crimes, related to their mandate and their scope of responsibility.

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

 

Nomination Committee
Members: Andrea Gemma (Chairman), Diva Moriani, Fabrizio Pagani and Luigi Zingales.

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

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

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

 

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

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

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

 

Board of Statutory Auditors
The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of May 8, 2014 for a term of three financial years²⁰. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2016.

Name		Position		Year first appointed to Board of Statutory Auditors
Matteo Caratozzolo		Chairman		2014
Paola Camagni		Auditor		2014
Alberto Falini		Auditor		2014
Marco Lacchini		Auditor		2014
Marco Seracini		Auditor		2014
Stefania Bettoni		Alternate		2014
Mauro Lonardo		Alternate		2014

Paola Camagni, Alberto Falini, Marco Seracini and Stefania Bettoni (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; Matteo Caratozzolo (Chairman), Marco Lacchini and Mauro Lonardo (Alternate) were candidates listed in the slate presented by non-controlling shareholders (institutional investors).

The Auditors are appointed by means of a slate voting system: the lists are presented by shareholders representing at least 0.5% of the share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders.

In accordance with the provisions designed to ensure gender balance, which were applied for the first time in the elections of the Board of Directors and the Board of Statutory Auditors at the Shareholders’ Meeting held on May 8, 2014, one Statutory Auditor and one Alternate Statutory Auditor were drawn from the less represented gender. For the next two elections, one third of the statutory auditors will be drawn from the less represented gender.

The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. Regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of financial statements and internal control processes.

Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters within the scope of the Board’s

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Authority, the adequacy of the internal control system and the administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.

In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, in its role as the "internal control and financial auditing committee" the Board of Statutory Auditors oversees the following: (a) the financial reporting process; (b) the efficacy of internal control, internal audit (where applicable) and risk management systems; (c) the auditing of the annual financial statements and Consolidated Financial Statements; and (d) the independence of the external auditor or the Audit Firm, in particular with regard to the provision of non-audit services to the entity subject to financial auditing.

The responsibilities assigned under the Legislative Decree No. 39/2010 to the "internal control and financial auditing committee" are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the "U.S. Sarbanes-Oxley Act" (discussed in greater detail below).

As already set forth in the Consolidated Law on Financial Intermediation and currently regulated by Article 13 of Legislative Decree No. 39/2010, the Board of Statutory Auditors submits a reasoned opinion to the Shareholders’ Meeting on the selection of the external auditors and the determination of the associated fees.

In particular, pursuant to Article 19, paragraph 1, letters c) and d) of Legislative Decree No. 39/2010, the Board of Statutory Auditors supervises the auditing activities and the independence of the Audit Firm, verifying compliance with all applicable regulations, as well as the nature and scale of any services other than financial auditing services provided to the Eni Group, either directly or through companies belonging to its network.

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

On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, the Board of Statutory Auditors approved the internal rules concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC rules are as follows:

•		evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor;
•		overseeing the work of the external Auditor engaged to audit the accounts or performing other audit, review or certification services;
•		making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting;
•		approving the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;
•		approving the procedures for the pre-approval of specifically identified admissible non-audit services and examining the disclosures on the execution of the authorized services;
•		evaluating requests to use the external auditor firm engaged to perform audit services for admissible non-audit services and providing its opinion to the Board of Directors;
•		examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;
•		examining reports from the CEO and the CFO concerning any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and
•		examining reports from the CEO and the CFO concerning any fraud that involves management or other employees who have a significant role in the Company’s internal controls.

The Board of Statutory Auditors, in the performance of its duties, is supported by Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department.

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Eni Watch Structure and Model 231
In accordance with the Italian regulations concerning the "administrative liability of legal entities deriving from criminal offences", contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, "Legislative Decree No. 231/2001"), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high-ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni SpA’s Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the Watch Structure. Moreover, as a result of changes in the Italian legislation governing the matter and of the Company’s organizational structures, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Most recently, the Board of Directors, in its meetings of April 10 and May 28, 2014, updated the Model 231 to incorporate all the types of crimes relevant to the Company pursuant to Legislative Decree No. 231 of 2001.

The synergies between the Code of Ethics – an integral part and essential general principle of Model 231 – and Model 231 are highlighted by the assignment, to the Eni Watch Structure, of the function of Guarantor of the Code of Ethics. The composition of the Eni Watch Structure, initially composed of only three members, was modified in 2007 with the inclusion of two external members, one of whom was appointed as Chairman of the Eni Watch Structure selected among academics and professionals of proven authority and expertise in economic and business management issues. At present, the Watch Structure of Eni SpA is composed of three external members and three internal members. The internal members are the Chief Legal & Regulatory Officer; the Senior Vice President Relations with Entrepreneurial Associations Coordination and the Senior Executive Vice President Internal Audit of the Company. On May 28, 2014, the Board of Directors, with the favorable opinion of the Board of Statutory Auditors, appointed the current members of the Watch Structure.

 

Audit Firm
The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit Firm appointed by the Shareholders’ Meeting on the basis of a reasoned recommendation of the Board of Statutory Auditors.

In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm issue a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit Firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting.

For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit Firm. Moreover, Eni’s Audit Firm, for the purpose of issuing an opinion on the Consolidated Financial Statements, assumes responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which, taken together, account for an immaterial share of consolidated assets and revenues.

Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of April 29, 2010 appointed Reconta Ernst & Young SpA for the financial years 2010-2018.

 

Court of Auditors (Corte dei conti)
The financial management of Eni is subject to the control of the Court of Auditors in order to preserve the integrity of the public finances. Until December 22, 2014 this task was carried out by the Magistrate of the Court of Auditors, Raffaele Squitieri, on the basis of the resolution approved on October 28, 2009 by the Presidential Council of the Court of Auditors. On the basis of the resolution approved on December 22, 2014, the Presidential Council of the Court of Auditors appointed Adolfo Teobaldo De Girolamo. The Magistrate of the Court attends the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Control and Risk Committee.

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Employees

As of December 31, 2014, Eni had a total of 84,405 employees, with an increase of 518 employees, or up by 0.6% from December 31, 2013, which reflects an increase of 1,673 employees working outside Italy and a decrease of 1,155 employees in Italy.

		2012 (1)		2013		2014

(number)

Exploration & Production		11,304		12,352		12,777
Gas & Power (2)		4,836		4,616		4,228
Refining & Marketing		8,608		8,438		6,774
Chemicals		5,668		5,708		5,443
Engineering & Construction		43,387		47,209		49,559
Other activities		871		818		726
Corporate and financial companies		4,731		4,746		4,898
		79,405		83,887		84,405

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The table below sets forth Eni’s employees as of December 31, 2012, 2013 and 2014 in Italy and outside Italy:

		2012 (1)		2013		2014

(number)

Exploration & Production	Italy		3,933		4,133		4,534
	Outside Italy		7,371		8,219		8,243
			11,304		12,352		12,777
Gas & Power (2)	Italy		2,126		2,178		1,980
	Outside Italy		2,710		2,438		2,248
			4,836		4,616		4,228
Refining & Marketing	Italy		6,098		5,909		4,897
	Outside Italy		2,510		2,529		1,877
			8,608		8,438		6,774
Chemicals	Italy		4,606		4,615		4,476
	Outside Italy		1,062		1,093		967
			5,668		5,708		5,443
Engineering & Construction	Italy		5,186		5,136		5,016
	Outside Italy		38,201		42,073		44,543
			43,387		47,209		49,559
Other activities	Italy		871		818		726
	Outside Italy
			871		818		726
Corporate and financial companies	Italy		4,577		4,589		4,594
	Outside Italy		154		157		304
			4,731		4,746		4,898
Total	Italy		27,397		27,378		26,223
	Outside Italy		52,008		56,509		58,182
			79,405		83,887		84,405
of which senior managers			1,504		1,505		1,503

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Share ownership

As of February 28, 2015, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 258,462 less than 0.1% of Eni’s share capital outstanding as of the same date. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The breakdown of share ownership for each of those persons is provided below.

Name	Position	Number of shares owned

Board of Directors
Emma Marcegaglia		Chairman		53,894
Claudio Descalzi		CEO		39,455
Luigi Zingales		Director		2,000
Board of Statutory Auditors				5,000
Senior Managers				158,113