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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, 2012
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                                                                                                                                                                 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).*

* This requirement does not apply to the registrants in respect of this filing.   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	62
I	I	Refining & Marketing	I	73
I	I	Engineering & Construction	I	79
I	I	Chemicals	I	82
I	I	Corporate and Other activities	I	84
I	I	Research and development	I	85
I	I	Insurance	I	87
I	I	Environmental matters	I	87
I	I	Regulation of Eni’s businesses	I	95
I	I	Property, plant and equipment	I	101
I	I	Organizational structure	I	101
Item 4A.	I	UNRESOLVED STAFF COMMENTS	I	101
Item 5.	I	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	I	102
I	I	Executive summary	I	102
I	I	Critical accounting estimates	I	104
I	I	2010-2012 Group results of operations	I	107
I	I	Liquidity and capital resources	I	121
I	I	Recent developments	I	128
I	I	Management's expectations of operations	I	128
Item 6.	I	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	I	137
I	I	Directors and Senior Management	I	137
I	I	Compensation	I	144
I	I	Board practices	I	154
I	I	Employees	I	161
I	I	Share ownership	I	164
Item 7.	I	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	I	165
I	I	Major Shareholders	I	165
I	I	Related party transactions	I	165
Item 8.	I	FINANCIAL INFORMATION	I	166
I	I	Consolidated Statements and other financial information	I	166
I	I	Significant changes	I	166
Item 9.	I	THE OFFER AND THE LISTING	I	167
I	I	Offer and listing details	I	167
I	I	Markets	I	168
Item 10.	I	ADDITIONAL INFORMATION	I	170
I	I	Memorandum and Articles of Association	I	170
I	I	Material contracts	I	176
I	I	Exchange controls	I	176
I	I	Taxation	I	177
I	I	Documents on display	I	181
Item 11.	I	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	I	182
Item 12.	I	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	I	183
12A.	I	Debt securities	I	183
12B.	I	Warrants and rights	I	183
12C.	I	Other securities	I	183
12D.	I	American Depositary Shares	I	183
II	I	I	I	I
PART II	I	I	I	I
Item 13.	I	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	I	185
Item 14.	I	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	I	185
Item 15.	I	CONTROLS AND PROCEDURES	I	185
Item 16.	I	I	I	II
16A.	I	Board of Statutory Auditors financial expert	I	186
16B.	I	Code of Ethics	I	186
16C.	I	Principal accountant fees and services	I	186
16D.	I	Exemptions from the Listing Standards for Audit Committees	I	187
16E.	I	Purchases of equity securities by the issuer and affiliated purchasers	I	187
16F.	I	Change in Registrant’s Certifying Accountant	I	188
16G.	I	Significant Differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual	I	188
16H.	I	Mine safety disclosure	I	190
PART IIII	I	I	I	II
Item 17.	I	FINANCIAL STATEMENTS	I	191
Item 18.	I	FINANCIAL STATEMENTS	I	191
Item 19.	I	EXHIBITS	I	191

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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" and "U.S. $" are to the currency of the United States, and references to "euro" and "€" are to the currency of the European Monetary Union.

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

 

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 minority 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
AEEG (Authority for Electricity and Gas)		The Regulatory Authority for Electricity and Gas is the Italian independent body which regulates, controls and monitors the electricity and gas 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.
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. Balanced conversion capacity of a refinery is a measure of a refinery capacity to process raw materials averaging both capacity at topping and capacity at conversion plants that normally have smaller capacity.
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.

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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.
EPIC		Engineering, Procurement, Installation and Construction.
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 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

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		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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(*)

In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. From July 1, 2012, as part of an ongoing review of the yields at the Company’s gas fields currently in production, Eni has updated the conversion rate of gas to 5,492 cubic feet of gas equals 1 barrel of oil (it was 5,550 cubic feet of gas per barrel in previous reporting periods). The effect of this update on production expressed in BOE was 9 kBOE/d for the full year 2012 and the change in the initial reserves balance as of January 1, 2012 amounted to 40 mmBOE. Prior-year converted amounts were left unchanged. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depreciation and depletion charges. Other oil companies may use different conversion rates.

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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 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, 2008, 2009, 2010, 2011 and 2012. In accordance with the guidelines of IFRS 5, results of Snam SpA and its subsidiaries (Snam) which manage the Italian regulated businesses of gas infrastructures have been reported as discontinued operations due to Eni’s plan to divest the business. Eni lost control over the entity in October 2012 as part of a transaction to divest 30% interest less one share in Snam to an Italian entity, Cassa Depositi e Prestiti which is a related party of Eni as both entities are under the common control of the Italian Ministry for Economy and Finance. The divestment took place in accordance to Law No. 27 of March 24, 2012 which mandated the ownership unbundling of Snam from Eni. Prior year data have been reclassified in accordance with guidelines of IFRS 5. The residual interest of Eni in Snam equal to 20.2% of the share capital of the investee as of the balance sheet date was accounted as a financial asset because Eni is forbidden from exercising the underlying voting rights by applicable laws and therefore cannot influence the financial and operating policy decisions of the investee. Furthermore, under applicable rules, Eni is mandated to divest any residual interest in the entity. See Item 5 and Item 7 – Related party transactions for more information on the transaction.

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,

	2008		2009		2010		2011		2012

CONSOLIDATED PROFIT STATEMENT DATA
Net sales from continuing operations		106,978			81,932			96,617			107,690			127,220
Operating profit by segment from continuing operations
Exploration & Production		16,239			9,120			13,866			15,887			18,451
Gas & Power (1)		2,330			1,914			896			(326	)		(3,221	)
Refining & Marketing		(988	)		(102	)		149			(273	)		(1,303	)
Chemicals		(845	)		(675	)		(86	)		(424	)		(683	)
Engineering & Construction		1,045			881			1,302			1,422			1,433
Other activities		(466	)		(436	)		(1,384	)		(427	)		(302	)
Corporate and financial companies		(623	)		(420	)		(361	)		(319	)		(345	)
Impact of unrealized intragroup profit elimination and other consolidation adjustments (2) (3)		1,690			1,513			1,100			1,263			996
Operating profit from continuing operations		18,382			11,795			15,482			16,803			15,026
Net profit attributable to Eni from continuing operations		8,996			4,488			6,252			6,902			4,198
Net profit (loss) attributable to Eni from discontinued operations (4)		(171	)		(121	)		66			(42	)		3,590
Net profit attributable to Eni		8,825			4,367			6,318			6,860			7,788
Data per ordinary share (euro) (5)
Operating profit:
- basic		5.05			3.26			4.27			4.64			4.15
- diluted		5.05			3.26			4.27			4.64			4.15
Net profit attributable to Eni basic and diluted from continuing operations		2.47			1.24			1.72			1.90			1.16
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		(0.05	)		(0.03	)		0.02			(0.01	)		0.99
Net profit attributable to Eni basic and diluted		2.43			1.21			1.74			1.89			2.15
Data per ADR ($) (5) (6)
Operating profit:
- basic		14.86			9.08			11.33			12.92			10.67
- diluted		14.86			9.08			11.33			12.92			10.67
Net profit attributable to Eni basic and diluted from continuing operations		7.27			3.45			4.59			5.32			2.98
Net profit (loss) attributable to Eni basic and diluted from discontinued operations		(0.15	)		(0.08	)		0.05			(0.03	)		2.54
Net profit attributable to Eni basic and diluted		7.14			3.36			4.62			5.26			5.53

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(1)		Following the divestment of a significant stake in Snam and its deconsolidation closed in 2012, results of the G&P business segment include Marketing and International transport activities. To allow a homogeneous comparison, the presentation of prior year data has been modified accordingly.
(2)		This item mainly pertained to intra-group sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of the end of the period.
(3)		In the circumstances of discontinued operations, the International Financial Reporting Standards require that the profits earned by continuing and discontinued operations are those deriving from transactions external to the Group. Therefore, profits earned by the discontinued operations, in this case Snam operations, on sales to the continuing operations are eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa. This representation does not indicate the profits earned by continuing and Snam operations, as if they were stand alone entities, for past periods or likely to be earned in future periods. Results attributable to individual segments are not affected by this representation.
(4)		In 2012, net profit attributable to Eni from discontinued operations includes post-tax gains on the disposal of a 30% stake and the revaluation of the residual interest in Snam.
(5)		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 2012 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 10, 2013.
(6)		Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/USD average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2008 through 2011 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 2012 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 1.08 per ADR) at the Noon Buying Rate recorded on the payment date on October 11, 2012, while the balance of euro 1.08 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2012. The balance dividend for 2012 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 23, 2013 to holders of Eni shares, being the ex-dividend date May 20, while ADRs holders will be paid late on June 7, 2013.

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	As of December 31,

	2008		2009		2010		2011		2012

CONSOLIDATED BALANCE SHEET DATA
Total assets		116,673			117,529			131,860			142,945			139,641
Short-term and long-term debt		20,837			24,800			27,783			29,597			24,463
Capital stock issued		4,005			4,005			4,005			4,005			4,005
Minority interest		4,074			3,978			4,522			4,921			3,514
Shareholders’ equity - Eni share		44,436			46,073			51,206			55,472			59,199
Capital expenditures from continuing operations		12,935			12,216			12,450			11,909			12,761
Weighted average number of ordinary shares outstanding (fully diluted - shares million)		3,639			3,622			3,623			3,623			3,623
Dividend per share (euro) (1)		1.30			1.00			1.00			1.04			1.08
Dividend per ADR ($) (1) (2)		3.72			2.91			2.64			2.73			2.82

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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 2012 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 10, 2013.
(2)		Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/USD average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2008 through 2011 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 2012 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 1.08 per ADR) at the Noon Buying Rate recorded on the payment date on October 11, 2012, while the balance of euro 1.08 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2012. The balance dividend for 2012 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 23, 2013 to holders of Eni shares, being the ex-dividend date May 20, while ADRs holders will be paid late on June 7, 2013.

 

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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, 2008, 2009, 2010, 2011 and 2012. Data on production of oil and natural gas and hydrocarbon production sold includes Eni’s share of production of affiliates and joint ventures accounted for under the equity method. In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. From July 1, 2012, as part of an ongoing review of the yields at the Company’s gas fields currently in production, Eni has updated the conversion rate of gas to 5,492 cubic feet of gas equals 1 barrel of oil (it was 5,550 cubic feet of gas per barrel in previous reporting periods). The effect of this update on production expressed in BOE was 9 kBOE/d for the full year 2012 and the change in the initial reserves balance as of January 1, 2012 amounted to 40 mmBOE. Prior-year converted amounts were left unchanged. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depreciation and depletion charges. Other oil companies may use different conversion rates.

	Year ended December 31,

	2008		2009		2010		2011		2012

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)		3,243			3,377			3,415			3,134			3,084
of which developed		2,009			2,001			1,951			1,850			1,762
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)		142			86			208			300			266
of which developed		33			34			52			45			44
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) (1)		17,214			16,262			16,198			15,582			14,190
of which developed		11,138			11,650			10,965			10,363			8,965
Proved reserves of natural gas of equity-accounted entities at period end (BCF)		3,015			1,588			1,684			4,700			6,767
of which developed		420			234			246			53			424
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)		6,242			6,209			6,332			5,940			5,667
of which developed		3,948			4,030			3,926			3,716			3,394
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end		666			362			511			1,146			1,499
of which developed		107			74			96			54			122
Reserves replacement ratio (2)		135			96			125			142			107
Average daily production of liquids (kBBL/d) (3)		1,026			1,007			997			845			882
Average daily production of natural gas available for sale (mmCF/d) (3)		4,143			4,074			4,222			3,763			4,118
Average daily production of hydrocarbons available for sale (kBOE/d) (3)		1,748			1,716			1,757			1,523			1,631
Hydrocarbon production sold (mmBOE)		632.0			622.8			638.0			548.5			598.7
Oil and gas production costs per BOE (4)		7.65			7.41			8.89			10.86			10.82
Profit per barrel of oil equivalent (5)		16.00			8.14			11.91			16.98			15.95

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(1)		Includes approximately 746, 769, 767 and 767 BCF of natural gas held in storage in Italy as of December 31, 2008, 2009, 2010 and 2011, respectively.
(2)		Referred to Eni’s subsidiaries and its equity-accounted entities. Consists of: (i) the increase in proved reserves of consolidated subsidiaries attributable to: (a) purchases of minerals in place; (b) revisions of previous estimates; (c) improved recovery; and (d) extensions and discoveries, less sales of minerals in place; divided by (ii) production during the year as set forth in the reserve tables, in each case prepared in accordance with Topic 932. See the unaudited supplemental oil and gas information in "Item 18 – Notes to the Consolidated Financial Statements". Expressed as a percentage.
(3)		Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (281, 300, 318, 321 and 383 mmCF/d in 2008, 2009, 2010, 2011 and 2012, respectively).
(4)		Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment including also royalties) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in "Item 18 – Notes to the Consolidated Financial Statements".
(5)		Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in "Item 18 – Notes to the Consolidated Financial Statements" for a calculation of results of operations from oil and gas producing activities.

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Selected operating information continued

	Year ended December 31,

	2008		2009		2010		2011		2012

Sales of natural gas to third parties (1)		83.69			83.79			75.81			78.16			78.24
Natural gas consumed by Eni (1)		5.63			5.81			6.19			6.21			6.43
Sales of natural gas of affiliates (Eni’s share) (1)		8.91			7.95			9.41			9.53			7.92
Total sales and own consumption of natural gas of the Gas & Power segment (1)		98.23			97.55			91.41			93.90			92.59
E&P natural gas sales in Europe and in the Gulf of Mexico (1)		6.00			6.17			5.65			2.86			2.73
Worldwide natural gas sales (1)		104.23			103.72			97.06			96.76			95.32
Electricity sold (2)		29.93			33.96			39.54			40.28			42.58
Refinery throughputs (3)		35.84			34.55			34.80			31.96			30.01
Balanced capacity of wholly-owned refineries (4)		544			554			564			574			767
Retail sales (in Italy and rest of Europe) (3)		12.03			12.02			11.73			11.37			10.87
Number of service stations at period end (in Italy and rest of Europe)		5,956			5,986			6,167			6,287			6,384
Average throughput per service station (in Italy and rest of Europe) (5)		2,502			2,477			2,353			2,206			2,064
Chemical production (3)		7.37			6.52			7.22			6.25			6.09
Engineering & Construction order backlog at period end (6)		19,105			18,730			20,505			20,417			19,739
Employees at period end (units) (7)		71,741			71,461			73,768			72,574			77,838

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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,
2008		1.60		1.24		1.47		1.39
2009		1.51		1.25		1.39		1.44
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

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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 2012		1.31		1.29		1.30
November 2012		1.30		1.27		1.30
December 2012		1.33		1.29		1.32
January 2013		1.36		1.31		1.36
February 2013		1.37		1.31		1.31
March 2013		1.31		1.28		1.28

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 April 5, 2013 was $1.3027 per euro 1.00.

 

Risk factors

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, we expect 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 and market dynamics. This is likely to increase competition in all our businesses, which may impact costs and margins.

•		In the Exploration & Production segment Eni faces competition from both international oil companies 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 cost increases, its growth prospects and future results of operations and cash flows may be adversely affected.
•		In the Gas & Power segment, Eni is facing increasingly strong competition on both the Italian market and the European market due to continuing slowdown in demand and macroeconomic uncertainties in the face of large gas availability on the marketplace which has driven the development of very liquid continental hubs to trade spot gas. Gas supplies to Europe were fuelled by material additions to global LNG availability by upstream producers and large upgrades of existing pipelines and construction of new backbones on several European routes over the latest few years to expand the import capacity from Russia and Algeria. Those developments were compounded by very significant increases in the production of shale gas in the United States which reduced the Country’s dependence on imported gas and resulted in diversion of important LNG volumes to Europe. In 2012, those fundamental shifts in market dynamics coupled with a demand downturn triggered intense pricing competition among gas operators which negatively affected profitability. Additionally, gas marketing operators, including Eni, were hit by diverging trends in the cost of gas supplies compared to selling prices. In fact, procurement costs of those operators were mainly indexed to the price of oil and its derivatives as provided by pricing formulas in long-term supply contracts, whereas selling prices were determined on the basis of spot prices at continental hubs which were pressured by weak demands, oversupplies and competition. Those trends resulted in the Company’s Gas & Power segment reporting sharply higher operating losses in 2012 (down to euro 3,221 million compared to a loss of euro 326 million in 2011). We believe that the outlook for our gas marketing business will remain weak in the short to medium term as the ongoing trends affecting the sector will take time to be reversed. Management forecasts that a better balance between demand and supply on the European market is unlikely to be achieved before 2014 or 2015. The described trends may negatively affect the Company’s future results of operations and cash flows in its natural gas business, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of natural gas in accordance to its long-term gas supply contracts that include take-or-pay clauses. See the sector-specific risk section below.

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•		Eni also faces competition from large, well-established European utilities and other international oil and gas companies in growing its market share and acquiring or retaining clients. A number of large clients, particularly electricity producers and large industrial buyers, in both the domestic market and other European markets have entered the wholesale market of natural gas by directly purchasing gas from producers or sourcing it at the continental spot markets adding further pressures on the economics of gas operators, including Eni. Management believes that this trend will continue in the future. At the same time, a number of national gas producers from countries with large gas reserves are planning to sell natural gas directly to final clients, which would threaten the market position of companies like Eni which resell gas purchased from producing countries to final customers. These developments may increase the level of competition in both the Italian and other European markets and reduce Eni’s expected operating profit and cash flows in the gas business. Finally, following a law decree enacted in March 2012 from the Italian Government to spur competition in the Italian gas sector, management expects that the Company’s selling margins will likely come under pressure on sales at the regulated residential and service segments due to the implementation of a less favorable indexation mechanism of the raw material cost in supplies to such customers than in the past. This will be achieved by progressively introducing a spot-based indexation mechanism of the cost of gas replacing the current oil-linked formula which mirrors a basket of long-term supply contracts. We expect that similar measures will be introduced by other market regulators in European countries where Eni engages in selling gas to residential clients (see sector-specific risk factors below).
•		In its domestic 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 on the Italian market.
•		In the retail marketing of refined products both in Italy and abroad, Eni competes with third parties (including international oil companies and local operators such as supermarket chains) 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. In Italy, there is an ongoing pressure from political and administrative entities, including the Italian Antitrust Authority, to increase the level of competition in the retail marketing of fuels. The above mentioned law decree of March 2012 targeted the Italian fuel retail market, by relaxing commercial ties between independent operators of service stations and oil companies, enlarging options to build and operate fully-automated service stations, and opening up the merchandising of various kinds of goods and services at service stations. Eni expects developments in this field to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing market share in Italy. Furthermore, the ongoing demand downturn in the Italian fuel market is expected to exacerbate competition among oil companies and other retail operators due to large product availability on the marketplace.
•		In the Chemical segment, we are facing strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized market segments such as production of basic petrochemicals products and plastics. Many of those competitors based in the Far East and Middle East are able to benefit from cost advantages due to larger scale, looser environmental regulations, availability of cheaper feedstock, and more favorable location and proximity to end-markets. Excess capacity and sluggish economic growth may exacerbate competitive pressures. Furthermore, we expect that petrochemicals producers based in the U.S. will regain market share in the next future leveraging on a competitive cost structure due to the increasing availability of cheap feedstock deriving from the production of domestic shale gas. The Company expects continuing margin pressures in the foreseeable future as a result of those trends.
•		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.

The Company’s failure or inability to respond effectively to competition could adversely impact the Company’s growth prospects, future results of operations and cash flows.

 

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, storage and distribution of petroleum products, production of base chemicals and special products. By their nature the Group’s operation expose us 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 our activities. Eni’s future results from operations and liquidity depend on our ability to identify and mitigate the risks and hazards inherent to operating in those industries.

In exploration and production, we face 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

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environment and risks of 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 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), 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.

In the transportation area, the type of risk depends not only on the hazardous nature of the products transported, but also 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 dedicates a great deal of efforts and attention to safety, health, the environment and the prevention of risks; in pursuing compliance with applicable laws and policies; and in responding and learning from unexpected incidents. We seek to minimize these operational risks by carefully designing and building our 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 effectively could result in unexpected incidents, including releases, oil spills, explosions, 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 equipment and other property, all of which could lead to a disruption in operations. Our operations are often conducted in difficult or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic, in which the consequences of any incident could be greater than in other locations. We also face risks once production is discontinued, because our activities require 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 maintains insurance coverage that include coverage for physical damage to our assets, third party liability, workers’ compensation, pollution and other damage to the environment and other coverage. Our insurance is subject to caps, exclusion and limitation, and there is no assurance that such coverage will adequately protect us against liabilities from all potential consequences and damages. In light of the accident at the Macondo well in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher retentions. Also, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

The occurrence of the above mentioned 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.

 

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 our oil and gas fields. A description of the main risks facing our business in the exploration and production of oil and gas is provided below.

 

i) Our oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks

We have material operations relating to the exploration and production of hydrocarbons located offshore. In 2012, approximately 52% of our total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Norway, Italy, Angola, the Gulf of Mexico, Congo, UK and Nigeria. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. As the Macondo accident occurred 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. Also offshore operations are subject to marine perils, 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

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result in regulatory action, legal liability, loss of revenues and damage to our reputation and could have a material adverse effect on our operations or financial condition. In 2012, a gas leak following a well operation occurred at a wellhead platform of the Elgin/Franklin gas field, located in the UK North Sea. The field was operated by an international oil company with Eni holding 21.87% interest in the field. We incurred costs to restart the platform operations and reported a significant loss of production for the year (down by 7 mmBBL). We may also incur environmental liabilities which may arise from the incident.

 

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 variety of factors, including unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, blow-outs and other forms of accidents, marine risks such as collisions and adverse weather conditions and shortages or delays in the delivery of equipment. Exploration drilling in offshore areas, particularly in deep waters, is generally more challenging and riskier than in onshore areas; the same is true for exploratory activity in remote areas or in challenging environmental conditions in environmentally-sensitive locations such as those we are experiencing in the Barents Sea. 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 significant investments in executing high-risk exploration projects, it is likely that Eni will incur significant exploration and dry hole expenses in future years. Eni plans to explore for oil and gas onshore and offshore. A number of exploration projects are planned in deep and ultra-deep waters or at deep drilling depths, where operations are more challenging and costly than in other areas. Deep water operations generally may require significant time before commercial production of 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, Liberia, Ghana and Gabon), East Africa (Mozambique), the South-East Asia (Indonesia, Vietnam and other locations), Australia, the Barents Sea and the Black Sea. In 2012, the Company spent approximately euro 1.8 billion to conduct exploration projects and it plans to spend approximately euro 1.4 billion on average in the next four-year plan on exploration activities.

Unsuccessful exploration activities and failure to find additional commercial reserves could reduce future production of oil and natural gas which is highly dependent on the rate of success of exploratory activity.

 

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

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

•		the outcome of negotiations with co-venturers, governments and state-owned companies, suppliers, customers or others, including, for example, Eni’s ability to negotiate favorable long-term contracts to market gas reserves;
•		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 goods and services;
•		the ability to design development projects so as to prevent the occurrence of technical inconvenience;
•		delays in manufacturing and delivery of critical equipment, or shortages in the availability of such equipment, causing cost overruns and delays;
•		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 at project execution on the part of international contractors who are awarded project construction activities generally based on the EPC (engineering, procurement, construction) – turn key contractual scheme. We believe that this is mainly due to lack of contractual flexibility, poor quality of front-end design engineering and commissioning delays;
•		changes in operating conditions and cost overruns. In recent years, the industry has been impacted by escalating costs of certain critical productive factors including specialized workforce, procurement costs and costs for leasing third party equipment or purchase services such as drilling rigs as a result of industry-wide cost inflation, bottlenecks and other constraints in the worldwide production capacity available to build

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		critical equipment and facilities and growing complexity and scale of projects, including environmental and safety costs. Furthermore, there has been an evolution in the location of our projects, as we have been discovering increasingly important volumes of reserves in remote and harsh locations or environmentally sensitive locations (i.e. the Barents Sea, Alaska, the Jamal Peninsula, the Caspian Sea) where we are experiencing significantly higher operating costs and environmental, safety and other costs than in other locations. The Company expects that costs in its upstream operations will continue to rise in the foreseeable future;
•		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.

Poor project execution, delays in the achievement of critical events and production start-up, differences between scheduled and actual timing, as well as cost overruns may adversely affect the economic returns of our development projects. Failure to deliver major projects successfully could negatively impact our results of operations, cash flow and short-term targets of production growth. Finally, developing and marketing hydrocarbons reserves typically requires 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 cost, and Eni could have limited influence over and control of the operations, behaviors and performance of its partners. Furthermore, Eni may not have full operation control of the joint ventures in which participates and may have exposure to counterparty credit risk and disruption of operation and strategic objectives due to the nature of its relationships.

We have incurred material cost overruns and substantial delay in the scheduling of production start-up at the Kashagan oilfield, where development is ongoing. These negative trends were driven by a number of factors including depreciation of the U.S. dollar versus the euro and other currencies; cost escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the offshore facilities. The partners of the venture are currently targeting the achievement of the first commercial production by the first half of 2013 in accordance to the updated development plan covering Phase 1 of the field development which was agreed with the Kazakh Authorities in the course of 2012. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the Kashagan project.

We have also experienced a few delays at a number of development projects located mainly in Algeria, the UK, Angola and Norway. Those delays were attributable to execution issues and delivery of critical equipment reflecting capacity constraints. These events will impact the timing profile of our planned production growth in the short term.

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

 

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 Production Sharing Agreements ("PSAs") and similar contractual schemes. In accordance to such contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditures. In 2012, the Company’s reserve replacement was negatively affected by lower entitlements in its PSAs and in the economics of marginal productions for an estimated amount of 62 mmBOE, which however did not impair the Company’s ability to fully replace reserves produced in the year. See "Item 4 – Business overview – Exploration & Production" and "Item 5 – Management’s expectations of operations". 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 countries and other owners of known reserves and acquisitions. In a number of reserve-rich countries, national oil companies control a large portion of oil and gas reserves that remain to be developed. To the extent that national oil companies decide to develop those reserve without the participation of international oil companies or if our Company fails to establish partnership with national oil companies, our ability to access or develop additional reserves will be limited.

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An inability to replace produced reserves by finding, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If we are unsuccessful, we may not meet our long-term targets of production growth and reserve replacement, and our future total proved reserves and production will decline, negatively affecting Eni’s future results of operations and financial condition.

 

v) Changes in crude oil and natural gas prices may adversely affect Eni’s results of operations

The exploration and production of oil and gas is a commodity business with a history of price volatility. The single largest variable that affects the Company’s results of operations and financial condition is crude oil prices. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flows. Eni generally does not hedge exposure of the Group reserves to fluctuations in future cash flows due to crude oil price movements. As a consequence, Eni’s profitability depends heavily on crude oil and natural gas prices. Crude oil and natural gas prices are subject to international supply and demand and other factors that are beyond Eni’s control, including among other things:

(i)		the control on production exerted by the Organization of the Petroleum Exporting Countries ("OPEC") member countries which control a significant portion of the world’s supply of oil and can exercise substantial influence on price levels;
(ii)		global geopolitical and economic developments, including sanctions imposed on certain oil-producing countries on the basis of resolutions of the United Nations or bilateral sanctions;
(iii)		global and regional dynamics of demand and supply of oil and gas; we believe that the current economic slowdown may have affected global demand for oil. In 2012, gas demand in Europe and Italy fell sharply due to the economic downturn. This trend negatively affected gas prices at our North Sea fields;
(iv)		prices and availability of alternative sources of energy. We believe that gas demand in Europe has been impacted by a shift to the use of coal in firing power plants due to cost advantages compared to gas, as well as the rising contribution of renewable energies in satisfying energy requirements. We expect those trends to continue in the future;
(v)		governmental and intergovernmental regulations, including the implementation of national or international laws or regulations intended to limit greenhouse gas emissions, which could impact the prices of hydrocarbons; and
(vi)		success in developing and applying new technology.

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

Lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flows by: (i) reducing rates of return of development projects either planned or being implemented, leading the Company to reschedule, postpone or cancel development projects, or accept a lower rate of return on such projects; (ii) reducing the Group’s liquidity, entailing lower resources to fund expansion projects, further dampening the Company’s ability to grow future production and revenues; and (iii) triggering a review of future recoverability of the Company’s carrying amounts of oil and gas properties, which could lead to the recognition of significant impairment charges.

 

vi) We expect 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 interests, 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, we expect that governments throughout the world will implement stricter regulation 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, could increase the cost of compliance and may also require changes to our drilling operations and exploration and development plans and may lead to higher royalties and taxes.

 

vii) 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 depends 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 timing of development expenditures;

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•

whether the prevailing tax rules, other government regulations and contractual conditions will remain the same as on the date estimates are made;

•		results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may require 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.

In particular the reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s PSAs and similar contractual schemes.

Many of these factors, assumptions and variables involved in estimating proved reserves are beyond Eni’s control and may change over time and impact the estimates of oil and natural gas reserves. Accordingly, the estimated reserves could be significantly different from the quantities of oil and natural gas that will ultimately be recovered. Additionally, 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.

 

viii) 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 44%. The tax rate of the Company’s Exploration & Production segment for the fiscal year 2012 was approximately 60%.

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, 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, 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.

 

Political considerations

A substantial portion of our oil and gas reserves and gas supplies are located in countries which are politically, socially and economically less stable than OECD countries. Therefore we are exposed to risks of material disruptions to our operations in those less stable countries. As of December 31, 2012, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries and 59% of Eni’s supplies of natural gas came from countries outside OECD countries. See "Item 4 – Exploration & Production and Gas & Power" for more information about the Group reserve locations and natural gas supplies.

Adverse political, social and economic developments 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 issues:

(i)		lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
(ii)		unfavorable developments in laws, regulations and contractual arrangements leading, for example, to expropriations 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 with 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 481 million relating to cost recovery under a petroleum contract 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

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(v)

civil and social unrest leading to sabotages, acts of violence and incidents. For example, we experienced continuing acts of sabotage and theft in Nigeria which caused significant production losses and negatively affected our results of operations in the Country for the year 2012.

See "Item 4 – Exploration & Production – Oil and natural gas reserves".

While the occurrence of those events is unpredictable, it is likely that the occurrence of such events could cause Eni to incur material losses or facility disruptions, by this way adversely impacting Eni’s results of operations and cash flows.

 

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

As of end of 2012, approximately 30% of the Company’s proved oil and gas reserves were located in North Africa and Middle East. In 2011, several North African and Middle Eastern oil producing countries experienced an extreme level of political instability that has resulted in changes in governments, unrest and violence and consequential economic disruptions. This instability is currently continuing to affect the region. The 2011 situation was particularly serious in Libya where the political instability escalated to turn out into an internal revolution and conflict which caused material disruptions to our operations in the country for a period of eight months. After the end of the conflict in late 2011, Eni was able to restart its all fields, producing facilities and gas exports through the GreenStream pipeline. In the course of 2012, the Company has progressively built up production volumes and achieved a level of approximately 258 kBOE/d on average for the year. However, we were unable to restore the full production plateau at our fields contrary to our initial planning assumptions, due to the complexity of the transition period which the Country is currently undergoing.

We believe that the political outlook in North Africa and Middle East remains an area of risks for our operations, results and strategic development.

 

Risks associated with our presence in sanction targets

Our activities in Iran could lead to sanctions under relevant U.S. legislation

Eni is currently conducting oil and gas operations in Iran. The legislation and other regulations of the United States 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.

The United States enacted the Iran Sanctions Act of 1996 (as amended, "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 investment in Iran’s petroleum sector. The ISA was amended in July 2010 by the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 ("CISADA"). As a result, in addition to sanctions for knowingly investing in Iran’s petroleum sector, parties engaging in business activities in Iran now may be sanctioned under the ISA for knowingly providing to Iran refined petroleum products, and for knowingly providing to Iran goods, services, technology, information or support that could directly and significantly either: (i) facilitate 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 also expanded the menu of sanctions available to the President of the United States by three, from six to nine, and requires the President to impose three of the nine sanctions, as opposed to two of six, if the President has determined that a party has engaged in sanctionable conduct. The new sanctions include a prohibition on transactions in foreign exchange by the sanctioned company, a prohibition of any transfers of credit or payments between, by, through or to any financial institution to the extent the interest of a sanctioned company is involved, and a requirement to "block" or "freeze" any property of the sanctioned company that is subject to the jurisdiction of the United States. Investments in the petroleum sector that commenced prior to the adoption of CISADA appear to remain subject to the pre-amended version of the ISA, except for the mandatory investigation requirements described below, but no definitive guidance has been given. The new sanctions added by CISADA would be available to the President with respect to new investments in the petroleum sector or any other sanctionable activity occurring on or after July 1, 2010. CISADA also adopted measures designed to reduce the President’s discretion in enforcement under the ISA, including a requirement for the President to undertake an investigation upon being presented with credible evidence that a person is engaged in sanctionable activity. CISADA also added to the ISA provisions 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. The President also may waive sanctions, subject to certain conditions and limitations.

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The United States maintains 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 sanctions generally restrict the dealings of U.S. citizens and persons subject to the jurisdiction of the United States. In addition, we are 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 our 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 our share price. Even if our activities in and with respect to Iran do not subject us 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.

With regard to the trading of crude oil, the above mentioned measures (in particular, the Iran Threat Reduction and Syrian Human Rights Acts of August 10, 2012, and the National Defense Authorization Acts 2012) provide for a ban on carrying out transactions associated with the purchase of crude oil and a ban on owning, operating or insuring any vessels used to transport Iranian crude. Both bans may be granted a waiver by the U.S. State Department (based on the National Defense Authorization Act for the Fiscal Year 2012) covering the home-country of an entity or the country of destination of the crude oil. A waiver granted to Italy and other EU Member States in March 2012 and lastly renewed on March 13, 2013 for a further 180-day period.

Other sanctions programs have been adopted by various governments and regulators with respect to Iran, including a series of resolutions from the United Nations Security Council, and measures imposed by various countries based on and to implement these United Nations Security Council resolutions. On July 26, 2010, the European Union adopted new restrictive measures regarding Iran (referred to as the "EU measures"). Among other things, the supply of equipment and technology in the following sectors of the oil and gas industry in Iran are prohibited: refining, liquefied natural gas, exploration and production. The prohibition extends to technical assistance, training and financing and financial assistance in connection with such items. Extension of loans or credit to, acquisition of shares in, entry into joint ventures with or other participation in enterprises in Iran (or Iranian owned enterprises outside of Iran) engaged in any of the targeted sectors also is prohibited.

On March 23, 2012 the Council of the European Union enacted regulation prohibiting the import, transport and purchase of Iranian crude oil and petroleum products. The rules allow for the performance of contracts, entered into 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.

In the last months of 2012, the Council of the European Union adopted new measures providing for additional restrictive measures against Iran including:

•		export prohibition on key naval equipment and technology for ship-building, maintenance or refit;
•		prohibition in trade in graphite, raw or semi-finished metals, such as aluminum and steel, and software for certain industrial processes;
•		ban on the import, purchase or transport of Iranian natural gas;
•		prohibitions on the provision of flagging and classification services to Iranian oil tankers and cargo vessels; and
•		prohibition on the supply of vessels designed for the transport or storage of Iranian oil and petrochemical products.

The new measures also prohibit transactions between the European Union and Iranian banks and financial institutions, unless an authorization is granted in advance by the relevant Member State and include 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, starting from April 15, 2013.

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

The European measures provide a waiver of certain prohibitions (i.e. embargo on oil and gas key technologies, prohibition to supply of vessels for the purpose of transporting Iranian oil, asset freeze of the National Iranian Corp and its subsidiaries) in order to perform obligations under contracts entered into before January 23, 2012, which provide for the supply of Iranian crude oil and petroleum products as a reimbursement of outstanding receivables due to entities under the jurisdictions of EU member states by Iranian counterparties (such as the case of Eni service contracts described therein). Under this waiver Eni is allowed to carry out its upstream and oil import activities. In this respect, Eni is in close contact with the competent European authorities in order to obtain the relevant authorizations, certain of which have already been received.

Eni Exploration & Production segment 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)

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entered into with the National Iranian Oil Co (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 oil fields, and is entitled to recovery of expenditures made, as well as a service fee. The service contracts do not provide for payments to be made by Eni, as contractor, to the Iranian Government (e.g. leasing fees, bonuses, significant amounts of local taxes); all material future cash flows relate to the payment to Eni of its dues. All projects mentioned above have been completed or substantially completed; the Darquain project, is in the process of final commissioning and is being handed over to the NIOC. In this respect, we expect to incur operating costs in the range of approximately $10 to $20 million per year over the next few years for contractual support activities and services. In 2012, we incurred $22 million to provide such activities and services.

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.

In 2012, Eni’s production in Iran averaged 3 kBOE/d, representing less than 1% of the Eni Group’s total production for the year. Eni’s entitlement in 2012 represented less than 3% of the overall production from the oil and gas fields that we have developed in Iran. Eni believes that the results from its Iranian exploration and production are immaterial to the Group’s results.

After 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 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, we will not be regarded as a company of concern for our past Iran related activities.

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

Such restrictive measures are: the Executive Orders 13590 of November 21, 2011 and 13622 of July 31, 2012 and 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 among those subject to sanctions.

The new provisions impose, inter alia, sanctions on persons that are determined to have engaged in certain activities in support of Iran’s energy and petrochemicals sector that are not specifically targeted by the ISA, as amended by CISADA.

Those activities include:

•		the provision of goods, services, technology or support that have a fair market value above certain monetary thresholds and that could directly and significantly contribute to the maintenance or enhancement of Iran’s ability to develop its petroleum resources or to the maintenance or expansion of Iran’s domestic production of petrochemical products;
•		the purchase of petrochemical products from Iran, and the supply of financial, material, technological support for, or goods or services in support of the National Iranian Oil Co (NIOC); and
•		the participation in a joint oil and gas development venture with Iran, outside Iran, if that venture was established after January 1, 2002.

As discussed above, pursuant to the Darquain service contract, entered into prior to the date of these measures, Eni is providing services in advance of the hand over of the oilfield to NIOC and retains certain technical assistance and service obligations, and an obligation to provide, upon request, spare parts and supplies for field maintenance and operations. We do not believe that Eni’s activities in Iran (the completion of existing contracts which has already been notified to the U.S. administration when the Special Rule was applied) are sanctionable under the mentioned measures. However, 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 such measures. If sanctions were imposed, their impact could be material and adverse to Eni.

Our Refining & Marketing segment has historically purchased amounts of Iranian crude oil under a term contract with the NIOC and on a spot basis. We purchased 1.63 mmtonnes, 976 ktonnes and 498 ktonnes in 2010, 2011 and 2012, respectively. We paid NIOC $888 million in 2010, $742 million in 2011 and $396 million in 2012, for those purchases.

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In addition, in 2010 we purchased crude oil from international traders and oil companies who, based on bills of loading and shipping documentation available to us, we believe purchased the crude oil from Iranian companies. Purchases were mainly on spot basis. In 2010, we purchased 2.09 mmtonnes of crude oil amounting to $1.1 billion.

Also as a consequence of EU restrictive measures, in June 2012 Eni ceased to import Iranian crude oil with the exception of those volumes necessary to collect outstanding receivables towards Iranian counterparties, as allowed by the European Union sanctions regime.

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

Finally, our 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. Eni plans to suspend all contracts by April 2013 to comply with EU restrictions.

We will continue to monitor closely legislative and other developments in the United States and the European Union in order to determine whether our remaining interests in Iran could subject us to application of either current or future sanctions under the OFAC sanctions, the ISA, the EU Measures or otherwise. If any of our 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 our business, plans to raise financing, sales and reputation.

 

We have commercial transactions with Syria where we mainly purchase from time to time volumes of crude oil

Our operations in Syria have mainly been limited to transactions carried out by our Refining & Marketing segment with Syrian Petrol Co, an entity controlled by the Syrian Government, for the purchase of crude oil under term purchase contracts or on a spot basis, based on prevailing market conditions.

We purchased 321 ktonnes and 243 ktonnes in 2010 and 2011, respectively. We paid Syrian Petrol Co $163 million in 2010 and $175 million in 2011, for those purchases. No crude oil purchases were made in 2012.

We also purchased small amounts of crude oil from international traders who, based on bills of lading and shipping documentation available to us, we believe purchased those raw materials from Syrian companies.

In 2010, our Engineering & Construction segment was awarded by Dijla Petroleum Co, an affiliate of the Syrian National Oil Co, a contract for the central processing facility to be installed at the Khurbet East oil field, on Block 26.

Other than as described above, Eni is not currently investing in the country, and it has no contractual arrangements in place to invest in the Country.

 

We have a limited presence in the Democratic Republic of Congo

In August 2010, we signed a farm-in agreement with the UK-based Surestream Petroleum to acquire the 55% interest and the operatorship in the Ndunda Block in the Democratic Republic of Congo. Currently we are not conducting any activity in this Country.

 

Cyclicality of the petrochemical industry

The petrochemical industry is subject to fluctuations in demand in response to macroeconomic cycles, leading to volatile results of operations and cash flow. It is a highly competitive industry due to lack of entry barriers, product commoditization and excess capacity, which may exacerbate the impact of any demand downturns on the results reported by our Chemicals business. Eni’s chemical operations have been facing increasing competition from Asian companies and the petrochemical arm of national oil companies based in the Middle East which can leverage on long-term competitive advantages in terms of lower operating costs and cheaper feedstock costs. In particular, Eni’s competitors based in the Middle East are benefiting from the large availability of gas-based feedstock which provides a cost advantage compared to the oil-based feedstock used at Eni’s operations. Management also expects that U.S.-based petrochemical companies will regain competitiveness in the medium term leveraging on the large domestic availability of raw materials which can be extracted from shale gas.

Our chemical operations are located mainly in Italy and Western Europe where the expenses to comply with environmental, safety and security rules may be higher than in most Asian countries due to an established regulatory framework and public environmental sensitivity. Additionally, our petrochemical operations lack sufficient scale and

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competitiveness at a number of sites owing also to geographic location and other structural weaknesses. Due to poor industry fundamentals, intense competitive pressures, high feedstock costs, coupled with company-specific factors, our chemical operations incurred substantial operating losses in recent years. In 2012, our chemicals operations reported sharply higher operating losses compared to the year earlier, down to euro 683 million (down by 61%) driven by unprofitable product margins particularly in the basic petrochemicals and polyethylene businesses which were impaired by high oil-based feedstock costs, and lower sales volumes amidst a demand downturn. Looking forward, management expects that in the foreseeable future results and cash flow at our chemical business could be adversely affected by a weak economic outlook in Italy and Europe. Furthermore, rising costs of oil-based feedstock represent a risk to the profitability of the Company’s petrochemical operations as it may be difficult to preserve products margins due to the high level of competition in the industry and the commoditized nature of many of Eni’s products.

 

Risks in the Company Gas & Power business

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

In 2012, the Company’s gas marketing business reported sharply lower operating losses due to a demand downturn and increasing competitive pressures arising from large gas availability in the marketplace. We expect negative market conditions to affect results and liquidity in 2013 and beyond

The Company’s gas marketing business has reported operating losses and negative cash flow in 2012 and 2011 due to a demand downturn and changed competitive dynamics in the European gas sector. Gas demand has been severely hit by the economic slowdown and lower consumption in the thermoelectric sector. The latter trend was affected by an ongoing expansion of renewable sources of electricity and a shift away from gas to the use of coal in firing power plants due to cost advantages. In the face of weak demand, supplies on the marketplace have continued to increase fuelled by pipeline upgrades, growing availability of LNG and the fact that the U.S. have reduced their dependence on LNG imports due to large development of domestic production of shale gas further adding to global LNG supplies. Those trends have driven the expansion of very liquid continental 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 latest few years reflecting oversupplies and weak demand. This trend has hit the profitability at European gas marketing operators, including Eni. Those operators procured their gas supplies under long-term contracts with producing countries whereby the cost of gas is generally indexed to the price of crude oil and other derivatives and margins were squeezed due to a decoupling between spot prices and the oil-linked costs of purchased gas. Adding to the pressure was the circumstance that reduced sales opportunities forced operators to aggressively compete on pricing to limit the financial risks associated with the take-or-pay clause provided by the long-term supply contracts. On their part, large clients adopted opportunistic supply patterns, in order to take advantage of the large availability of spot gas. Finally governmental administrations in several European countries have commenced to review the indexation mechanism of supply tariffs in the retail sector in order to make residential customers benefit from the ongoing trend in gas spot markets. Against this backdrop, our gas marketing business reported sharply higher operating losses down to euro 3,221 million due also to material impairment charges to align the asset book values to their lower values-in-use to reflect a reduced profitability outlook.

Management expects industrial conditions in the gas sector in Italy and Europe to remain unfavorable over the short to the medium term due to continuing market imbalances and strong competition. We forecasts that weak gas demand due to the current economic downturn and uncertainties, the persistence of oversupplies and strong competition will represent risk factors to the profitability outlook of the Company gas marketing business over the next two to three years. Short-term perspectives are anticipated to be highly adverse in Italy where the economic recovery is feeble, the price of gas to industrial and other large clients is likely to align to the pricing level at the continental hubs and finally gas margins are expected to be affected by the liberalization measures enacted by the Italian Government intended to reduce the cost of gas to residential users (see below). We believe 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 (see below).

 

We are seeking to improve our cost competitiveness by renegotiating more favorable contractual terms with our long-term suppliers. If we fail to achieve this our profitability could be adversely affected

Our 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 in a changed market environment. We are seeking to renegotiate better terms and pricing of our long-term supply contracts in the next future years to align our cost structure to prices prevailing in the marketplace in order to preserve the profitability of our gas operations. If we fail to obtain the planned benefits, our future results and cash flow could be adversely affected. Furthermore, we believe that our results will become more volatile and unpredictable in future years as contractual renegotiations take time to define, possibly leading to large one-off price adjustments recorded in the reporting period when the new terms are agreed upon. In addition, in case the parties are entitled to fail to arrange renewed contractual terms, both of them may seek an

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arbitration ruling, which increases the uncertainty regarding a final outcome of the renegotiation process. Similarly, we expect that a number of our clients whom we supply to on long-term basis, will request price revisions and other contractual changes.

 

We expect that current imbalances between demand and supply in the European gas market will persist for sometime

In 2012, gas demand fell by 2% in Europe and by 4% in Italy due to the economic downturn and sharply lower gas consumptions in the thermoelectric sector. Management estimates that gas demand will grow at an average rate of approximately 1.7% in Italy and Europe until 2020. Those estimates have been revised downward from previous management projections to factor in the risks associated with a number of ongoing trends:

•		uncertainties and volatility in the macroeconomic cycle; particularly the current downturn in Europe will weigh on the short-term perspectives of a rapid recovery in gas demand;
•		growing adoption of consumption patterns and life-styles characterized by wider sensitivity to energy efficiency; and
•		EU policies intended to reduce GHG emissions and promote renewable energy sources. For further information about the Company’s outlook for gas demand see "Item 4 – Gas & Power".

The projected moderate dynamics in demand will not be enough to balance current oversupplies on the marketplace over the next two to three years according to management’s estimates. Gas oversupplies have been increasing in recent years as new, large investments to upgrade import pipelines to Europe have come online from Russia and Algeria, and large availability of LNG on a worldwide scale has found an outlet at the European continental hubs driving the development of very liquid spot gas markets. Furthermore, in the near future management expects the start-up of new infrastructures in various European entry points which will add large amounts of new import capacity over the next few years. Those include a new line of the Nord Stream pipeline connecting Russia to Germany through the Baltic Sea as well as new LNG facilities. In Italy, the gas offered will increase moderately in the next future as a new LNG plant is expected to start operations at Livorno with a 4 BCM treatment capacity and effects are in place of Law Decree No. 130/2010 about storage capacity which is expected to increase by 4 BCM by 2015.

These developments will be tempered by an expected increase in worldwide gas demand driven by economic growth in China and other emerging economies, a slowdown in additions of new worldwide LNG capacity, and mature field decline in Europe.

Those trends represent risks to the Company’s future results of operations and cash flows in its gas business. See "Item 4 – Gas & Power" for further information about our long-term expectations on gas demand and supply.

 

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, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts have been ensuring approximately 80 BCM of gas availability from 2010 (including the Distrigas portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 16 years and a pricing mechanism that indexes the cost of gas to the price of crude oil and its products (gasoil, fuel oil, etc.). These contracts include take-or-pay clauses whereby the Company is required to off-take minimum pre-determined 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 during the period of contract execution. Amounts of cash prepayments and time schedules for off-taking pre-paid gas vary from contract to contract. Generally, cash prepayments 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 pre-payments range from 10 to 100 percent 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 100%, 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.

Management believes that the current outlook pointing to weak gas demand growth and large gas availability on the marketplace, the possible evolution of sector-specific regulation, as well as strong competitive pressures on the

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marketplace represent risk factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts.

Since the beginning of the downturn in the European gas market late in 2009, Eni has triggered the take-or-pay clause as the Company collected lower volumes than its minimum take obligations in each of those years accumulating deferred costs amounting to euro 2.37 billion and has paid almost the whole of the relevant cash advances.

Considering ongoing market trends and the Company’s outlook for its sales volumes which are anticipated to remain stable in 2013 and to increase at a moderate pace in subsequent years, as well as the expected benefit associated with contract renegotiations which may temporarily reduce the annual minimum take and other commercial initiatives, management believes that the Company’s exposure to take-or-pay contracts will need continuing monitoring and will continue to give rise to financial risk in future years.

In addition to the financial risk, failure to off-take the contractual minimum amounts exposes the Company to a price risk, because the purchase price Eni will ultimately be required to pay is based on future energy prices which may be higher than the energy prices prevailing when the off-take obligation arose. In addition, Eni is subject to the risk of not being able to dispose of pre-paid volumes should the total addressable market be smaller than the Company’s gas availability in the relevant period. Finally, the Company expects to incur financing costs considering the cash advances already paid to its suppliers. As a result, the Company’s selling margins, results of operations and cash flow may be negatively affected. For further information on the Company’s take-or-pay contracts see "Item 4 – Gas & Power – Purchases".

 

Eni plans to increase natural gas sales in Europe. If Eni fails to achieve projected growth targets, this could adversely impact future results of operations and liquidity

Over the medium term, Eni plans to increase its natural gas sales in Europe leveraging on its natural gas availability under take-or-pay purchase contracts, availability of transport rights and storage capacity, and widespread commercial presence in Europe. Should Eni fail to increase natural gas sales in Europe as planned due to poor strategy execution or competition, Eni’s future growth prospects, results of operations and cash flows might be adversely affected also taking account that Eni might be unable to fulfill its contractual obligations to purchase certain minimum amounts of natural gas based on its take-or-pay purchase contracts currently in force.

 

ii) Risks associated with sector-specific regulations in Italy

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

The Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing. Specifically, the Authority for Electricity and Gas holds a 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 consuming less than 50,000 CM/y (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 Authority for Electricity and Gas 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. The indexation mechanism set by the Authority for Electricity and Gas basically provides that the cost of the raw material in the pricing formula to the residential sector be indexed to movements in a basket of hydrocarbons. The Authority for Electricity and Gas modified in a few occasions that indexation mechanism by introducing price adjustments to benefit the residential customers.

Finally, the Italian law decree on liberalizations enacted in March 2012 entrusted the AEEG with the task to gradually introduce reference to the price of certain benchmarks quoted at continental hubs in the indexation mechanism of the cost of gas in the pricing of sales to the above mentioned customers. In compliance with the recently enacted law, the AEEG published a consultation document regarding the reform of the gas retail prices proposing, starting from April 2013, 20% of the retail gas price raw material component shall be linked to spot prices (up from current 5%). Starting from October 2013, the raw material component is planned to be 100% spot based; this should be partially offset by the introduction of new tariff components, applicable for the next two thermal years, in order to grant a gradual transition from oil-linked prices to spot market determined prices, to cover the costs of the transition to new supply formulas and to favor an effective renegotiation of long-term contracts for importing gas. Management believes that this development will negatively affect the profitability of the Company sales in the residential market in Italy because we expect that trends in spot prices will be less favorable than the oil-linked cost of gas supplies to the Group, thus limiting our ability to pass cost increases to our clients. This will adversely affect our future results and cash flow.

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Recent liberalization measures in the gas storage sector

At the beginning of 2013, the Minister of Economic Development and the Italian Authority for Electricity and Gas introduced new criteria for the allocation of gas storage capacities pursuant to Article 14 of Law Decree No. 1/2012. In particular:

•		the natural gas storage capacity which becomes available as a result of the decreased amount of strategic storage and of new methods for calculating the modulation storage obligations is assigned to industrial companies and regasifiers; and
•		the modulation storage capacity for the needs of "vulnerable customers" is assigned partly with competitive bidding procedures, and partly under existing procedures.

 

The Italian Government has taken steps to increase competition in the Italian natural gas market. Further regulatory developments are possible in the future which may adversely affect Eni’s results of operations and cash flows

The Italian Government has long supported a higher degree of competition in the Italian natural gas market and this may produce significant developments in this area.

In March 2012, a law decree on liberalizations was enacted which established new measures to enhance competition in the Italian natural gas market. Among those measures, there was a provision that required Eni to divest its shareholding in Snam, the Italian dominant player in the field of gas transportation, distribution and storage. The divestiture of a significant stake in Snam was made to an entity controlled by the Italian State, effective October 15, 2012; as part of the transaction Eni lost control over the investee.

Management believes the institutional debate on the degree of competition in the Italian natural gas market and the regulatory activity to be areas of concern and cannot exclude negative impacts deriving from developments on these matters on Eni’s future results of operations and cash flows.

For more information on these issues see "Item 4 – Regulation of Eni’s businesses – Gas & Power".

 

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 petrochemicals activities due to the fact that Eni is the incumbent operator in those markets in Italy and a large European player. See "Item 18 – note 34 of the Notes to the Consolidated Financial Statements" for a full description of Eni’s main pending antitrust proceedings. 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 regulation

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, products 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, petrochemicals and other Group 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

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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 exposes 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 due to 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 to comply with laws and regulations addressing safeguard of the environment, safety on the workplace, health of employees 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, caused by our activities or accidents; and
•		costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging.

In addition, growing public concerns in the EU and globally that rising greenhouse gas emissions and climate change may significantly affect the environment and society could adversely affect our businesses, including the possible enactment of stricter regulations that increase our operating costs, affect product sales and reduce profitability. For more discussion about this topic see "Item 4 – Environmental regulations".

Furthermore, in the countries where we operate or expect 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 us to incur material costs resulting from actions taken to comply with such laws and regulations, including:

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

As a further result of any new laws and regulations or other factors, we may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish our productivity and materially and adversely impact our results of operations, including profits.

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

 

Eni has incurred in the past and may incur in the future material environmental liabilities in connection to the environmental impact of its past and present industrial activities. Also plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution

Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management’s beliefs that Eni adopts high operational standards to ensure safety of its operations and to protect the environment and health of people and employees, it is possible that incidents like blow-outs, oil spills, contaminations 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.

Environmental laws also require the Company to remediate and clean-up the environmental impacts of prior disposals or releases of chemicals or petroleum substances and pollutants by the Company. Such contingent liabilities may exist at various sites that the Company disposed of, closed or shut down in prior years where the Group products have been produced, processed, stored, distributed or sold, such as chemicals plants, mineral-metallurgic plants, refineries and other facilities. The Company is particularly exposed to the risk of environmental liabilities in Italy where several industrial installations operated by Eni were located which were subsequently divested, closed, liquidated or shut down. At those industrial locations Eni has commenced a number of initiatives to restore and clean-up proprietary

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or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. Notwithstanding the Group claimed that it cannot be held liable for such past contaminations as permitted by applicable regulations in case of declaration rendered by a guiltless owner – particularly regulations that enacted into Italian legislation the Directive No. 2004/35/EC – plaintiffs and several public administrations have been acting against Eni to claim both the environmental damage and measures to perform additional clean-up and remediation projects in a number of civil and administrative proceedings. Remedial and clean-up activities with respect to the Company’s sites are expected to continue in the foreseeable future, impacting our liquidity as with reference to the balance sheet date 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 Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavorable developments in ongoing litigation on the environmental status of certain Company’s site where a number of public administrations and the Italian Ministry for 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 future environmental restoration and remediation programs are often inherently difficult to estimate.

 

Legal Proceedings

Eni is defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of the balance sheet date to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to 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. For more information see disclosure of pending litigation in "Item 18 – note 34 of the Notes to the Consolidated Financial Statements".

 

Risks related to changes in the price of oil, natural gas, refined products and chemicals

Operating results in Eni’s Exploration & Production, Refining & Marketing, and Chemical segments are affected by changes in the price of crude oil and by the impacts of movements in crude oil prices on margins of refined and petrochemical products.

 

Eni’s results of operations are affected by changes in international oil prices

Overall, lower oil prices have a net adverse impact on Eni’s results of operations. The effect of lower oil prices on Eni’s average realizations for produced oil is generally immediate. Furthermore, Eni’s average realizations for produced oil differ from the price of Brent crude marker primarily due to the circumstance that Eni’s production slate, which also includes heavy crude qualities, has a lower API gravity compared with Brent crude (when processed the latter allows for higher yields of valuable products compared to heavy crude qualities, hence higher market price).

 

The favorable impact of higher oil prices on Eni’s results of operations may be offset in part by opposite trends in margins for Eni’s downstream businesses

The impact of changes in crude oil prices on Eni’s downstream businesses, including the Gas & Power, the Refining & Marketing and the Chemicals businesses, depends upon the speed at which the prices of gas and products adjust to reflect movements in oil prices.

In the Gas & Power segment, increases in oil price represent a risk to the profitability of the Company sales as gas supplies are mainly indexed to the cost of oil and certain refined products, while selling prices, particularly outside Italy, are increasingly benchmarked to gas spot prices quoted at continental hubs. In the current trading environment, spot prices at those hubs are particularly depressed due to oversupply conditions. In 2012, the de-coupling between trends in the oil-linked costs of supplies and spot prices of gas sales was the main driver of the operating loss incurred

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by our gas marketing business. We expect that such unfavorable trend will continue in 2013 and beyond due to ongoing rising trends in crude oil prices and weak spot prices pressured by sluggish industry fundamentals and competition.

In addition, the Italian Authority for Electricity and Gas and other European regulatory authorities may limit the ability of the Company to pass cost increases linked to higher oil prices onto selling prices in supplies to residential customers and small businesses as we expect a shift to spot prices in the indexation mechanism of the raw material cost which may replace the oil-linked indexation in selling formulas to those customers. See the paragraph "Risks in the Company’s gas business" above for more information.

In addition, in light of the changed European gas market environment, Eni has adopted new risk management policies. These policies contemplate the use of derivative contracts to mitigate the exposure of Eni’s future cash flows to future changes in gas prices; such exposure had been exacerbated in recent years by the fact that spot prices at European gas hubs have ceased to track the oil prices to which Eni’s long-term supply contracts are linked.

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 future prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. All derivative contracts that are not entered into for hedging purposes in accordance with IFRS will be accounted through profit and loss, resulting in higher volatility of the gas business’ operating profit. Please see "Item 5 – Financial review – Management’s expectations of operations" and "Item 11 – Quantitative and qualitative disclosures about market risk".

In the Refining & Marketing and Chemicals businesses a time lag exists between movements in oil prices and in prices of finished products.

 

Eni’s results of operations are affected by changes in European refining margins

Results of operations at Eni’s Refining & Marketing segment are substantially affected by changes in European refining margins which reflect changes in relative 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. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy or sour crude qualities versus light or sweet crude qualities, taking into account the ability of Eni’s refineries to process complex crudes that represent a cost advantage when market prices of heavy crudes are relatively cheaper than the marker Brent price.

In 2012, Eni’s refining margins were unprofitable as the high cost of oil was only partially transferred to final prices of fuels pressured by weak demand, high worldwide and regional inventory levels and excess refining capacity particularly in the Mediterranean area. Furthermore, the profitability of complex cycles was impaired due to shrinking price differentials between heavy crudes versus light ones. Management does not expect any significant recovery in industry fundamentals over the short to medium term. The sector as a whole will continue to suffer from weak demand and excess capacity, while the cost of oil feedstock may continue rising and price differentials may remain compressed.

In this context, management expects that the Company’s refining margins will remain at unprofitable levels in 2013 and possibly beyond. In addition, due to a reduced outlook for refining margins and the persistence of weak industry fundamentals, management took substantial impairment charges amounting to euro 846 million before tax to align the book value of the Company’s refining plants to their lower values-in-use which impacted 2012 results of operations.

 

Eni’s results of operations are affected by changes in petrochemical margins

Eni’s margins on petrochemical products are affected by trends in demand for petrochemical products and movements in crude oil prices to which purchase costs of petroleum-based feedstock are indexed. Given the commoditized nature of Eni petrochemical products, it is difficult for the Company to transfer higher purchase costs for oil-based feedstock to selling prices to customers. In 2012, Eni’s petrochemicals business reported sharply higher operating losses down to euro 683 million due to unprofitable margins on basic petrochemicals products, mainly the margin on cracker, reflecting high oil-based feedstock costs and as demand for petrochemicals commodities plunged due to the economic downturn. A weak demand outlook and rising oil-based feedstock costs will continue to adversely affect Eni’s results of operations and liquidity in this business segment in 2013 and possibly beyond.

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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. We also may incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets we acquire. If the integration and financial risks connected to acquisitions materialize, our 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 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 our operations and damage our facilities. Furthermore, our operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to our operations and consequent loss or damage of properties and facilities.

 

Our crisis management systems may be ineffective

We have 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, we have crisis management plans and capability to deal with emergencies at every level of our operations. If we do not respond or are not seen to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

 

Exposure to financial risk

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

Our 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, we execute 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 deep changes occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid gas spot markets.

We are engaged in substantial trading and commercial activities in the physical markets. We also use 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. We also use financial instruments to manage foreign exchange and interest rate risk.

The Group’s approach to risk management includes identifying, evaluating and managing the financial risk using a top-down approach whereby the Board of Directors is responsible for establishing the Group risk management strategy and setting the maximum tolerable amounts of risk exposure. The Group’s chief executive officer is responsible for implementing the Group risk management strategy, while the Group’s chief financial officer is in charge of defining policies and tools to manage the Group’s exposure to financial risk, as well as monitoring and reporting activities. Various Groups’ 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 we believe we have 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.

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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. For further discussion on this issues see paragraph "Changes in crude oil and natural gas prices may adversely affect Eni’s results of operations" above and "Item 11 – Quantitative and qualitative disclosures about market risk".

On the other hand, the Group actively manages its exposure to commercial risk which arises when a contractual sale of a commodity has occurred or it is highly probable that it will occur and the Group aims at locking in the associated commercial margin. The Group’s risk management objectives are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. Also, as part of its risk management activities the Group enters trading activities in order to seek to profit from short-term market opportunities. The Group’s risk management has evolved particularly in response to the deep changes occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid markets to trade spot gas. To achieve those targets, Eni enters into commodity derivatives transactions in both commodity and financial markets:

(i)		to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. As tight correlation exists between such commodity derivatives transactions and underlying physical contracts, those derivatives are treated in accordance with hedging accounting in compliance with IAS 39, where possible; and
(ii)		to pursue speculative purposes such as altering the risk profile associated with a portfolio of contracts (purchase contracts, transport entitlements, storage capacity) or leveraging any pricing differences in the marketplace, seeking to increase margins on existing assets in case of favorable trends in the commodity pricing environment or seeking a potential profit based on expectations of trends in future prices.

Furthermore, the Company is implementing strategies of asset-backed trading in order to maximize the economic value of the flexibilities associated with its assets. Price risks related to asset backed trading activities are mitigated by the natural hedge granted by the assets’ availability.

These derivative contracts entered to 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 operating profit, particularly in the gas marketing business.

 

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 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.

 

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

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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 we are unable to access the financial markets, including due to our financial position or market sentiment as to our prospects, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment program may be impacted with a consequent effect on our growth rate, and may impact shareholder returns, including dividends or share price.

 

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 failure due to the severity of the economic and financial downturn. In Eni’s 2012 Consolidated Financial Statements, Eni accrued an allowance against doubtful accounts amounting to euro 164 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 middle and small businesses and retail customers who are particularly impacted by the current global financial and economic downturn.

 

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, and 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. See "Item 5 – Critical accounting estimates".

 

Digital infrastructure is an important part of maintaining our operations, and a breach of our 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 our digital infrastructure are critical to maintaining the availability of our business applications, including the reliable operation of technology in our various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. A breach of our digital security, either due to intentional actions or due to negligence, could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

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Our auditor, like all other independent registered public accounting firms operating in Italy, is 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 our annual reports filed with the 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 SEC rules and PCAOB professional standards.

Because our 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, our 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 our 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 the oil and gas exploration and production, gas marketing operations, power generation, chemicals, oilfield services and engineering industries. Eni has operations in 90 countries and 77,838 employees as of December 31, 2012.

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 Stefano Lucchini, 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 43 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq and Mozambique. In 2012, Eni average daily production amounted to 1,631 kBOE/d on an available-for-sale basis. As of December 31, 2012, Eni’s total proved reserves amounted to 7,166 mmBOE; proved reserves of subsidiaries totaled 5,667 mmBOE; Eni’s share of reserves of equity-accounted entities was 1,499 mmBOE. In 2012, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 35,881 million and operating profit of euro 18,451 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. Following the divestment of a stake of 30% less one share in Snam and deconsolidation of the regulated business of gas infrastructures in Italy effective in 2012, the Gas & Power segment includes only results and activities of the Marketing of gas and the International transport activity. In 2012, Eni’s worldwide sales of natural gas amounted to 95.32 BCM, including 2.73 BCM of gas sales made directly by Eni’s Exploration & Production segment in Europe and in the United States. Sales in Italy amounted to 34.78 BCM, while sales in European markets were 51.02 BCM that included 2.73 BCM of gas sold to certain importers to Italy.

Eni produces power and steam at a number of operated sites in Italy with a total installed capacity of 5.3 GW as of December 31, 2012. In 2012, sales of power totaled 42.58 TWh. In 2012, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 36,200 million and operating loss of euro 3,221 million.

Eni’s Refining & Marketing segment engages in crude oil supply, refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2012, processed volumes of crude oil and other feedstock amounted to 30.01 mmtonnes and sales of refined products were 48.33 mmtonnes, of which 23.79 mmtonnes in Italy. Retail sales of refined products at operated service stations amounted to 10.87 mmtonnes including Italy and the rest of Europe. In 2012, Eni’s retail market share in Italy through its "Eni" and "Agip" branded network of service stations was 31.2%. In 2012, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 62,656 million and operating loss of euro 1,303 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 this entity are reported within the Gas & Power segment with regard to the results recorded 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 2012, Eni sold 3.95 mmtonnes of chemical products. In 2012, Eni’s Chemical segment reported net sales from operations (including inter-segment sales) of euro 6,418 million and operating loss of euro 683 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 petrochemicals sectors, mainly in the field of performing large EPC (engineering, procurement and construction) 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 2012, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 12,771 million and operating profit of euro 1,433 million.

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

 

Strategy

Eni’s strategy is to grow the Company’s main businesses over both the medium and the long term, with improving profitability.

•

In the Exploration & Production business we plan to grow profitably oil and gas production and to fully replace produced reserves. We intend to boost returns by focusing on delivering the planned projects on time and on budget as well as increasing the share of operated production in the Company’s portfolio. Project operatorship enables the Company to better schedule and control project execution, expenditures and timely achievement of project milestones. In addition, the Company plans to seek cost efficiencies through greater deployment of proprietary technologies designed to maximize the rate of hydrocarbon recovery from reservoirs, the reduction of drilling costs and ongoing operational improvement. This growth strategy will be underpinned by continuing risk mitigation as we are exposed to political risks and operational risks relating to increasingly high complexity of our projects and environmental challenges. See "Item 3 – Risk factors – Risks associated with the exploration and production of oil and natural gas";

•		We intend to improve the profitability of our operations in the Gas & Power segment by renegotiating our long-term supply contracts in order to enhance the competitiveness of the Company’s gas offer and to mitigate the take-or-pay risk to our liquidity as we manage through the downturn. We plan to retain our market share in Italy and Europe by leveraging the expected improved costs in procurement and logistics and effective commercial actions. The return to profitability will be helped by developing LNG sales in international markets and optimizing margins by means of our trading activities;
•		Our priority in the Refining & Marketing segment is to restore profitability against the backdrop of weak industry fundamentals and an unfavorable trading environment. We plan to steep up cost reduction initiatives, energy saving and optimization of plant operations, in order to drive margin expansions. Management plans to implement selective capital projects for upgrading refinery complexity and securing the safety and reliability of our assets. In the marketing business in Italy we plan to enhance profitability through a number of initiatives for 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;
•		Our Engineering & Construction segment is expected to be adversely impacted by a slowdown in activities due to macroeconomic headwinds and lower profitability at newly acquired orders. However we believe that the business remains well positioned to return to revenue and profitability growth in the medium term leveraging on technologically-advanced assets and competencies in engineering and project management and execution of large and complex oil and gas developments;
•		In the Chemical segment, we plan to recover profitability by progressively reducing the exposure to loss-making commodity chemicals while at the same time developing innovative and niche productions. We intend to grow the green chemistry business leveraging on the ongoing project of converting the Porto Torres site in a modern plant for the manufacture of eco-compatible chemical products and to expand operations in international markets leveraging our technologies and know-how in the field of elastomers.

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. Over the next four years, Eni plans to execute a capital expenditure program amounting to euro 56.8 billion to support continuing organic growth in its segments, mainly the Exploration & Production which will absorb 83% of planned expenditures. That amount includes funds destined to joint venture projects and associates.

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For the full year 2013, management expects a capital budget in line with 2012 (in 2012 capital expenditure from continuing operations amounted to euro 12.76 billion, while expenditures incurred in joint venture initiatives and other investments amounted to euro 0.57 billion).

Eni plans to focus on preserving a balanced and well established financial structure. In 2012, following the divestment of a significant stake in Snam, which resulted in the exclusion of Snam’s net indebtedness from the Group’s consolidated financial statements, and the sale of part of the Group interest in Galp, Eni achieved a stronger balance sheet than in 2011, in line with the Company’s new business profile, more exposed to the Exploration & Production business. Looking forward, management will seek to maintain the ratio of net borrowings to total equity within a target range of 0.1-0.3 under the assumption of a Brent price scenario of 90 $/BBL flat in the next four year period and other trading assumptions, as well as the commitments of funding capital expenditure plans and implementing the Company’s progressive dividend policy (see "Item 5 – Operating and financial review and prospects – Management’s expectations of operations" and "Item 3 – Risk factors").

For fiscal year 2012, management plans to distribute a dividend of euro 1.08 a share subject to approval from the General Shareholders’ Meeting scheduled on May 10, 2013; the 2012 dividend represents a 4% increase from the previous year.

Further details on each business segment strategy are discussed throughout this item. 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".

In the next four-year period, Eni plans to make expenditures dedicated to technological research and innovation activities amounting to euro 1.1 billion. Management believes that technological developments may secure long-term competitive advantages to the Company. For more information on Research and Development activity see page 84.

 

Significant business and portfolio developments

The significant business and portfolio developments that occurred in 2012 and to date in 2013 were the following:

•		On October 15, 2012, following the satisfaction of certain conditions precedent, including, in particular, antitrust approval, we finalized the sale to Cassa Depositi e Prestiti SpA ("CDP"), an entity controlled by the Italian Ministry of Economy and Finance, of 1,013,619,522 ordinary shares of Snam SpA, corresponding to 30% less 1 share of the voting shares at a price of euro 3.47 per share, as provided for by the sale and purchase agreement dated June 15, 2012. The total consideration of euro 3,517 million was paid for 75% within the balance sheet date. The remaining 25% amounting to euro 879 million has been paid on February 28, 2013. The exclusion of Snam from the Group’s scope of consolidation effective from the last quarter of 2012 resulted in a reduction of financial debt by euro 12.45 billion. Prior to the divestment, Snam had already reimbursed intercompany loans via third-party financing. The transaction implements the provisions of Law No. 27/2012, pursuant to which Eni was mandated to divest the control in Snam in accordance with Legislative Decree No. 93/2011. Including the sale of a further 5% interest in Snam to institutional investors in July 2012, the residual interest of Eni in Snam equal to 20.2% of the share capital was accounted as a financial instrument because Eni cannot exercise the underlying voting rights pursuant to applicable laws and therefore cannot influence the financial and operating policy decisions of Snam. Furthermore, under applicable rules, Eni was mandated to divest any residual interest in Snam following loss of control on the entity. In January 2013, Eni finalized the divestment of a further portion of its interest in Snam with the placement of euro 1,250 million aggregate principal amount of senior, unsecured bonds, exchangeable into ordinary shares of Snam. The bonds have a maturity of 3 years and pay a coupon of 0.625% per year. The bonds will be exchangeable into Snam ordinary shares at an exchange price of euro 4.33 per Snam ordinary share, up to a maximum of approximately 288.7 million ordinary shares of Snam, corresponding to approximately 8.54% of the currently outstanding share capital of Snam.
•		On July 20, 2012, as part of the agreements signed on March 29, 2012 by Eni and the other relevant shareholders of the Portuguese company Galp Energia, Amorim Energia and Caixa Geral de Depòsitos SA, we sold a 5% interest in Galp Energia to Amorim Energia. The transaction covered 41.5 million shares at the price of euro 14.25 a share, for a total consideration of euro 582 million and a capital gain registered in profit of euro 288 million. Following the sale we ceased to be a party to the existing shareholders’ agreement governing Galp Energia and our residual interest of 28.34% was stated as a financial instrument.
•		The exploration campaign carried out in 2012 in the operated Area 4 offshore the Rovuma basin in Mozambique resulted in a significant discovery at the Mamba Gas complex. A total of 7 exploration and appraisal wells were drilled in the area and new, very large exploration opportunities have been identified at the Coral and Mamba North-East prospects, which are independent from Mamba’s structure. In December 2012, Eni signed an agreement with Anadarko Petroleum Corp establishing basic principles for the coordinated development of common offshore activities in Area 4, operated by Eni and Area 1, operated by Anadarko. Furthermore, we will jointly plan and construct onshore LNG liquefaction facilities in Northern Mozambique.

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•		On June 28, 2012, the international contractor companies of the final production sharing agreement of the giant Karachaganak gas-condensate field and the Republic of Kazakhstan closed a settlement agreement to all pending claims relating to the recovery of costs incurred to develop the field as well as minor tax issues. The contractor companies divested 10% of their rights and interest in the project to Kazakhstan’s KazMunaiGas for a $1 billion net cash consideration ($325 million being Eni’s share). From the effective date, Eni’s interest in the Karachaganak project has been reduced to 29.25% from the 32.5% previously held.
•		In 2012, Eni has launched a reorganization to integrate the supply activities of the Gas & Power and Refining & Marketing segments together with the trading, risk management and the wholesale activities of gas and LNG. This integration will allow Eni to capture opportunities from market trends and synergies in commodity risk management.
•		Eni signed a trilateral agreement with Korea Gas Corp and the Japanese company Chubu Electric Power Co for the sale of 28 loads of LNG corresponding to 1.7 mmtonnes of LNG in the 2013-2017 period.
•		In October 2012, the Green Refinery project was launched, which targets the conversion of the Venice plant into a "bio-refinery" to produce bio-fuels. The project will involve an estimated investment of approximately euro 100 million leveraging the Ecofining technology developed and licensed by Eni. Bio-fuel production will start from January 1, 2014 and will grow progressively as new facilities enter into operation. The new facilities to be built under the project will be completed in the first half of 2015.
•		In October 2012, Versalis, Eni’s chemical subsidiary, signed agreements to establish two joint ventures with major chemicals operators in South Korea and Malaysia to build and operate facilities for the production of elastomers incorporating Versalis proprietary technologies and know-how. These initiatives are part of Versalis strategy of international expansion in Asian markets with interesting growth prospect where Versalis can leverage on its technological and industrial leadership in elastomers.

•		In January 2013, Versalis signed a strategic partnership with Yulex for the manufacture of bio-rubber materials for consumer, medical and industrial markets and the construction of an industrial production complex in Southern Europe. The partnership will leverage on Yulex’s agronomical competencies and bio-rubber extraction technologies to boost Versalis’ green products portfolio.
•		In March 2013, Eni signed a Memorandum of Understanding with Pirelli related to a joint research project for the use of guayule-based natural rubber in tire production. On an exclusivity basis, Versalis will provide an innovative range of guayule-based natural rubber materials, while Pirelli will carry out trial tests to validate the performance of the materials for tire production on industrial basis.

In addition, Eni closed the following transactions:

•		In January 2013, Exploration and Production Sharing Contracts were signed with the Republic of Cyprus, for Blocks 2, 3 and 9 located in the Cypriot deep offshore portion of the Levantine Basin, which encompass an area of around 12,530 square kilometers, thus marking the entry of Eni in the Country. Eni was awarded the three blocks whilst leading the consortium with an 80% interest.
•		In December 2012, Eni signed an agreement with the Pakistani Authorities and the state oil and gas company OGDCL for the acquisition of 25% and the operatorship of the Indus Block G exploration license. The contractual area is located offshore in ultra-deep waters and covers approximately 7,500 square kilometers.
•		In August 2012, Eni and its partner Vitol signed a Memorandum of Understanding with the Government of Ghana and Ghana National Petroleum Corp for the development and marketing of gas reserves discovered in the Offshore Cape Three Points Block in the Tano Basin operated by Eni (47.22% interest).
•		In August 2012, Eni acquired a 25% interest in three blocks offshore Liberia covering an area of 8,145 square kilometers at a maximum water depth of 3,000 meters. The joint venture is operated by another international oil company. This operation marks Eni’s entry into Liberia.
•		In July 2012, Eni was awarded three product sharing contracts by the Government of Kenya. The contracts relate to the L-21, L-23 and L-24 exploration blocks which are located in the deep and ultra-deep waters of the Lamu Basin covering an area of approximately 36,000 square kilometers.
•		In June and July 2012, Eni acquired the operatorship (50% interest) of three exploration blocks located offshore Vietnam, in the Song Hong and Phu Khanh basins. The three blocks cover approximately 21,000 square kilometers of acreage. These basins are estimated to contain 10% of Vietnam’s hydrocarbon resources, mainly gas. In January 2013, Eni and the Vietnamese national oil company PetroVietnam signed a Memorandum of Understanding for the development of business opportunities in Vietnam and abroad.
•		In June 2012, Eni signed a Share Purchase Agreement with Ukrainian state-owned National Joint Stock Co, Nak Nadra Ukrayny, and Cadogan Petroleum Plc to acquire a 50.01% interest and operatorship of the Ukrainian company Westgasinvest Llc which currently holds subsoil rights to nine unconventional (shale) gas license areas in the Lviv Basin of Ukraine. These licenses cover approximately 3,800 square kilometers of acreage.

In 2012, capital expenditures of continuing operations amounted to euro 12,761 million, of which 89% related to Exploration & Production, Gas & Power and Refining & Marketing businesses, 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 622 million), in particular at the Sannazzaro refinery, as

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well as upgrading and rebranding of the refined product retail network (euro 220 million); and (iv) initiatives to improve flexibility of the combined cycle power plants (euro 131 million). There were no significant acquisitions in the year.

In 2011, capital expenditures of continuing operations amounted to euro 11,909 million, of which 88% related to Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily regarded: (i) the development of oil and gas reserves (euro 7,357 million) deployed mainly in Norway, Kazakhstan, Algeria, United States, Congo and Egypt, and exploration projects (euro 1,210 million) carried out mainly in Australia, Angola, Mozambique, Indonesia, Ghana, Egypt, Nigeria and Norway; (ii) projects aimed at improving the conversion capacity and flexibility of refineries, and at building and upgrading service stations in Italy and outside Italy (totaling euro 629 million); and (iii) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,090 million). There were no significant acquisitions in the year.

In 2010, capital expenditures of continuing operations amounted to euro 12,450 million, of which 78% related to Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 8,578 million) deployed mainly in Egypt, Kazakhstan, Congo, United States and Algeria, and exploration projects (euro 1,012 million) carried out mainly in Angola, Nigeria, United States, Indonesia and Norway; (ii) projects aimed at improving the conversion capacity and flexibility of refineries, and at building and upgrading service stations in Italy and outside Italy (totaling euro 692 million); and (iii) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,552 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 43 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq and Mozambique. In 2012, Eni average daily production amounted to 1,631 kBOE/d on an available-for-sale basis. As of December 31, 2012, Eni’s total proved reserves amounted to 7,166 mmBOE; proved reserves of subsidiaries totaled 5,667 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 1,499 mmBOE.

Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth leveraging on its strong asset base and market position in a number of core mineral basins. We plan to achieve a production growth rate of more than 4% on average in the 2013-2016 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 rate by continuing development activities and new project start-ups in the main areas of operations including North Africa, Sub-Saharan Africa, Venezuela, the Barents Sea, the Yamal Peninsula, Kazakhstan, Iraq and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. 65% of these new projects have already been sanctioned and management plans to reach 90% by the end of 2013.

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

Management plans to invest euro 39.9 billion to develop reserves over the next four years. An important share of these expenditures will be allocated to certain development projects which will support the Company’s long-term production plateau, in particular we plan to start developing the recent gas discovery offshore Mozambique and to progress large and complex projects in the Barents Sea, Nigeria and Indonesia. We are also planning to maintain a prevailing share of projects regulated by production sharing agreements in our portfolio; this will shorten the cost recovery in an environment of high crude oil prices.

Approximately euro 1.8 billion will be spent to execute development projects through equity-accounted entities.

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Exploration projects will attract some euro 5.5 billion to appraise the latest discoveries made by the Company and to support continuing reserve replacement over the next four years. The most important amounts of exploration expenses will be incurred in Angola, Russia, United States, Nigeria, Egypt, Norway and Indonesia; important resources will be dedicated to explore new areas (Kenya, Vietnam, Ukraine and Cyprus) and on unconventional plays. Management plans to achieve a balance between exploration projects in conventional fields versus projects in high risk/high reward basins.

Management believes that in the 2013-2016 period Eni’s exploration and production activities will retain significant risks relating to our strong presence in countries which we believe to be politically less stable than OECD Countries and our exposure to complex projects because they are conducted in harsh, remote and environmentally-sensitive areas (Arctic, Gulf of Mexico, deep offshore, etc.). Management plans to mitigate those risks by expanding the geographic reach of our operations and continuing deployment of the Eni cooperation model with host countries based on the commitment to maximize the benefits delivered to local communities by our upstream activities and invest in initiatives that improve socio-economic standards over the long term (access to energy, education, health). Furthermore Eni intends to minimize financial exposure in countries with political risk through well-designed agreements and a selected plan of cash-outs for each project.

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 acknowledge that our results of operations and production levels for the year have been adversely impacted by delays and cost overruns at a number of projects. We plan to mitigate those risks in the future 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 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. We expect that costs to develop and operate fields will increase in the next years due to sector-specific inflation, and growing complexity of new projects. We plan to counteract those cost increases by leveraging on cost efficiencies associated with: (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; and (iii) applying our technologies which we believe can reduce drilling and completion costs.

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.

Eni will pursue further growth options by developing unconventional plays, gas-to-LNG projects and integrated gas projects. Finally, we intend to optimize our portfolio of development properties by focusing on areas where our presence is well established, and divesting non-strategic or marginal assets.

For the year 2013, management plans to spend approximately euro 11 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.

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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 reserve 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 previous booking of reserves due to analysis of new information.

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

 

Reserves governance

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

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

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Division Reserves Evaluators (DRE), 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, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, long-term 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

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to third party evaluators. In 2012, Ryder Scott Co and DeGolyer and MacNaughton provided an independent evaluation of approximately 33% of Eni’s total proved reserves at December 31, 2012⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation⁵.

In the 2010-2012 period, 92% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2012, the principal Eni properties not subjected to independent evaluation in the last three years were Bouri and Bu Attifel (Libya) and M’Boundi (Congo).

 

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, 2012, 2011 and 2010. Net proved reserves are set out in more detail under the heading "Supplemental oil and gas information" on page F-116.

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, 2010		724		601		2,096		1,133		1,126		295		230		127		6,332
Developed		554		405		1,215		812		543		139		141		117		3,926
Undeveloped		170		196		881		321		583		156		89		10		2,406
Year ended Dec. 31, 2011		707		630		2,031		1,021		950		230		238		133		5,940
Developed		540		374		1,175		742		482		129		162		112		3,716
Undeveloped		167		256		856		279		468		101		76		21		2,224
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
Equity-accounted entities
Year ended Dec. 31, 2010						23		28				317		143				511
Developed						22		5				43		26				96
Undeveloped						1		23				274		117				415
Year ended Dec. 31, 2011						21		83				656		386				1,146
Developed						19		4				5		26				54
Undeveloped						2		79				651		360				1,092
Year ended Dec. 31, 2012						20		81				668		730				1,499
Developed						20						82		20				122
Undeveloped								81				586		710				1,377
Consolidated subsidiaries
and equity-accounted entities
Year ended Dec. 31, 2010		724		601		2,119		1,161		1,126		612		373		127		6,843
Developed		554		405		1,237		817		543		182		167		117		4,022
Undeveloped		170		196		882		344		583		430		206		10		2,821
Year ended Dec. 31, 2011		707		630		2,052		1,104		950		886		624		133		7,086
Developed		540		374		1,194		746		482		134		188		112		3,770
Undeveloped		167		256		858		358		468		752		436		21		3,316
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

 

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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, 2010		248		349		978		750		788		139		134		29		3,415
Developed		183		207		656		533		251		39		62		20		1,951
Undeveloped		65		142		322		217		537		100		72		9		1,464
Year ended Dec. 31, 2011		259		372		917		670		653		106		132		25		3,134
Developed		184		195		622		483		215		34		92		25		1,850
Undeveloped		75		177		295		187		438		72		40				1,284
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
Equity-accounted entities
Year ended Dec. 31, 2010						19		6				44		139				208
Developed						18		4				5		25				52
Undeveloped						1		2				39		114				156
Year ended Dec. 31, 2011						17		22				110		151				300
Developed						16		4						25				45
Undeveloped						1		18				110		126				255
Year ended Dec. 31, 2012						17		16				114		119				266
Developed						17						8		19				44
Undeveloped								16				106		100				222
Consolidated subsidiaries
and equity-accounted entities
Year ended Dec. 31, 2010		248		349		997		756		788		183		273		29		3,623
Developed		183		207		674		537		251		44		87		20		2,003
Undeveloped		65		142		323		219		537		139		186		9		1,620
Year ended Dec. 31, 2011		259		372		934		692		653		216		283		25		3,434
Developed		184		195		638		487		215		34		117		25		1,895
Undeveloped		75		177		296		205		438		182		166				1,539
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

 

 

 

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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, 2010		2,644		1,401		6,207		2,127		1,874		871		530		544		16,198
Developed		2,061		1,103		3,100		1,550		1,621		560		431		539		10,965
Undeveloped		583		298		3,107		577		253		311		99		5		5,233
Year ended Dec. 31, 2011		2,491		1,425		6,190		1,949		1,648		685		590		604		15,582
Developed		1,977		995		3,070		1,437		1,480		528		385		491		10,363
Undeveloped		514		430		3,120		512		168		157		205		113		5,219
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
Equity-accounted entities
Year ended Dec. 31, 2010						24		118				1,520		22				1,684
Developed						22		4				214		6				246
Undeveloped						2		114				1,306		16				1,438
Year ended Dec. 31, 2011				2		20		338				3,033		1,307				4,700
Developed						17		4				24		8				53
Undeveloped				2		3		334				3,009		1,299				4,647
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
Consolidated subsidiaries
and equity-accounted entities
Year ended Dec. 31, 2010		2,644		1,401		6,231		2,245		1,874		2,391		552		544		17,882
Developed		2,061		1,103		3,122		1,554		1,621		774		437		539		11,211
Undeveloped		583		298		3,109		691		253		1,617		115		5		6,671
Year ended Dec. 31, 2011		2,491		1,427		6,210		2,287		1,648		3,718		1,897		604		20,282
Developed		1,977		995		3,087		1,441		1,480		552		393		491		10,416
Undeveloped		514		432		3,123		846		168		3,166		1,504		113		9,866
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

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 648 mmBOE as of December 31, 2012 (647 and 683 mmBOE as of December 31, 2011 and 2010, respectively). Said volumes are not included in reserves volumes shown in the table herein.

	Subsidiaries		Equity-accounted entities

	2010		2011		2012		2010		2011		2012

Additions to proved reserves		776			176			337			158			644			366
of which purchases and sales of reserves-in-place		(12	)		(7	)		(212	)								(38	)
Production for the year		(653	)		(568	)		(610	)		(9	)		(9	)		(13	)

	Subsidiaries and equity-accounted entities

	2010		2011		2012

Proved reserves replacement ratio of subsidiaries and equity-accounted entities		125		142		107

Eni’s proved reserves as of December 31, 2012 totaled 7,166 mmBOE (liquids 3,350 mmBBL; natural gas 20,957 BCF) and included the impact of the gas conversion factor update (40 mmBOE). Eni’s proved reserves reported an increase of 80 mmBOE, or 1.1%, from December 31, 2011. All sources additions to proved reserves booked in 2012 were 703 mmBOE, of which 337 mmBOE came from Eni’s subsidiaries and 366 mmBOE from Eni’s share of equity-accounted entities.

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In spite of stable Brent prices at $111 per barrel in 2012 (also $111 in 2011), all sources additions were adversely affected by the unfavorable movements in oil and gas prices on reserves entitlements in certain PSAs and service contracts and in the economics of marginal productions (down 62 mmBOE).

The methods (or technologies) used in the Eni’s proved reserves assessment 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 reserves replacement ratio achieved by Eni’s subsidiaries and equity-accounted entities was 107% in 2012 (142% in 2011 and 125% in 2010). The ratio did not include the impact associated with adoption of a new conversion factor of natural gas to barrel-of-oil equivalent on the initial balances of proved reserves as of January 1, 2012 estimated at 40 mmBOE as management believes that change did not pertain to the Company’s reserve performance for the year. The reserves replacement ratio was calculated by dividing additions to proved reserves by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities - Oil & Gas (Topic 932) (see the supplemental oil and gas information in "Item 18 – 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 additions. Management considers the reserves replacement ratio to be an important indicator of the Company’s ability to sustain its growth perspectives. 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 and geological and environmental risks. Specifically, in recent years Eni’s reserves replacement ratio has been affected by the impact of changes in hydrocarbon prices on reserves entitlements in the Company’s Production Sharing Agreements and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of field reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference hydrocarbon prices used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures. See "Item 3 – Risks associated with the exploration and production of oil and natural gas - Uncertainties in estimates of oil and natural gas reserves".

The average reserves life index of Eni’s proved reserves was 11.5 years as of December 31, 2012 (12.3 years as of December 31, 2011) which included reserves of both subsidiaries and equity-accounted entities.

 

Eni’s subsidiaries

Eni’s subsidiaries added 337 mmBOE of proved oil and gas reserves in 2012 (176 mmBOE in 2011). This comprised 266 mmBBL of liquids and 224 BCF of natural gas. Additions to proved reserves derived from: (i) revisions of previous estimates were 321 mmBOE mainly reported in Kazakhstan, Nigeria and Egypt; (ii) extensions, discoveries and others were 200 mmBOE, with major increases booked in Kazakhstan and Angola; (iii) improved recovery were 28 mmBOE mainly reported in Algeria and Nigeria; and (iv) sales of mineral-in-place were 213 mmBOE and resulted from the disposals of Snam (in particular the divestment of 139 mmBOE of gas storage in Italy) and other non-strategic assets as well as the change of the working interest in the Karachaganak field (48 mmBOE).

 

Eni’s share of equity-accounted entities

Eni reported an increase of 366 mmBOE in its share of equity-accounted entities’ proved oil and gas reserves in 2012 (644 mmBOE in 2011). This comprised mainly 2,100 BCF of natural gas. Additions to proved reserves derived from: (i) revisions of previous estimates were 254 mmBOE mainly reported in Venezuela; (ii) extensions, discoveries and other factors were 149 mmBOE, with major increases booked in Venezuela and Russia; and (iii) sales of mineral-in-place were 38 mmBOE resulting from the divestment of Galp.

 

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2012 totaled 3,650 mmBOE (including the impact of the gas conversion factor update equal to 20 mmBOE). At year end, proved undeveloped reserves of liquids amounted to 1,544 mmBBL, mainly concentrated in Africa and Kazakhstan. Proved undeveloped reserves of natural gas amounted to

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11,568 BCF, mainly located in Africa, Russia and Venezuela. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,322 mmBBL of liquids and 5,225 BCF of natural gas.

In 2012, total proved undeveloped reserves increased by 334 mmBOE due to new projects sanctions mainly in Venezuela, Angola and Congo (approximately 438 mmBOE) as well as due to upwards and downwards revisions mainly related to contractual and technical revisions, price effect and portfolio operations.

During 2012, Eni converted 227 mmBOE of proved undeveloped reserves to proved developed reserves due to development activities, production start-ups and revisions. The main reclassifications to proved developed reserves are related to the following fields/projects: Samburgskoye (Russia), CAFC and MLE (Algeria), Seth (Egypt), Marulk and Tyrihans (Norway), M’Boundi (Congo), Clochas (Angola), Zubair (Iraq) and Nikaitchuq (USA).

In 2012, capital expenditure amounted to approximately euro 1.9 billion and was made to progress the development of proved undeveloped reserves.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 1.1 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 0.6 BBOE) where development activities are progressing and production start-up is targeted by the end of the first half 2013. Such PUD reserves will be produced within the limits of the oil processing capacity that is planned to be available at end of the ongoing developing phase (Phase 1 or Experimental Program). For more details regarding this project please refer to part 1, Item 4, page 54, where the project is disclosed; (ii) some Libyan gas fields (0.27 BBOE) where development completion and production start-up are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields, which are expected to be put in production over the next several years; and (iii) other projects including a gas asset located in Siberia where development activities are progressing and we are targeting production start-up in the short-to-medium term (see also our discussion under the "Item 3 – Risk factors" section about risks associated with oil and gas development projects on page 9).

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 431 mmBOE from producing assets located mainly in Australia, Egypt, Libya, Nigeria, Norway and Russia.

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 72% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2012.

 

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

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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 2012, oil and natural gas production available for sale averaged 1,631 kBOE/d (1,523 kBOE/d in 2011). Production for the year expressed in barrel-of-oil equivalent was calculated assuming a natural gas conversion factor which was updated to 5,492 CF of gas equaling 1 barrel of oil. On a comparable basis, i.e. when excluding the effect of updating the gas conversion factor, production reported an increase of 7% for the full year. The performance was driven by an ongoing recovery in Libyan production and continuing field start-up and ramp-up mainly in Russia and Australia as well as increased production in Iraq. These positives were partly offset by the temporary shutdown of the Elgin/Franklin field (Eni’s interest 21.87%) in the UK due to a gas leak, losses in Nigeria due to force majeure and mature field declines.

Liquids production (882 kBBL/d) increased by 37 kBBL/d, or 4.4%, due the ramp-up of Libyan production and growth registered mainly in: (i) Australia, due to the ramp-up of the Kitan field (Eni operator with a 40% interest); and (ii) Iraq, due to increased production at the Zubair field (Eni’s interest 32.8%). Production declined in the United Kingdom and Nigeria following the driver described above and mature field declines, mainly in Angola.

Natural gas production (4,118 mmCF/d) increased by 355 mmCF/d, or 9.4%. The performance was driven by the ramp-up of Libyan production and start-ups in: (i) Samburgskoye field (Eni’s interest 29.4%) in Russia, by means of start-up of the first and the second train with an expected production level of 95 kBOE/d (28 kBOE/d net to Eni); and (ii) Seth field in the Ras el Barr offshore concession (Eni’s interest 50%) in Egypt. Production plateau is expected at approximately 170 mmCF/d (approximately 11 kBOE/d net to Eni). These positives were partly offset by lower production in the United Kingdom and facilities downtime in the United States.

Oil and gas production sold amounted to 598.7 mmBOE. The 23.9 mmBOE difference over production (622.6 mmBOE) reflected mainly volumes of natural gas consumed in operations (25.5 mmBOE).

Approximately 57% of liquids production sold (325.4 mmBBL) was destined to Eni’s Refining & Marketing Division (of which 25% was processed in Eni’s refineries); about 29% of natural gas production sold (1,501 BCF) was destined to Eni’s Gas & Power Division.

The tables below provide Eni subsidiaries and its equity-accounted entities’ production, by final product sold of liquids and natural gas by geographical area of each of the last three fiscal years.

LIQUIDS PRODUCTION

		2010		2011		2012

(kBBL/d)

Eni consolidated subsidiaries

Eni share of equity-accounted entities

Eni consolidated subsidiaries

Eni share of equity-accounted entities

Eni consolidated subsidiaries

Eni share of equity-accounted entities

Italy		61				64				63
Rest of Europe		121				120				95
North Africa		297		4		204		5		267		4
Sub-Saharan Africa		318		3		275		3		245		2
Kazakhstan		65				64				61
Rest of Asia		47		1		33		1		41		3
Americas		60		11		55		10		72		11
Australia and Oceania		9				11				18
		978		19		826		19		862		20

 

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NATURAL GAS PRODUCTION AVAILABLE FOR SALE ⁽¹⁾

		2010		2011		2012

(mmCF/d)

Eni consolidated subsidiaries

Eni share of equity-accounted entities

Eni consolidated subsidiaries

Eni share of equity-accounted entities

Eni consolidated subsidiaries

Eni share of equity-accounted entities

Italy		648				648				667
Rest of Europe		517				498				421
North Africa		1,556		3		1,165		4		1,589		3
Sub-Saharan Africa		365				422				444
Kazakhstan		221				212				202
Rest of Asia		412		24		378		20		355		68
Americas		385				323				273
Australia and Oceania		91				93				96
		4,195		27		3,739		24		4,047		71

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(1)

It excludes production volumes of natural gas consumed in operations. Said volumes were 383, 321 and 318 mmCF/d in 2012, 2011 and 2010, respectively.

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, 28 kBOE/d and 105 kBOE/d in 2012, 2011 and 2010, respectively.

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

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2010
Consolidated subsidiaries
Oil and condensate, per BBL		72.19		67.26		70.96		78.23		66.74		75.20		72.84		73.00		72.95
Natural gas, per kCF		8.71		7.40		6.87		1.87		0.49		4.35		4.70		7.40		6.01
Average production cost, per BOE		9.42		9.42		5.63		15.19		6.40		5.62		8.15		9.75		8.89
Equity-accounted entities
Oil and condensates, per BBL						16.09		77.78				57.05		71.70				58.86
Natural gas, per kCF												9.87						8.73
Average production cost, per BOE						13.53		9.73				5.05		27.78				17.45
2011
Consolidated subsidiaries
Oil and condensates, per BBL		101.20		97.56		97.63		110.09		98.68		101.09		101.15		98.05		102.47
Natural gas, per kCF		11.56		9.72		5.95		1.97		0.57		5.27		4.02		7.38		6.44
Average production cost, per BOE		11.17		10.31		5.96		18.32		6.37		8.28		12.38		12.14		10.86
Equity-accounted entities
Oil and condensates, per BBL				97.18		17.98		108.92				74.98		93.03				84.78
Natural gas, per kCF				10.65		5.39						15.68						13.89
Average production cost, per BOE				26.91		10.82		11.43				7.68		46.77				26.76
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

 

Development activities

In 2012, a total of 351 development wells were drilled (163.6 of which represented Eni’s share) as compared to 407 development wells drilled in 2011 (186.1 of which represented Eni’s share) and 399 development wells drilled in 2010 (178 of which represented Eni’s share). The drilling of 109 wells (36.9 of which represented Eni’s share) is currently underway.

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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, 2012. 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

		2010		2011		2012		2012

(units)

Productive

Dry

Productive

Dry

Productive

Dry

Gross

Net

Italy		23.9		1.0		25.3				18.0		1.0		3.0		2.6
Rest of Europe		2.9		0.2		3.3		0.3		2.9		0.6		9.0		1.8
North Africa		44.3		0.3		55.9		1.1		46.0		1.6		19.0		8.1
Sub-Saharan Africa		28.0		2.5		28.2		1.0		27.4		0.3		19.0		4.4
Kazakhstan		1.8				1.3				1.4				16.0		2.9
Rest of Asia		41.7		1.8		39.2		2.5		41.2		0.1		36.0		14.2
Americas		27.6		0.5		27.6				23.1				7.0		2.9
Australia and Oceania		1.5				0.4
Total including equity-accounted entities		171.7		6.3		181.2		4.9		160.0		3.6		109.0		36.9

 

Exploration activities

In 2012, a total of 60 new exploratory wells were drilled (34.1 of which represented Eni’s share), which includes drilled exploratory wells that have been suspended pending further evaluation, as compared to 56 exploratory wells drilled in 2011 (28 of which represented Eni’s share) and 47 exploratory wells drilled in 2010 (23.8 of which represented Eni’s share).

The overall commercial success rate was 40% (40.8% net to Eni) as compared to 42% (38.6% net to Eni) and 41% (39% net to Eni) in 2011 and 2010, 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, 2012. 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 (a)

		2010		2011		2012		2012

(units)

Productive

Dry

Productive

Dry

Productive

Dry

Gross

Net

Italy				0.5						1.0				5.0		3.4
Rest of Europe		1.7		1.1		0.3		0.7		1.0		1.0		19.0		7.2
North Africa		9.3		8.1		6.2		3.4		6.3		11.3		17.0		11.7
Sub-Saharan Africa		2.3		4.7		0.6		2.6		4.5		5.1		57.0		24.2
Kazakhstan												0.8		8.0		1.4
Rest of Asia		1.0		2.8		0.2		7.6		0.5		0.6		27.0		11.2
Americas				6.3		2.5						0.1		10.0		2.4
Australia and Oceania		1.0		0.4				1.4				0.4		1.0		0.5
Total including equity-accounted entities		15.3		23.9		9.8		15.7		13.3		19.3		144.0		62.0

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(a)

Includes temporary suspended wells pending further evaluation.

 

Oil and gas properties, operations and acreage

As of December 31, 2012, Eni’s mineral right portfolio consisted of 1,072 exclusive or shared rights for exploration and development in 43 countries on five continents for a total acreage of 251,170 square kilometers net to Eni of which developed acreage of 40,939 square kilometers and undeveloped acreage of 210,231 square kilometers.

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In 2012, changes in total net acreage mainly derived from: (i) new leases mainly in China, Indonesia, Kenya, Liberia, Norway, Pakistan and Ukraine for a total acreage of approximately 51,000 square kilometers; (ii) partial relinquishment or interest reduction in Algeria, Australia, Egypt, India, Ireland, Nigeria, Timor Leste, the United States, the United Kingdom and Pakistan covering an acreage of approximately 22,000 square kilometers; and (iii) the total relinquishment of leases in Brazil and Mali for a total acreage of approximately 22,000 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, 2012. A gross acreage is one in which Eni owns a working interest.

	December 31, 2011		December 31, 2012

Total net acreage (a)

Number of interests

Gross developed (b) acreage (a)

Gross undeveloped acreage (a)

Total gross acreage (a)

Net developed (b) acreage (a)

Net undeveloped acreage (a)

Total net acreage (a)

EUROPE		26,023		288		17,191		27,199		44,390		11,150		16,273		27,423
Italy		16,872		151		10,847		11,438		22,285		9,011		8,545		17,556
Rest of Europe		9,151		137		6,344		15,761		22,105		2,139		7,728		9,867
Croatia		987		2		1,975				1,975		987				987
Norway		2,335		52		2,264		6,226		8,490		346		2,330		2,676
Poland		1,968		3				1,968		1,968				1,968		1,968
United Kingdom		1,014		65		2,055		647		2,702		776		138		914
Ukraine		45		12		50		3,840		3,890		30		1,911		1,941
Other Countries		2,802		3				3,080		3,080				1,381		1,381
AFRICA		137,220		287		64,075		192,079		256,154		19,891		122,905		142,796
North Africa		30,532		119		31,988		17,691		49,679		14,066		7,324		21,390
Algeria		9,065		41		2,640		1,158		3,798		1,071		161		1,232
Egypt		5,898		57		4,937		7,845		12,782		1,771		2,819		4,590
Libya		13,295		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		106,688		168		32,087		174,388		206,475		5,825		115,581		121,406
Angola		6,218		78		4,804		20,037		24,841		636		5,443		6,079
Congo		5,020		26		1,835		7,681		9,516		1,027		4,008		5,035
Democratic Republic of Congo		263		1				478		478				263		263
Gabon		7,615		6				7,615		7,615				7,615		7,615
Ghana		1,885		2				5,144		5,144				1,885		1,885
Kenya				3				35,724		35,724				35,724		35,724
Liberia				3				8,145		8,145				2,036		2,036
Mozambique		9,502		1				12,956		12,956				9,069		9,069
Nigeria		8,491		41		25,448		10,838		36,286		4,162		3,484		7,646
Togo		6,192		2				6,192		6,192				6,192		6,192
Other Countries		61,502		5				59,578		59,578				39,862		39,862
ASIA		55,284		73		17,126		101,554		118,680		5,778		52,264		58,042
Kazakhstan		880		6		324		4,609		4,933		95		774		869
Rest of Asia		54,404		67		16,802		96,945		113,747		5,683		51,490		57,173
China		5,365		11		200		10,456		10,656		39		10,456		10,495
India		9,206		11		206		16,546		16,752		109		6,099		6,208
Indonesia		17,719		13		1,735		28,490		30,225		656		19,078		19,734
Iran		820		4		1,456				1,456		820				820
Iraq		352		1		1,074				1,074		352				352
Pakistan		9,289		19		8,430		20,210		28,640		2,478		8,055		10,533
Russia		1,469		4		3,501		1,495		4,996		1,029		440		1,469
Timor Leste		6,740		2				5,148		5,148				4,118		4,118
Turkmenistan		200		1		200				200		200				200
Other Countries		3,244		1				14,600		14,600				3,244		3,244
AMERICAS		10,209		409		4,571		14,180		18,751		3,074		6,001		9,075
Brazil		795
Ecuador		1,985		1		1,985				1,985		1,985				1,985
Trinidad & Tobago		66		1		382				382		66				66
United States		5,123		393		1,826		6,206		8,032		925		3,707		4,632
Venezuela		914		6		378		2,427		2,805		98		968		1,066
Other Countries		1,326		8				5,547		5,547				1,326		1,326
AUSTRALIA AND OCEANIA		25,685		15		1,980		23,102		25,082		1,046		12,788		13,834
Australia		25,647		14		1,980		22,338		24,318		1,046		12,750		13,796
Other Countries		38		1				764		764				38		38
Total		254,421		1,072		104,943		358,114		463,057		40,939		210,231		251,170

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

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The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2012. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same bore hole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 8,512 (3,213.1 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, 2012 ^(a)

		Oil wells		Natural gas wells

(units)		Gross		Net		Gross		Net

Italy		242.0		196.1		621.0		536.6
Rest of Europe		460.0		69.7		180.0		89.2
North Africa		1,447.0		702.3		154.0		59.2
Sub-Saharan Africa		2,858.0		542.2		383.0		27.6
Kazakhstan		102.0		29.1
Rest of Asia		642.0		404.1		889.0		336.6
Americas		169.0		90.5		344.0		122.8
Australia and Oceania		7.0		3.8		14.0		3.3
Total including equity-accounted entities		5,927.0		2,037.8		2,585.0		1,175.3

---

(a)

Multiple completion wells included above: approximately 2,203 (747.7 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 2012, Eni’s oil and gas production amounted to 184 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 61 operated offshore).

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The Adriatic and Ionian Sea represents Eni’s main production area for gas, accounting for 50% of Eni’s domestic production in 2012. 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 fed by 26 production wells representing 30% of Eni’s production in Italy and is treated by the Viggiano oil center. Oil produced is carried to Eni’s refinery in Taranto via a 136-kilometer long pipeline. Gas produced is delivered to the national grid system. Other main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso in Sicily, which in 2012 accounted for approximately 10% of Eni’s production in Italy. The development activity for the year was focused on maintenance and optimization of producing fields and existing facilities. In the Val d’Agri concession the development plan is ongoing as agreed with the Basilicata Region in 1998. The construction of a new gas treatment unit started at the end of 2012, targeting a production capacity of 104 kBBL/d. Other development activities concerned: (i) production optimization at the Antonella, Barbara, Basil, Brenda, Gela, Naomi & Pandora and Porto Corsini

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fields; (ii) upgrading of compression and hydrocarbon treatment facilities at the production platform of the Barbara field; and (iii) linkage to the existing production facilities of the Colle Sciarra well (Eni’s interest 50%).

In the medium-term, management expects a stable production plateau 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 UK. In 2012, the Rest of Europe accounted for 11% of Eni’s total worldwide production of oil and natural gas.

Croatia. Eni has been present in Croatia since 1996. In 2012, Eni’s production of natural gas averaged 23 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula.

Exploration and production activities in Croatia are regulated by PSAs.

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

Cyprus. In January 2013, Exploration and Production Sharing Contracts were signed with the Republic of Cyprus, for Blocks 2, 3 and 9 located in the Cypriot deep offshore portion of the Levantine Basin. The new acreage encompasses an area of around 12,530 square kilometers, and marks the entry of Eni in the Country. Eni was awarded the three blocks as operator with an 80% interest.

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 123 kBOE/d in 2012.

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

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14.9%), Tyrihans (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2012 accounted for 78% of Eni’s production in Norway.

Eni holds interests in 5 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 2012 produced approximately 27 kBOE/d net to Eni and accounted for 22% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension. Activities were performed during the year to maintain and optimize the production rate by means of infilling wells, the development of the South Area extension, upgrading of existing facilities and optimization of water injection.

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. The project is progressing; the production start-up is expected in 2014 with the production plateau of 100 kBBL/d.

In April 2012, Eni signed with Solveig Gas Norway AS an agreement for the sale of its 1.43% interest in the Gassled JV, a network of gas pipelines and terminals for natural gas transportation. The sale was closed at the end of 2012 with a consideration amount of approximately euro 130 million.

Eni was awarded four exploration licenses: (i) the PL091D license (Eni’s interest 7.9%) in the Norwegian Sea; and (ii) PL697 (Eni operator with a 65% interest), the PL657 (Eni operator with an 80% interest) and the PL696 license (Eni’s interest 30%) in the Barents Sea.

Exploration activities yielded positive results in the: (i) PL532 license (Eni’s interest 30%) with the appraisal campaign for the assessment of mineral potential of the oil and gas Skrugard discovery and the new Havis oil and gas discovery. Both fields are planned to be put in production by means of a fast-track synergic development; and (ii) PL 533 license (Eni’s interest 40%) with the gas and condensate Salina discovery.

Ukraine. In June 2012, Eni signed a Share Purchase Agreement with Ukrainian state-owned National Joint Stock Co, Nak Nadra Ukrayny, and Cadogan Petroleum Plc to acquire a 50.01% interest and operatorship of the Ukrainian company Westgasinvest Llc which currently holds subsoil rights to nine unconventional (shale) gas license areas in the Lviv Basin of Ukraine. These licenses cover approximately 3,800 square kilometers of acreage.

United Kingdom. Eni has been present in the UK since 1964. Eni’s activities are carried out in the British section of the North Sea and the Irish Sea. In 2012, Eni’s net production of oil and gas averaged 44 kBOE/d. Exploration and production activities in the UK are regulated by concession contracts. Eni holds interests in 13 production areas; in 1 of these, the Hewett Area, Eni is operator with an 89% interest. The other main fields are Elgin/Franklin (Eni’s interest 21.87%), West Franklin (Eni’s interest 21.87%), Liverpool Bay (Eni’s interest 53.9%), J Block Area (Eni’s interest 33%), Flotta Catchment Area (Eni’s interest 20%) and MacCulloch (Eni’s interest 40%), which in 2012 accounted for 91% of Eni’s production in the UK. In 2012, Eni signed an agreement for the divestment of the following development/production assets: Mariner (Eni’s interest 20%), Andrew (Eni’s interest 16.21%), Kinnoul (Eni’s interest 16.67%), Flotta Catchment Area (Eni’s interest 20%) and a few minor ones. At the end of the year the sale of Mariner was completed. The completion date for the other assets is expected in 2013. Main development activities in 2012 were: (i) the construction of production and treatment facilities for the gas and liquids Jasmine field (Eni’s interest 33%). Start-up is expected in 2013; and (ii) the construction of production platforms and linkage to nearby treatment facilities for the West Franklin field (Eni’s interest 21.9%). During 2012, a gas leak occurred on a well at the Elgin/Franklin field. Production for the field operated by an international oil company was stopped at the end of March.

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Production resumed during the first quarter of 2013. The impact on 2012 production was estimated at approximately 7 mmBBL.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2012, North Africa accounted for 34% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2012, Eni’s oil and gas production averaged 71 kBOE/d. Operated and participated activities are located in the Bir Rebaa area in the South-Eastern Desert: (i) Blocks 403a/d (Eni’s interest 100%); (ii) Block Rom North (Eni’s interest 35%); (iii) Blocks 401a/402a (Eni’s interest 55%); (iv) Blocks 403 (Eni’s interest 50%) and 404 (Eni’s interest 12.25%, non operated); (v) Block 212 (Eni’s interest 22.38%) with discoveries already made; and (vi) Blocks 208 (Eni’s interest 12.25%, non operated) and 405b (Eni’s interest 75%) with ongoing development activities. Exploration and production activities in Algeria are regulated by Production Sharing Agreements and concession contracts. Production in Block 403a/d and Rom North comes mainly from the HBN and Rom and satellite fields and represented approximately 21% of Eni’s production in Algeria in 2012. Zero gas flaring, in compliance with applicable country law, had been achieved in 2012. Production in Blocks 401a/402a comes mainly from the ROD/SFNE and satellite fields and accounted for approximately 24% of Eni’s production in Algeria in 2012. The main fields in Block 403 are BRN, BRW and BRSW which accounted for approximately 18% of Eni’s production in Algeria in 2012. The main fields in Block 404 are HBN and HBNS and satellites which accounted for approximately 37% of Eni’s production in Algeria in 2012.

In 2013, production started at the MLE field part of the MLE-CAFC integrated project in Block 405b (Eni’s interest 75%). A natural gas treatment plant started operations with a gross production and export capacity of approximately 320 mmCF/d of gas, 15 kBBL/d of oil and condensates and 12 kBBL/d of GPL. Four export pipelines link it to the national grid system. Development activities progressed at the CAFC oil project. The project includes the construction of an oil treatment plant and synergies with the MLE production facilities. Production start-up is expected in 2015. The MLE-CAFC integrated project targets a production plateau of approximately 33 kBOE/d net to Eni by 2016.

Block 208 is located South of Bir Rebaa where the El Merk project is progressing. The development program provides for the construction of a gas treatment plant for the liquid extraction with a gross capacity of approximately 600 mmCF/d, two oil trains with a gross capacity of 65 kBBL/d each and three export pipelines targeting a production plateau at approximately 18 kBBL/d net to Eni in 2015. Start-up is expected in 2013.

Egypt. Eni has been present in Egypt since 1954. In 2012, Eni’s share of production in this Country amounted to 223 kBOE/d and accounted for 14% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Melehia (Eni’s interest 56%) 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 2012, production from these large concessions accounted for approximately 94% of Eni’s production in Egypt.

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

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In 2012, Eni started-up the gas offshore Seth field located in the Ras el Barr concession (Eni’s interest 50%). Production is processed at the El Gamil onshore plant. Production plateau is expected at approximately 170 mmCF/d (approximately 11 kBOE/d net to Eni). Other activities for the year concerned the upgrading of the El Gamil and Abu Madi plants by adding new compression capacity to support production. Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 BCF/y of feed gas. Eni, together with other international oil company, have entered into an agreement to supply 310 mmCF/d for 17-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 kBOE/d net to Eni of feed gas. Exploration activities yielded positive results in the: (i) Belayim concession with the BLNE-2 and BMSW-1 oil discoveries that were linked to the existing facilities; (ii) Nile Delta offshore with the gas discoveries of Ha’py-12, Taurt North-1, Seth South-1, Plio-1C and Nile Delta onshore with the El Qara N-2 gas discovery; (iii) Meleiha development lease with the Rosa North-1X, Emry Deep 1X and 4X oil discoveries. The Emry Deep field started-up with approximately 18 kBBL/d (approximately 6 kBBL/d net to Eni); and (iv) West Razzak development lease with the Aghar NN-1X oil discovery.

Libya. Eni started operations in Libya in 1959. In 2012, Eni’s oil and gas production averaged 252 kBOE/d. Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%). In the exploration phase, Eni is operator of four onshore blocks in the Kufra area (186/1, 2, 3 & 4) and in the contract Areas A, B and 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. In the Offshore Area D, Eni was the first IOC to restart exploration activity after revolution, with the acquisition of about 2,600 square kilometers of 3D seismic survey from February to April 2012. The onshore exploration activity was resumed in December 2012 by drilling the A1-108/4 exploration well that will reach a total depth of approximately 4,420 meters. This is the first well of an onshore exploration campaign that will continue in 2013 marking a relevant step in the full recovery of Eni’s upstream activity in Libya.

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Management plans to complete the recovery of the full production plateau at its Libyan assets in the short term and then to assess possible options to upgrade certain projects.

Tunisia. Eni has been present in Tunisia since 1961. In 2012, Eni’s production amounted to 15 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), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks.

Production optimization was carried out at the Baraka, Oued Zar, MLD and Adam fields.

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo and Nigeria. In 2012, Sub-Saharan Africa accounted for 20% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2012, Eni’s production averaged 80 kBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

The main producing blocks with Eni’s participation are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) in the North of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest ranging from 12% to 15%) in the offshore of the Congo Basin; (iii) Development Areas in the former 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 35% 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%). In the exploration and development phase, Eni operates Block 15/06 (Eni’s interest 35%), where development is ongoing at the West Hub project. Project start-up is expected by mid 2014 with production peaking at 84 kBBL/d (25 kBBL/d net to Eni) in 2016. Exploration and production activities in Angola are regulated by concessions and PSAs. Production started at the satellites Kizomba Phase 1 project in the Development Areas of former Block 15 with peak production at 72 kBBL/d (12 kBBL/d net to Eni) expected in 2013. In 2012, three development projects have been sanctioned: (i) the second phase of Kizomba satellites. The project includes the linkage of three additional discoveries to the existing FPSO. Start-up is expected in 2015; (ii) the Mafumeira field in Area A of Block 0. Development activities are in progress and start-up is expected in 2015; and (iii) the Lianzi discovery. As part of the activities designed to reduce gas flaring in Block 0, activity progressed at the Nemba field in Area B, with completion expected in 2014. Once completed flared gas is expected to decrease by approximately 85% from current level. Other ongoing projects include the installation of a second compression unit at the Nemba platform.

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Eni holds a 13.6% interest in the Angola LNG Ltd (A-LNG), consortium responsible for the construction of an LNG plant with a processing capacity of approximately 1.1 BCF/d of natural gas, producing 5.2 mmtonnes/y of LNG and over 50 kBBL/d of condensates and LPG. The project has been sanctioned by the relevant Angolan Authorities. It envisages the development of 10,594 BCF of gas in 30 years. Exports start-up is expected in 2013. In the year a new agreement has been reached by the partners and local authorities for the sale of LNG on Asian and European markets.

In addition, Eni is part of the Gas Project, a second gas consortium with the Angolan national company and other partners that will explore further potential gas discoveries to support the feasibility of a second LNG train or other marketing projects to monetize gas and associated liquids.

Exploration activities yielded positive results in: (i) Block 15/06 with the oil Vandumbu 1 discovery, first commitment well of the second exploration period; and (ii) Block 2 with the Etele Tampa 7 well containing gas and condensates.

In the medium term, management expects to increase Eni’s production to approximately 160 kBBL/d reflecting additions from ongoing development projects.

Congo. Eni has been present in Congo since 1968. In 2012, production averaged 98 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 65%), Loango (Eni’s interest 50%), Ikalou (Eni’s interest 100%), Djambala, Foukanda and Mwafi (Eni’s interest 65%), Kitina (Eni’s interest 35.75%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Zingali and Loufika (Eni’s interest 85%) fields.

Other relevant producing areas are a 35% interest in the Pointe-Noire Grand Fond, PEX and Likouala permits.

In the exploration phase, Eni also holds interests in the Mer Très Profonde Sud deep offshore block (Eni’s interest 30%), the Noumbi onshore permit (Eni’s interest 37%) and the Marine XII offshore permit (Eni operator with a 65% interest).

Exploration and production activities in Congo are regulated by Production Sharing Agreements. Activities on the M’Boundi field moved forward with the application of Eni advanced recovery techniques and a design to monetize associated gas within the activities aimed at zero gas flaring by 2013. Gas is sold under long-term contracts to power plants in the area including the CEC Centrale Electrique du Congo (Eni’s interest 20%) a 300 MW generation capacity. These facilities will also receive in the future gas from the offshore discoveries of the Marine XII permit. In 2012, M’Boundi contractual supplies were approximately 106 mmCF/d (approximately 17 kBOE/d net to Eni). In 2012, the development project for the gas and condensates Litchendjili field in Block Marine XII has been sanctioned. The project provides for the installation of a production platform, the construction of transport facilities and of an onshore treatment plant. Production will also feed the CEC power station. Other activities in the area concerned the optimization of producing fields of Foukanda and Mwafi by means of Eni’s enhanced recovery technology. Exploration activities yielded positive results in offshore Block Marine XII with the Nene Marine 1 gas discovery. In the medium term, management expects to increase Eni’s production in Congo due to the integration and development of recently acquired assets as well as projects underway, targeting a level in excess of 120 kBOE/d by 2016. Democratic Republic of Congo. Eni has been present in the Democratic Republic of Congo since 2010 where it retains

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a 55% interest and operatorship in Ndunda Block. At present no relevant activities are conducted in this Country.

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.

Exploration activities yielded positive results in the Offshore Cape Three Points license with the: (i) Sankofa East-1X well, the first commercial oil discovery in the area that flowed at approximately 5 kBBL/d of high quality oil in test production; and (ii) the Sankofa East-2A appraisal well that confirmed the high mineral potential of the western area. Studies for a fast track commercial development are underway.

In July 2012, Eni and its partners in the OCPT license, signed a Memorandum of Understanding with the Ministry of Energy of Ghana for the development and marketing of discovered gas resources.

Kenya. In July 2012, Eni was awarded three product sharing contracts by the Government of Kenya. The contracts relate to the L-21, L-23 and L-24 exploration blocks which are located in the deep and ultra-deep waters of the Lamu Basin covering an area of approximately 36,000 square kilometers.

Liberia. In August 2012, Eni acquired a 25% interest in three blocks offshore Liberia covering an area of 8,145 square kilometers at a maximum water depth of 3,000 meters. The joint venture is operated by another international oil company. This operation marks Eni’s entry into Liberia.

Mozambique. Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 block located in the offshore Rovuma Basin. The Exploration Period expires in 2015, and a 30 years duration is awarded in respect of any approved Development and Production Area.

In 2011, Eni made the important Mamba gas discovery.

On March 13, 2013, Eni signed an agreement with CNPC/Petrochina to sell 28.57% of the share capital of the subsidiary Eni East Africa SpA, which currently owns 70% interest in Area 4 for an agreed price equal to $4,210 million. The deal is subject to approval by relevant authorities. Once finalized, CNPC indirectly acquires, through its 28.57% equity investment in Eni East Africa, a 20% interest in Area 4, while Eni will retain the 50% interest through the remaining controlling stake in Eni East Africa.

In 2012, exploration and appraisal campaigns achieved new exploration successes in Area 4 with the Mamba South 2, Mamba North 1, Mamba North East 1 and 2 as well as Coral 1 and 2 gas discoveries. The latest Mamba North East and Coral discoveries are particularly significant since they confirm a new exploration play in Area 4, which is independent from Mamba’s new discovery structure. Management believes that this exploration area contains a large amount of gas resources. The final investment decision is expected in 2014.

In early 2013, a new exploration success was achieved with the delineation of the Coral 3 gas well that is estimated to improve the mineral potential of the area operated by Eni. The wells, drilled at the Coral prospect, showed excellent results during the production test.

Eni plans to drill a further delineation well, Mamba South 3 before moving back to exploration drilling in the Southern sector of Area 4.

In December 2012, Eni signed an agreement with Anadarko Petroleum Corp establishing basic principles for the coordinated development of common offshore activities in Area 4, operated by Eni and Area 1, operated by Anadarko. Furthermore, the two companies plan to jointly design and construct onshore LNG liquefaction facilities in Northern Mozambique.

Nigeria. Eni has been present in Nigeria since 1962. In 2012, Eni’s oil and gas production averaged 149 kBOE/d located mainly onshore and offshore the Niger Delta.

In 2012, Eni completed the divestment of a 5% stake in Blocks OMLs 30, 34 and 40.

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OPL 245 (Eni’s interest 50%), OML 125 (Eni’s interest 85%), 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 25 onshore blocks and a 12.86% interest in 5 conventional offshore blocks.

In the exploration phase Eni operates offshore Oil Prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (Eni’s interest 85%) and OPL 2009 (Eni’s interest 49%); and onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in OML 135.

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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 the state-owned company.

Starting from March 21, 2013, the oil production of the onshore Swamp area mainly in the Bayelsa State in Nigeria has been temporarily shut down due to the increasing bunkering and sabotage acts on the oil trunk lines. Currently, the area produces from 9 fields through 4 flow stations (Ogbainbiri, Tebidaba, Clough Creek, Obama). A detailed survey of the lines affected by the bunkering is in progress in order to identify and repair the damages suffered.

In service contract OML 119, Phase 2A achieved production start-up and is expected to peak at 15 kBBL/d.

In Blocks OMLs 60, 61, 62 and 63, activities progressed to support gas production to feed the Bonny liquefaction plant. Development activities concerned the Tuomo gas field aimed at supplying 170 mmCF/d net to Eni of feed gas to the sixth train for 20 years. The flowstation at Ogbainbiri is nearing completion. This facility will ensure approximately 310 mmCF/d of feed gas to the fourth and the fifth trains. Flaring down program continued with the upgrading of the flowstation at the Idu field with a decline in flared gas of 45 mmCF/d NAOC JV share.

In Block OML 28 (Eni’s interest 5%) the integrated oil and natural gas project in the Gbaran-Ubie area is underway. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of approximately 1 BCF/d of gas and 120 kBBL/d of liquids in order to feed gas the Bonny liquefaction plant.

Activities progressed at the Abo Phase 3 project in Block OML 125. Start-up is expected in 2013.

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 (Eni’s interest 5%) 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

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approximately 49 kBOE/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.

Eni holds a 17% interest in Brass LNG Ltd Co for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100-kilometer west of Bonny. This plant is expected to start operating in 2017 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 BCF/y (approximately 45 net to Eni) of feed gas on two trains for twenty years. Supply to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61.

Exploration activities yielded positive results in: (i) Block OPL 282 with the Tinpa 1 well containing oil; and (ii) Block OPL 2009 with the Afiando 1 and 2 oil wells.

In the medium term, management expects to increase Eni’s production in Nigeria to approximately 190 kBOE/d, reflecting the development of gas reserves.

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 2012, Eni’s operations in Kazakhstan accounted for 6% of its total worldwide production of oil and natural gas.

Kashagan. Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of 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. Development activities are ongoing at the Kashagan field, targeting the production start-up by mid-2013. The NCSPSA will expire 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, and the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, ConocoPhillips with 8.40%, and Inpex with 7.56%.

The exploration and development activities of the Kashagan field and the other discoveries made in the contractual area are executed through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in executing the subsequent development phases of the project once they are sanctioned. The North Caspian Operating Co (NCOC) BV, participated by the seven partners of the consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni has retained the responsibility for the development of Phase 1 of the project (the so-called "Experimental Program") and, when sanctioned, the onshore part of Phase 2.

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 2012, the Experimental Program progressed at the last phase of mechanical completion while commissioning and pre-start up activities achieved an advanced stage. Production plants are planned to be handed over to the production organization and tested. Start-up and commercial production is expected by the end of the first half of 2013, as agreed with the Republic of Kazakhstan.

The Phase 1 (Experimental Program) is targeting an initial production capacity of 150 kBBL/d; by 2014 a second treatment train and compression facilities for gas reinjection will be completed and put online enabling to increase the production capacity 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 re-injection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities and sanction is expected in 2013 to start-up with the FEED phase.

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

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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, 2012, Eni’s proved reserves booked at the Kashagan field amounted to 568 mmBOE, recording an increase compared to 2012 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, 2011, Eni’s proved reserves booked for the Kashagan field amounted to 449 mmBOE, recording a decrease of 120 mmBOE compared to 2010 mainly due to a higher Brent marker price and downward revisions.

As of December 31, 2010, Eni’s proved reserves booked for the Kashagan field amounted to 569 mmBOE, recording a decrease of 19 mmBOE with respect 2009 mainly due to price effect.

As of December 31, 2012, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $7.5 billion (euro 5.7 billion at the EUR/USD exchange rate of December 31, 2012). This capitalized amount included: (i) $5.7 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $1.8 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, 2011, the aggregate costs incurred by Eni for the Kashagan project capitalized in the Consolidated Financial Statements amounted to $6.7 billion (euro 5.2 billion at the EUR/USD exchange rate of December 31, 2011). This capitalized amount included: (i) $5.1 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $1.6 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. The contracting companies transferred 10% of their rights and interest in the project to Kazakhstan’s KazMunaiGas for $1 billion net cash consideration ($325 million being Eni’s share). From the effective date of June 28, 2012, Eni’s interest in the Karachaganak project has been reduced to 29.25% from the 32.5% previously held. The agreement also includes the allocation of an additional 2 mmtonnes/y capacity in the Caspian Pipeline. In 2012, production of the Karachaganak field averaged 239 kBBL/d of liquids (61 net to Eni) and 788 mmCF/d of natural gas (202 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. 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 and associated raw gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg.

Phase 3 of the Karachaganak project is currently under study. The project is aimed at further developing gas and condensates reserves by means of the installation, in stages, of gas treatment plants and re-injection facilities to increase gas sales and liquids production. The development plan is currently in the phase of technical and marketing definition to be presented to the relevant Authorities.

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

As of December 31, 2011, Eni’s proved reserves booked for the Karachaganak field amounted to 500 mmBOE based on a 32.5% working interest, corresponding to the pre-divestment share. The 57 mmBOE decrease derives from the price effect and production of the year in part compensated for upwards revisions.

As of December 31, 2010, Eni’s proved reserves booked for the Karachaganak field amounted to 557 mmBOE, recording a decrease of 76 mmBOE with respect to 2009 due to price effect and production of the year.

Rest of Asia

In 2012, Eni’s operations in the rest of Asia accounted for 8% of its total worldwide production of oil and natural gas.

China. Eni has been present in China since 1984 and its activities are located in the South China Sea. In 2012, Eni’s production amounted to 9 kBOE/d.

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

In March 2013, Eni and CNPC signed a joint study agreement for the development of the Rongchang Block with shale gas resources, over an area of approximately 2,000 square kilometers, located in the Sichuan Basin, in China.

Hydrocarbons are produced from the offshore Blocks 16/08 and 16/19 through eight platforms connected to an FPSO. Natural gas production from the HZ21-1 field is delivered through a sealine to the Zhuhai Terminal and sold to the Chinese National Co CNOOC. Oil is mainly produced from HZ25-4 field (Eni’s interest 49%). Activity is operated by the CACT-Operating Group (Eni’s interest 16.33%).

In April 2012, Eni and CNOOC signed a Production Sharing Contract for the exploration of offshore Block 30/27, located in the South China Sea. The exploration commitment provides for the acquisition of a 3D seismic survey and the drilling of one well to be performed during the first exploration period. Eni will be the Operator of the project, with a 100% interest. In the case of a discovery, CNOOC has a back-in right up to 51%.

India. Eni has been present in India since 2005 and its activities are located in the offshore Cauvery Basin near the South-Eastern coast. In 2012, Eni’s production amounted to 2 kBOE/d. Production mainly comes from the PY-1 gas field which is operated by Eni’s subsidiary Hindustan Oil Exploration Co Ltd (Eni’s interest 47.18%). Gas production is sold to the National oil company. Indonesia. Eni has been present in Indonesia since 2001. In 2012, Eni’s production mainly composed of gas, amounted to 14 kBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 13 blocks. Exploration and production activities in Indonesia are regulated by PSAs. In May 2012, Eni was awarded the East Sepinggan Block (Eni’s interest 100%), located offshore in Kutei Basin supported by the nearby Bontang LNG processing facility. The commitment activity foresees performing of geological and geophysical studies, acquisition of seismic data and the drilling of one well over the next three years. The development plan of the operated Jangkrik (Eni’s interest 55%) and Jau (Eni’s interest 85%) offshore fields progressed. The Jangkrik project includes linkage of production wells to a Floating Production Unit for gas and

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condensate treatment and the construction of a transportation facility to the Bontang liquefaction plant. Start-up is expected in 2016 with a production peak of 80 kBOE/d (41 kBOE/d net to Eni). The Jau project provides for the drilling of production wells and the linkage to onshore plants via pipeline.

Appraisal activities related to a coal bed methane project progressed at the Sanga Sanga PSC (Eni’s interest 37.8%). Predevelopment activities are underway leveraging on the synergy opportunities provided by the existing production and treatment facilities also including the Bontang LNG plant.

Development activities are underway at the Indonesia Deepwater Development project (Eni’s interest 20%), located in East Kalimantan, to ensure gas supplies to the Bontang plant. The project initially provides for the linkage of the Bangka field to existing facilities, then for the integrated development of four fields through a first Hub serving Gendalo, Gandang, Maha and a second Hub for Gehem.

Iran. Eni has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, the latter two projects being operated by another international oil company) entered into with the National Iranian Oil Co (NIOC) between 1999 and 2001, and no other exploration and development contracts have been entered into since then. All the above mentioned projects have been completed or substantially completed; the last one, the Darquain project, is being handed over to NIOC. Operatorship has already been transferred to a NIOC affiliate. When the final hand over of operations will be completed, Eni’s involvement will essentially consist of being reimbursed for its past investments. In 2012, Eni’s contractual reimbursement were equivalent to a production of 3 kBOE/d, lower than 1% of the Group’s worldwide production. Eni does not believe that its activities in Iran have a material impact on the Group’s results. See "Item 3 – Risk factors – Political consideration – Iran" for a full discussion of risks involved by our presence in Iran.

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 32.8% interests in Zubair oil field. Development and production activities in Iraq are regulated by a Technical Service Contract. This contractual term establishes an oil entitlement mechanism and associated risk profile similar to those applicable in Production Sharing Contracts. In 2012, production of the Zubair field averaged 262 kBBL/d (18 kBBL/d net to Eni). Development activities progressed at the Zubair oil field. The contracts have been awarded for the first expansion of the actual production capacity to double the current production level in 2014. Pakistan. Eni has been present in Pakistan since 2000. In 2012, Eni’s production mainly composed of gas amounted to 55 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 (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2012 accounted for 76% of Eni’s production in Pakistan. In December 2012, Eni signed an agreement with the Pakistani Authorities and the state oil and gas company OGDCL for the acquisition of a 25% stake and the operatorship of exploration license Indus Block G, located in ultra deep water offshore of the Indus Basin over an area of approximately 7,500 square kilometers.

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		Exploration activity yielded positive results with a relevant gas discovery in the onshore concession Badhra Area B. A further outline of the discovery will require additional wells. In 2012, the Badhra B North-1 well has been linked to the Bhit plant and started-up in October 2012, flowing at approximately 14 mmCF/d of gas net to Eni. Russia. Eni has been present in Russia since 2007 following the acquisition of Lot 2 in the liquidation procedure of bankrupt Russian company Yukos. Eni acquired a 29.4% interest in the joint venture Severenergia which currently owns important amounts of proved undeveloped gas reserves in the Yamal Peninsula in Siberia. In 2012, Eni’s production mainly composed of gas amounted to 11 kBOE/d. Following start-up of the first and the second train of the Samburgskoye field, a production level is expected at 95 kBOE/d (28 kBOE/d net to Eni). Development activities progressed with completion expected in 2015 and production peak of 146 kBOE/d (43 kBOE/d net to Eni) in 2016. The gas production is sold to Gazprom under an agreement signed in September 2011 while the condensate production is sold to Novatek under the relevant agreement signed in 2012. Eni retains the right to lift its share of natural gas and sell it to any third parties in the domestic market.

Planned activities progressed at the sanctioned Urengoiskoye field (Eni’s interest 29.4%). Start-up is expected in 2014. In April 2012, Eni and Rosneft signed an agreement related to a strategic cooperation whereby the two companies will set up joint ventures (Eni 33.33%) for the exploration and development of the Fedynsky and Tsentralno-Barentsevsky licenses, located offshore Russia in the Barents Sea, and Zapadno-Cernomorsky, located offshore Russia in the Black Sea. Finalization is expected in 2013. Turkmenistan. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused in the Western part of the Country. In 2012, Eni’s production averaged 10 kBOE/d. Exploration and production activities in Turkmenistan are regulated by PSAs. Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap 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 Turkmenneft, via national grid. Vietnam. In June and July 2012, Eni acquired the operatorship (50% interest) of three exploration blocks located offshore Vietnam, in the Song Hong and Phu Khanh basins. The three blocks cover approximately 21,000 square kilometers of acreage. These basins are estimated to contain 10% of Vietnam’s hydrocarbon resources, mainly gas. The

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Company plans to make significant investment to explore for hydrocarbons in the acquired acreage by drilling four wells.

In January 2013, Eni and the Vietnamese national oil company PetroVietnam signed a Memorandum of Understanding for the development of business opportunities in Vietnam and abroad.

Americas

In 2012, Eni’s operations in the Americas 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 2012, Eni’s production averaged 25 kBBL/d.

Exploration and production activities in Ecuador are regulated by a service contract, due to expire in 2023.

Production deriving solely from the Villano field is processed by means of a Central Production Facility and transported via a pipeline network to the Pacific Coast.

Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2012, Eni’s production averaged 59 mmCF/d and its activity is concentrated offshore North of Trinidad.

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

Production is provided by the Chaconia, Ixora, Hibiscus, Poinsettia, Bougainvillea and Heliconia gas fields in the North Coast Marine Area 1 Block (Eni’s interest 17.3%). 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 cost and sold under long-term contracts. LNG production is manly sold in the United States. Additional cargoes are sent to alternative destinations on a spot basis.

United States. Eni has been present in the United States since 1968. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and more recently onshore and offshore in Alaska.

In 2012, Eni’s oil and gas production mainly derived from the Gulf of Mexico with an average of 86 kBOE/d.

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

Eni holds interests in 281 exploration and production blocks in the Gulf of Mexico of which 172 are operated by Eni.

The main fields operated by Eni are Allegheny, Appaloosa and Morpeth (Eni’s interest 100%), Longhorn-Leo, Devils Towers and Triton (Eni’s interest 75%) as well as Pegasus (Eni’s interest 58%). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%) and Thunderhawk (Eni’s interest 25%) fields.

Development activities mainly concerned: (i) drilling activities at the Allegheny, Appaloosa and Devils Towers operated fields; (ii) production optimization of the Front Runner (Eni’s interest 37.5%), Europa, Popeye (Eni’s interest 50%) and Thunderhawk fields; and (iii) the start-up of drilling programs at the Hadrian South (Eni’s interest 30%) and St. Malo (Eni’s interest 1.25%) fields.

Exploration outlining activity of the Heidelberg oil discovery (Eni’s interest 12.5%) in the Gulf of Mexico yielded positive results. Studies are underway for a fast track development.

In order to achieve the highest security standards of operations, Eni entered the HWGC 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".

Development activity progressed at the Alliance area (Eni’s interest 27.5%), in the Fort Worth Basin in Texas. This area, including gas shale reserves, was acquired following a strategic partnership between Eni and Quicksilver. In particular, 12 new wells entered in production and contributed to a total production of approximately 10 kBOE/d net to Eni in the year.

In March 2013, Eni was awarded five offshore blocks located in Mississippi Canyon and Desoto Canyon, in the Gulf of Mexico.

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Eni holds interests in 111 exploration and development blocks in Alaska, with interests ranging from 10 to 100% and for 54 of these blocks, Eni is the operator.

The main fields are Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) with an overall production of 9 kBBL/d net to Eni in 2012.

Development activities mainly concerned drilling activities at the Nikaitchuq and Oooguruk fields.

Venezuela. Eni has been present in Venezuela since 1998. In 2012, Eni’s production averaged 9 kBBL/d.

Activity is concentrated in the Gulf of Venezuela, in the Gulfo de Paria and onshore in the Orinoco Oil Belt.

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

In March 2013, production started-up at the giant Junin 5 field (Eni’s interest 40%) with 35 BBBL of certified heavy oil in place, located in the Orinoco oil belt. Early production of the first phase is expected at plateau of 75 kBBL/d in 2015, targeting a long-term production plateau of 240 kBBL/d to be reached by 2018. The project provides also for the construction of a refinery with a capacity of approximately 350 kBBL/d. The drilling activity started during the year. Eni agreed to finance part of PDVSA’s development costs for the early production phase and engineering activity of refinery plant up to $1.74 billion. Eni signed a loan agreement in the fourth quarter 2012.

Venezuelan relevant Authority sanctioned the development plan of the Perla gas discovery, located in the Cardón IV Block (Eni’s interest 50%), in the Gulf of Venezuela. PDVSA exercised its 35% back-in right in 2012 and the completion of the stake transfer is expected in 2013. Eni retains a 32.5% joint controlled interest in the company.

The early production phase includes the utilization of the already successfully drilled discovery/appraisal wells and the installation of production platforms linked by pipelines to the onshore treatment plant. Target production of approximately 300 mmCF/d is expected in 2015. The development program will continue with the drilling of additional

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wells and the upgrading of treatment facilities to reach a production plateau of approximately 1,200 mmCF/d. In 2012, the FIDs of the further phases were sanctioned.

Activity progressed at the Corocoro producing field (Eni’s interest 26%), in the Gulfo de Paria. In 2012, the start-up of the Central Production Facility (CPF) allowed to achieve a production peak of approximately 42 kBBL/d (approximately 11 kBBL/d net to Eni).

Eni is also participating with a 19.5% interest in the Gulfo de Paria Centrale offshore oil exploration block, where the Punta Sur oil discovery is located and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest, the latter coinciding with the Corocoro oil field area.

Australia and Oceania

Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2012, 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 2012, Eni’s production of oil and natural gas averaged 36 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/P48 (Eni’s interest 32.5%). In addition, Eni holds interest in 9 exploration licenses.

 

Capital expenditures

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

 

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

The Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. 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 2012 Eni carried out support activities and services in respect of certain oil fields in Iran pursuant to certain legacy Service Contracts. Eni’s operating expenses pursuant to those contracts in 2012 amounted to approximately $22 million. In addition, in connection with its remaining Iranian operations, in 2012 Eni paid approximately $6 million for social security, withholding tax, corporate tax and rental tax.

In 2012, Eni’s production in Iran averaged 3 kBOE/d, representing less than 1% of the Eni’s total production for the year. We booked revenues of $128 million in 2012 in connection with our share of equity production and we reported a net loss of $69 million at our Iranian operations. As of the balance sheet date Eni had outstanding trade receivables amounting to euro 270 million towards Iranian oil national companies which were recorded in connection with revenues recognized in 2012 and in previous reporting periods. In 2012, we collected cash payments for a total of $107 million. Those revenues and trade receivables related to the recovery of the costs incurred by Eni in its

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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 $44 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. In addition, in 2012 we purchased 498 ktonnes of Iranian crude oil from NIOC and we paid NIOC $396 million in 2012, for those purchases. We believe that we made no profits on those purchases as our refining margins for the year 2012 were unprofitable on average. Those purchase transactions were entered into pursuant to a waiver granted by the U.S. Department of State as disclosed under “Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets”. Also as a consequence of EU restrictive measures, in June 2012 Eni ceased to import Iranian crude oil with the exception of those volumes necessary to collect outstanding receivables towards Iranian counterparties, as allowed by the European Union sanctions regime.

 

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 2012, Eni’s worldwide sales of natural gas amounted to 95.32 BCM, including 2.73 BCM of gas sales made directly by Eni’s Exploration & Production segment. Sales in Italy amounted to 34.78 BCM, while sales in European markets were 51.02 BCM that included 2.73 BCM of gas sold to certain importers to Italy.

In 2012, following the divestment of a significant interest in Snam, Eni lost control on activities related to the transport, regasification, storage and distribution of natural gas in Italy.

 

Marketing of natural gas

The outlook in the Europe on gas sector remains challenging as the current economic downturn will weigh on the prospects of a solid recovery in gas demand, while we expect strong competitive pressure fuelled by a supply overhang.

Management expects that continuing margin pressures will erode the business’s profitability in 2013 and beyond, particularly in the Italian market. A weaker-than-anticipated demand growth over the short term and rising competitive pressures fuelled by ongoing oversupplies in the European market will reduce sales opportunities and trigger pricing competition also fuelled by rigidities at long-term supply contracts with take-or-pay clauses. In fact, we expect that minimum off-take obligations in connection with take-or-pay, long-term gas supply contracts and the necessity to minimize the associated financial exposure will force gas operators to compete more aggressively on pricing in consideration of lower selling opportunities, with negative effects on selling prices and profitability. Unit margins are expected to remain under pressure due to depressed spot prices at continental hubs which have become the contractual benchmark in selling formulas outside Italy. In addition, as long as the cost of gas supplies to the Group remains indexed to oil prices, the Company will be exposed to the risk of rising oil prices.

In Italy we expect that gas margins will weaken too, due to a number of negative catalysts including competitive pressure, an ongoing shift to index selling prices to hub benchmarks at large client segments, the current level of minimum take volumes at Italian operators which are well above market dimension, and finally the expected measures to be implemented by the Italian administration to cut the gas tariffs to residential customers. See also the other risk factors described in Item 3. These drivers will substantially reduce spot prices in the Italian market and negatively impact the profitability at our Italian operations.

Against this scenario the Company set the following priorities: preserve the operating cash flow during the worst phase of the downturn which is expected to continue well in 2013 and recover the profitability in subsequent years leveraging contract renegotiations, an expected realignment of actual market imbalances and a gradual recovery in the spreads between the oil-linked cost of gas supplies and selling prices at spot markets.

The main driver to recover profitability in the Company’s gas marketing business is the renegotiation of pricing and other conditions of our supply contracts. In fact, take-or-pay supply contracts include revisions clauses allowing the counterparties to renegotiate the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Currently management is seeking to renegotiate about 80% of the Company’s supplies in order to reduce the purchase costs by aligning them to the spot prices at continental hub and improve contractual flexibility targeting to mitigate the take-or-pay risk.

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In a scenario of continuing weak demand and strong competition, management plans to retain the Company’s market share in Italy and Europe by leveraging improved costs in procurement and logistics, and effective commercial actions.

The Company intends to boost sales to business clients, including utilities, large industrial accounts and medium and small enterprises, leveraging 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 with flexibility on volumes and different ways to manage pricing.

The other leg of the Company’s marketing effort will address retail customers across Europe targeting to enhance the ongoing strong customer base. The drivers to achieve this will be a strategy of customer retention centered on brand identity, a distinctive offer and competitive cost to serve; a wide range of sale channels and continuing innovation in processes, promotion and customer care and post-sale assistance. The international expansion in the LNG business is expected to continue by boosting the Company’s presence in the more lucrative Far East markets.

Based on the above outlined trends and industrial actions, management believes that profitability in the Company’s gas marketing business will gradually recover along the plan period, albeit the visibility into future results of operations is constrained by the ongoing volatility in marketing margins. Our profitability outlook factors in the expected benefits of ongoing renegotiations at the Company long-term supply contracts, as well as the other risk factors described in Item 3.

For a description of uncertainties and risks associated with this strategy see "Item 3 – Risk factors" and "Item 5 – Operating and financial review and prospects".

The matters regarding future natural gas demand and sales target 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 relating to future natural gas demand include changes in underlying economic factors, changes in regulation, population growth or shrinkage, changes in the relative mix of demand for natural gas and its principal competing fuels, and unexpected developments in the markets for natural gas and its principal competing fuels.

 

Demand and supply outlook

In 2012, gas demand in Europe declined by 2% (down by 4% in Italy) due to declining consumption in all market segments on the back of the economic downturn. The power generation segment recorded the steepest fall, hit by an ongoing expansion in the use of renewable sources and a shift to coal as feedstock for power plants due to cost advantages. Due to the severity of the contraction in European gas demand and ongoing uncertainties in the macroeconomic outlook, management has revised down its projections of gas demand over the medium to long term to factor in a number of trends:

•		uncertainties and volatility in the current macroeconomic cycle;
•		growing adoption of consumption patterns and life-styles characterized by wider sensitivity to energy efficiency; and
•		EU policies intended to reduce GHG emissions and promoting renewable energy sources, following prescriptions set by the Climate Change and Renewable Energy package (the so-called PEE 20-20-20). The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020. Furthermore, the Energy Roadmap to 2050 set a target of reducing the level of carbon emissions made in 1990 by 80 to 95%.

Management now expects EU demand to increase from around 478 BCM in 2012 to around 526 BCM by 2016, and to close to 552 BCM in 2020, corresponding to an average growth rate of approximately 1.8% along the period. Gas demand in Italy is expected to grow with an average rate of approximately 1.7% in the same period. The projected level of gas demand in 2016 is significantly below the level recorded in the pre-crisis years.

On the plus side, the ongoing changes in the energy policies of the Euro-zone and other important countries like Japan and Taiwan, also as a result of the nuclear accident at the Fukushima plant in Japan, could accelerate a recovery in gas consumption. In addition, the fiscal policies of the EU Member States could affect the composition of the energy mix through the introduction of penalties on the use of the most inefficient and pollutant sources in energy production. Examples of these trends are a proposed European directive to enact a carbon tax to be levied on those sectors which do not participate in the ETS mechanism as well as a proposal to enact certain fiscal adjustments to put a floor to the price of carbon dioxide emissions in the UK.

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On the supply-side, gas availability remains abundant as large investments to upgrade import pipelines to Europe have come online from Russia and Algeria. These include the Medgaz pipeline connecting Algeria to the Iberian Peninsula, the North Stream pipeline connecting Russia to Germany through the Baltic Sea as well as new LNG facilities. Further 27 BCM of new supplies will be secured by a second line of the North Stream in the next future and new storage capacity will come online. In Italy, the gas offer will grow moderately in the next future as a new LNG plant is expected to start operations at Livorno with a 4 BCM treatment capacity and effects are in force of Law Decree No. 130/2010 concerning storage capacity (see below) which is expected to increase by 4 BCM by 2015. Large availability of LNG on a worldwide scale has found an outlet at the European continental hubs driving the development of very liquid spot gas markets driven by the ramp-up of important upstream projects which added an estimated 65 BCM of liquefaction capacity in the 2008-2010 period. Adding to the supply overhang, the United States has reduced the Country’s dependence on LNG imports due to commercial development of large non-conventional gas resources. As a result of those drivers, we expect that current market imbalances will continue over the next two to three years. Looking beyond, however, we expect the European market to rebalance due to a growing energy demand coming from the developing economies in China, India and other emerging countries in East Asia, Middle East and South America where, between now and 2015, we expect that consumption will increase significantly mainly driven by robust rates of economic development. This will help absorb part of worldwide LNG supplies which are currently being delivered to Europe. Additionally we expect that gas production in Europe will progressively decline due to mature field depletion. However there are also some risks in the demand scenario. In fact, management believes that it is possible that the U.S. Administration might speed up the process to monetize the Country’s large reserve base of shale gas by giving permission to reconvert re-gasification plants into LNG export facilities. Furthermore, new upstream projects might be started up in the long run adding to global LNG supplies (particularly the projects to develop gas reserves in Mozambique). Finally, it is difficult to estimate the long-term impact of the current European economic slowdown on gas demand, the effectiveness of EU Member States initiatives to achieve the committed targets in reducing energy intensity and the evolution of the role of renewables in the production of electricity.

 

Planned actions in marketing of natural gas

Over the 2013-2016 period, Eni’s strategy will focus on certain distinct commercial objectives to recover profitability in a difficult market:

•		to maintain its leadership in the Italian market mainly by strengthening the customer base in the valuable segments of retail consumers and small and medium businesses;
•		to consolidate Eni’s position in Europe in the business gas market, where the Company has a well balanced portfolio in terms of geographies, customer segments and contract duration;
•		to focus on more profitable segments;
•		to increase LNG sales in profitable markets outside Europe; and
•		maximize sales volumes in order to mitigate the take-or-pay risk.

In particular management plans to regain market share in Italy and to expand sales in European target markets by leveraging first of all on the improved competitiveness of the Company’s cost position reflecting the benefit of the renegotiation of its supply contracts, the quality of its offer, including risk management and transport and storage contracts, pricing formulas and commercial options that are designed to suit customers’ needs. In particular, in the retail segment in Italy Eni’s campaign will focus on a combined commercial offer "luce, gas, carburanti" (electricity, gas and fuels) and the adoption of lean marketing procedures to facilitate customers’ tasks and optimization of commercial channels (such as agencies, remote selling, energy stores) with a strong focus on web channels.

In order to increase exposure to the retail segment, management plans to expand its customer base in Italy and outside Italy, by almost 3 million clients in the next four years to reach a total of 14 million customers by 2016, strengthening Eni’s position in this segment in particular in Italy, through our distinctive offer "eni 3" (gas, electricity and fuels) and innovative sales channels. To retain more sophisticated customers in both the large and medium to small enterprises segment across Europe, the Company is ready to launch new innovative commercial offers based on multiple pricing options and volume flexibility.

 

Supply of natural gas

In 2012, Eni’s consolidated subsidiaries supplied 86.74 BCM of natural gas, representing an increase of 3.36 BCM, or 4% from 2011.

Gas volumes supplied outside Italy (79.19 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 91% of total supplies, an increase of 3.03 BCM, or 4%, from 2011, mainly reflecting higher volumes purchased from Libya (up 4.23 BCM), almost tripled from 2011 when the GreenStream gas pipeline had been shutdown.

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Increased volumes were purchased also from the Netherlands (up 0.95 BCM), and from Algeria (up 0.51 BCM). Declines were recorded in gas purchases from Russia (down 1.17 BCM) due to the recovery of Libyan supplies, the UK (down 0.37 BCM) and Norway (down 0.17 BCM). Supplies in Italy (7.55 BCM) increased slightly from 2011 also due to higher domestic production that offset the decline of mature fields. In 2012, main gas volumes from equity production derived from: (i) Italian gas fields (6.7 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (1.9 BCM); (iii) Libyan fields (1.8 BCM) increasing by almost 1.2 BCM due to the effect of force majeure registered in 2011; (iv) the United States (1.6 BCM); and (v) other European areas (Croatia with 0.2 BCM).

Considering also direct sales of the Exploration & Production Division and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 18 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		2010		2011		2012

(BCM)

Italy		7.29			7.22			7.55
Outside Italy		75.20			76.16			79.19
Russia		14.29			21.00			19.83
Algeria (including LNG)		16.23			13.94			14.45
Libya		9.36			2.32			6.55
the Netherlands		10.16			11.02			11.97
Norway		11.48			12.30			12.13
the United Kingdom		4.14			3.57			3.20
Hungary		0.66			0.61			0.61
Qatar (LNG)		2.90			2.90			2.88
Other supplies of natural gas		4.42			6.16			5.43
Other supplies of LNG		1.56			2.34			2.14
Total supplies of subsidiaries		82.49			83.38			86.74
Withdrawals from (input to) storage		(0.20	)		1.79			(1.35	)
Network losses, measurement differences and other changes		(0.11	)		(0.21	)		(0.28	)
Volumes available for sale of Eni’s subsidiaries		82.18			84.96			85.11
Volumes available for sale of Eni’s affiliates		9.23			8.94			7.48
E&P volumes		5.65			2.86			2.73
Total volumes available for sale		97.06			96.76			95.32

In order to secure long-term access to gas availability, particularly with a view to supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts have been ensuring approximately 80 BCM of gas availability from 2010 (including the Distrigas portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 16 years and a pricing mechanism that indexed to the cost of gas to the price of crude oil and its derivatives (gasoil, fuel oil, etc.). These contracts provide take-or-pay clauses whereby the Company is required to collect minimum pre-determined 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, applied to uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. In the current industry downturn, the Company has failed to off-takes the annual minimum quantities of gas provided by the contractual take-or-pay clause, being forced to pre-pay the underlying gas volumes.

Management believes that the weak industry outlook weighed down by declining demand 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. From the beginning of the downturn in the European gas market up to date, Eni has incurred the take-or-pay clause as the Company off-took lower volumes than its minimum take obligations accumulating deferred costs for an amount of euro 2.37 billion (net of limited amounts of volume make-up) paying the associated cash advances to its gas suppliers. Considering the Company’s outlook for its sales volumes which are anticipated to remain stable in 2013 and to grow at a moderate pace in subsequent years, management intends to adopt adequate initiatives to mitigate the financial exposure related to take-or-pay obligations mainly in the domestic market where the expected volume of demand is lower in comparison with the minimum contracted supplies which Italian gas intermediaries are obliged to fulfill. The initiatives to mitigate the take-or-pay risk include contract renegotiations which may temporarily reduce the annual minimum take, more flexible off-take conditions such as change in the delivery point or the possibility to replace supplies via pipeline with equivalent volumes of LNG. Based on the Company’s selling programs and higher flexibility already achieved or to be achieved through the above mentioned renegotiations, management believes that it is likely

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that in the 2013-2016 period Eni will manage to fulfill its minimum take obligations associated with its supply contracts thus minimizing the risk on liquidity.

These projections could be subject to the risks of further contraction in demand or total addressable market. As to the deferred costs stated in the balance sheet, based on management’s outlook for gas demand and offer in Europe, and projections for sales volumes and unit margins in future years, the Company believes that the pre-paid volumes of gas due to the incurrence of the take-or-pay clause will be off-taken in the long term in accordance to contractual term thus recovering the cash advances paid to suppliers.

This forecast is subject to the risk factors described in "Item 3 – Risk factors" and in our outlook in "Item 5 – Operating and financial review and prospects".

 

Sales of natural gas

In 2012, sales of natural gas were 95.32 BCM, down 1.44 BCM or 1.5% from 2011. Sales included Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and E&P sales in Europe and in the Gulf of Mexico.

Despite a 4% decline in natural gas demand, sales volumes on the Italian market were substantially stable at 34.78 BCM (up 0.10 BCM, or 0.3% from 2011). Lower sales to the power generation segment (down 1.76 BCM), industrial customers (down 0.28 BCM) and wholesalers (down 0.51 BCM), due to the negative scenario and increasing competitive pressure, were offset by higher sales on the Italian exchange for gas and spot markets (up 2.28 BCM) and at a lower extent to the residential segment (up 0.22 BCM) reflecting efficient commercial initiatives.

Sales to shippers were down 0.51 BCM, or 15.7%, due to the release of certain supply contracts despite the recovery of Libyan supplies.

Sales on target markets in Europe of 48.29 BCM showed a slight decline from 2011 (down 2.9%). This decline was mainly due to a decline in sales in Benelux (down 3.53 BCM) and in the Iberian Peninsula (down 1.19 BCM) due to the exclusion of Galp sales after the loss of control offset only in part by increases recorded in France (up 1.35 BCM) also and Germany/Austria (up 1.31 BCM) due commercial initiatives.

Sales to markets outside Europe increased by 0.55 BCM due to higher LNG sales in the Far East, in particular in Japan.

E&P sales in Northern Europe and in the United States (2.73 BCM) declined by 0.13 BCM due to lower sales in the North Sea.

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

Natural gas sales by entities		2010		2011		2012

(BCM)

Total sales of subsidiaries		82.00		84.37		84.67
Italy (including own consumption)		34.23		34.60		34.66
Rest of Europe		46.74		45.16		44.94
Outside Europe		1.03		4.61		5.07
Total sales of Eni’s affiliates (Eni’s share)		9.41		9.53		7.92
Italy		0.06		0.08		0.12
Rest of Europe		7.78		7.82		6.08
Outside Europe		1.57		1.63		1.72
Total sales of G&P		91.41		93.90		92.59
E&P in Europe and in the Gulf of Mexico (a)		5.65		2.86		2.73
Worldwide gas sales		97.06		96.76		95.32

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(a)

E&P sales include volumes marketed by the Exploration & Production division in Europe (2.33, 2.29 and 2.06 BCM in 2010, 2011 and 2012, respectively) and in the Gulf of Mexico (3.32, 0.57 and 0.67 BCM in 2010, 2011 and 2012, respectively).

 

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Natural gas sales by market		2010		2011		2012

(BCM)

ITALY		34.29		34.68		34.78
Wholesalers		4.84		5.16		4.65
Gas release		0.68
Italian gas exchange and spot markets		4.65		5.24		7.52
Industries		6.41		7.21		6.93
Medium-sized enterprises and services		1.09		0.88		0.81
Power generation		4.04		4.31		2.55
Residential		6.39		5.67		5.89
Own consumption		6.19		6.21		6.43
INTERNATIONAL SALES		62.77		62.08		60.54
Rest of Europe		54.52		52.98		51.02
Importers in Italy		8.44		3.24		2.73
European markets		46.08		49.74		48.29
Iberian Peninsula		7.11		7.48		6.29
Germany-Austria		5.67		6.47		7.78
Benelux		15.64		13.84		10.31
Hungary		2.36		2.24		2.02
UK-Northern Europe		4.45		4.21		4.75
Turkey		3.95		6.86		7.22
France		6.09		7.01		8.36
Other		0.81		1.63		1.56
Extra European markets		2.60		6.24		6.79
E&P in Europe and in the Gulf of Mexico		5.65		2.86		2.73
WORLDWIDE GAS SALES		97.06		96.76		95.32

 

European markets

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

Benelux. Eni’s holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, the integration with Distrigas’ operations, the presence in the retail and middle market and its significant exposure to spot markets in Western Europe. In 2012, sales in Benelux were mainly directed to industrial companies, power generation and wholesalers and amounted to 10.31 BCM (13.84 BCM in 2011), down by 3.53 BCM, or 25.5%, due to rising competitive pressure, in particular in the wholesalers segment. In 2012, Eni launched its brand in the business and retail gas and power market in Belgium. The Eni brand substituted that of local operators acquired in the past few years with the aim of consolidating its leadership on the market.

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. Management plans to expand sales in France over the plan period growing volumes supplied to the business segments and increasing retail customers. In 2012, sales in France amounted to 8.36 BCM (7.01 BCM in 2011), an increase of 1.35 BCM, or 19.3%, from a year ago. In 2012, Eni launched its brand in France, substituting 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 is present in the natural gas market through a direct marketing structure which sold in 2012 approximately 4.40 BCM in Germany and 0.94 BCM in Austria through its associate GVS (GasVersorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.48 BCM in 2012 (2.24 BCM being Eni’s share). Management plans to drive growth in direct sales leveraging on the quality of its commercial offer, a projected expansion in its business customer base and the enhancement of direct presence on the market. In 2012, total sales in the Germany/Austria market amounted to 7.78 BCM, an increase of 1.31 BCM, or 20.2%, from a year ago.

Iberian Peninsula

Portugal. From the second half of 2012 due to the divestment of a stake in Galp and exit from the shareholders’ pact, Eni ceased reporting the share of gas volumes marketed by Galp in the Portuguese market due to the loss of significant influence on the investee.

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 2012, UFG gas sales in Europe amounted to 4.82 BCM (2.41 BCM Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36%

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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 2012, Eni sales in Spain amounted to 5.24 BCM decreasing from a year ago. In 2012, total sales in the Iberian Peninsula amounted to 6.29 BCM, a decrease of 1.19 BCM, or 15.9%, from a year ago.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2012, sales amounted to 7.22 BCM, an increase of 0.36 BCM, or 5.2% from a year ago.

UK-Northern Europe. Eni through its subsidiary ETS markets in the UK 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 2012, sales amounted to 4.75 BCM, an increase of 12.8% from a year ago.

The Deborah Gas Storage Project (DGSP) is a seasonal gas storage development planned for the Deborah reservoir (located in UKCS Block 48/30a) which will be connected to the National Transmission System at Bacton, via the Company’s existing production terminal.

FEED activities, as well as site activities (i.e. onshore surveys) were carried out throughout 2010-2011. Concerning the permits and consents, an agreement to lease the offshore field has been reached with The Crown Estate and a Gas Storage License has been granted by DECC while the North Norfolk District Council (NNDC) has approved the Deborah Project planning application subject to conditions. Appraisal works on the Deborah reservoir were also progressed throughout 2010, including the drilling and completion of an appraisal well and the related tests. An approved equity sales process to dilute the Eni stake was conducted throughout 2011, as well as a market based long term capacity allocation process in 2010. Ongoing work with UK government ministries and regulatory agencies continued in 2011 and across 2012 in order to promote the continued role of natural gas within the UK energy mix and support the economic case for the DGSP. The aim being to secure a support mechanism guaranteeing reasonable revenues to underwrite the DGSP investment. At the end of 2012 the Department of Energy and Climate Change published its Gas Generation Strategy and received Ofgem’s Security of Supply report. It has now launched its own deep analysis of the costs and benefits of an intervention to support Gas Storage investment aiming to deliver its recommendations in Spring 2013.

However, Government legislation is not expected to come into force until 2014, Eni therefore targets a possible FID in 2014-2015.

 

The LNG business

Eni operates in all phases of the LNG business: gas feeding, liquefaction, shipping, re-gasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is tied to the Company’s plans to develop its large gas reserve base in Africa and elsewhere in the world. The LNG business has not been impacted by the economic downturn and oversupply affecting the European gas market, as well as by structural modifications in the U.S. market. LNG flexibility allowed to adapt the business model to the new scenario and to increase the value of the commodity entering in new markets.

Eni’s main assets and projects in the LNG business are described below.

Qatar. Through its subsidiary Distrigas, Eni increased its development opportunities in the LNG business with access to new supply sources mainly from Qatar, under a 20-year agreement with RasGas (owned by Qatar Petroleum with a 70% interest and ExxonMobil with a 30% interest) and the Zeebrugge LNG terminal on the Western coast of Belgium.

Egypt. Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant with a capacity of approximately 5 mmtonnes/y of LNG which equates to a feedstock of 7.56 BCM/y in natural gas out of which the Gas & Power segment interest is up to 2.2 BCM/y to be marketed in Europe.

Spain. Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto re-gasification plant, near Valencia, with a capacity of 8.8 BCM/y and a LNG storage capacity of 450,000 CM which will be increased to 600,000 CM after the ongoing construction of a fourth tank. At present, Eni’s re-gasification capacity entitlement amounts to 1.9 BCM/y of gas.

Eni through Unión Fenosa Gas also holds a 9.45% interest in the El Ferrol re-gasification plant, located in Galicia, with a treatment capacity of approximately 3.6 BCM/y, of which 0.34 BCM/y being Eni’s capacity entitlements. The LNG storage capacity of the plant is 300,000 CM in two tanks.

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USA

Cameron. The Cameron LNG terminal is located on the coastline of Louisiana. The facility where Eni owns a capacity entitlement to treat LNG was completed in the third quarter of 2009. In consideration of a changed demand outlook, on March 1, 2010, Eni renegotiated certain terms of the contract with the U.S. company Cameron LNG, relating to the farming out of a share of re-gasification capacity resulting in an entitlement to Eni of a daily send-out of 572,000 mmbtu (approximately 5.7 BCM/y). Considering current oversupply conditions in the U.S. gas market, the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant has been rescheduled with start-up in 2017.

Pascagoula. This project is part of an upstream development project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 BCM/y) destined to the North American market in order to monetize part of the Company’s gas reserves. As part of the downstream leg of the project, Eni signed a 20-year contract with Gulf LNG to buy 5.8 BCM/y of the re-gasification capacity of the plant under construction near Pascagoula in Mississippi. The re-gasification facility is in operation from the last quarter of 2012.

Eni USA Gas Marketing Llc also signed a 20-year contract to purchase approximately 0.9 BCM/y of re-gasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG. In 2012, the partners and local authorities reached an agreement for the sale of LNG on Asian and European markets due to the changed gas demand outlook in the U.S. market.

LNG sales		2010		2011		2012

(BCM)

G&P sales		11.2		11.8		10.5
Italy		0.2
Rest of Europe		9.8		9.8		7.6
Extra European markets		1.2		2.0		2.9
E&P sales		3.8		3.9		4.1
Liquefaction plants:
- Bontang (Indonesia)		0.7		0.6		0.6
- Point Fortin (Trinidad and Tobago)		0.6		0.4		0.5
- Bonny (Nigeria)		2.2		2.5		2.7
- Darwin (Australia)		0.3		0.4		0.3
		15.0		15.7		14.6

 

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 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 2012, the program for upgrading and improving flexibility of the combined cycle power plants progressed in accordance with the Company’s developing plans.

In 2012, electricity sales (42.58 TWh) were directed to the free market (75%), the Italian power exchange (14%), industrial sites (8%) and others (3%). In 2012, electricity sales increased by 5.7% due to an increased client base thanks to effective marketing policies in spite of weak domestic demand.

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Power availability		2010		2011		2012

(TWh)

Power generation sold		25.63		25.23		25.67
Trading of electricity (a)		13.91		15.05		16.91
		39.54		40.28		42.58
Power sales by market
Free market (b)		27.84		27.25		31.84
Italian Exchange for electricity		7.13		8.67		6.10
Industrial plants		3.21		3.23		3.30
Other (a) (b)		1.36		1.13		1.34
		39.54		40.28		42.58

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(a)		Include positive and negative imbalances.
(b)		Network losses have been restated from other to free market.

 

Power generation

Eni’s main power generation plants are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in various photovoltaic parks.

In 2012, power production was 25.67 TWh, down 0.44 TWh, or 1.7% from 2011, mainly due to increased production at the Ferrara plant, offset in part by decreases at the Ferrera Erbognone and Ravenna plants.

As of December 31, 2012, installed operational capacity was 5.3 GW (5.3 GW as of December 31, 2011).

Power availability in 2012 was supported by the growth in electricity trading activities (up 1.86 TWh, or 12.4%) due to higher volumes traded on the Italian power exchange benefiting from lower purchase prices.

By 2015, Eni expects to complete its plans for capacity expansion targeting an installed capacity of 5.4 GW. In the medium term, Eni intends to consolidate operations at its power generation plants and to enhance the flexibility of assets in order to better meet market needs. Furthermore Eni intends to develop the production from renewable sources focusing on photovoltaic power plants, and on the Company’s "Green Chemistry" project for the remediation of the Porto Torres site, where it will be also build a bio-mass power plant. Development activities are currently underway at the Bolgiano (Eni 100%) plant.

Supplies of natural gas are expected to amount to approximately 6 BCM/y from Eni’s diversified supply portfolio.

New installed generation capacity uses the combined cycle gas fired technology (CCGT) and produces electricity combined with heat ("cogeneration") used to feed industrial processes and district heating networks, ensuring a high level of efficiency and low environmental impact. In particular, management estimates that for a given amount of energy (electricity and heat) produced, using the CCGT technology instead of conventional power generation technology, the emission of carbon dioxide reduces by approximately 5 mmtonnes, on an energy production of 26.5 TWh.

The electricity acknowledged as produced in cogeneration benefits from the exemption from the legal provision of buying green certificates. According to this legal provision, power producers has to input a certain percentage of energy from renewable sources in proportion to the energy produced from fossil-fuel or, as an alternate measure, to purchase green certificates. The recently enacted Legislative Decree No. 28/2011 provides for a gradual reduction of the share of electricity production currently covered by obligation of buying green certificates, until it is completely cancelled in 2015. Eni and other cogeneration producers are involved in a legal argument with the Italian state-owned company promoting and supporting renewable energy resources (GSE - Gestore Servizi Elettrici), which is in charge of controlling the compliance of obligation, concerning the way of assessing energy acknowledged as produced in cogeneration. Position supported by GSE implies that producers have to buy a greater amount of green certificates because they are not allowed to assess the amount of electricity from cogeneration according to the AEEG’s decision 42/02.

With a further administrative measure, the electricity produced from cogeneration has been considered eligible to be awarded with "white certificates", in proportion to primary energy saving granted to the system. Power plants built before 2007 will be entitled to gain white certificates in a measure equivalent to 30% of the amount awarded to a new project.

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In spite of these incentives, we believe that in the next four years our expenses to comply with environmental regulation will trend higher as a result of stricter rules that will apply to the award of emission allowances in the EU emission trading mechanism, causing the Company to increase its purchases of allowance on the free market.

The main assets of Eni power generation activities in Italy are provided in the table below.

Site		Total installed capacity in 2012 (a) (MW)		Technology		Fuel

Brindisi		1,321		CCGT		gas
Ferrera Erbognone		1,030		CCGT		gas/syngas
Livorno		199		Power station		gas/fuel oil
Mantova		836		CCGT		gas
Ravenna		972		CCGT		gas
Taranto		75		Power station		gas/fuel oil
Ferrara		841		CCGT		gas
Bolgiano		30		Power station		gas
Photovoltaic parks		4		Power station		photovoltaic energy
		5,308

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(a)

Capacity available after completion of dismantling of obsolete plants.

 

Power generation		2010		2011		2012

Purchases
Natural gas		(mmCM)		5,154		5,008		5,206
Other fuels		(ktoe)		547		528		462
- of which steam cracking				103		99		98
Production
Electricity		(TWh)		25.63		25.23		25.67
Steam		(ktonnes)		10,983		14,401		12,603
Installed generation capacity		(GW)		5.3		5.3		5.3

 

Infrastructures

Eni has transport rights on a large European network of integrated infrastructure for transporting natural gas, which links key consumption basins with the main producing areas (Russia, Algeria, Libya and the North Sea).

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

Eni owns capacity entitlements in an extensive network of international high pressure enabling the Company to import natural gas produced in Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya to Italy. The Company participates to both entities which own and operate the pipelines, the pipeline owners, and entities which manage transport rights, the carriers. For financial reporting purposes, such entities are either fully-consolidated or equity-accounted depending on the Company’s interest or agreements with other shareholders.

The structure of the Company’s interests in those entities has significantly changed in 2011 following the divestment of Eni’s interests in importing pipelines of natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG) and related carrier companies, as part of the agreements signed on September 29, 2010 with the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas market. In light of the strategic importance of the Austrian TAG pipeline to the supply of the Italian system, which transports gas from Russia to Italy, Eni divested its stake to an entity controlled by the Italian State. However, Eni retained its gas transport rights in the divested assets.

A description of the main international pipelines currently participated or operated by Eni is provided below.

The TTPC pipeline, 740-kilometer long, 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 pipeline was recently upgraded by increasing compression capacity in order to enable transportation of an additional 6.5 BCM/y. The upgrade was finalized in 2008 and became fully-operational during 2009.

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 underwater 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 Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 11 BCM/y and crosses underwater in 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

Eni and Gazprom are jointly assessing the technical and economic feasibility of a project to build a new import route to Europe to market gas produced in Russia (the so-called South Stream project).

The South Stream pipeline will provide transport capacity of 63 BCM/y and is expected to be composed by two sections: (i) an offshore section crossing the Black Sea from the Russian coast at Anapa (in the same Southern Russian area of Beregovaya, the starting point of the Blue Stream pipeline) to the Bulgarian coast at Varna; and (ii) an onshore section crossing Bulgaria for which two options are currently being evaluated: one pointing North West and another one pointing South West.

Eni is involved only in the offshore section of the project.

In September 2011, Eni and Gazprom in the context of their strategic partnership signed a series of agreements in areas of common interest including the development of the offshore section of the South Stream project through the definition of terms for the participation to the project of gas operators Wintershall and EDF, each with a 15% stake; Gazprom and Eni hold 50% and 20% interests, respectively.

On November 14, 2012, in accordance with the shareholders agreement the partners confirmed that South Stream project will proceed according to the agreed schedule aiming at transporting the first gas through the Black Sea by the end of 2015. Pursuant the shareholder agreement the minority shareholders including Eni have the right to leave the project in case certain future conditions are not satisfied.

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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.

The outlook in the Refining & Marketing segment remains a depressed one as management does not expect any meaningful improvement in the trading environment over the next four years of the industrial plan. The ongoing economic downturn is anticipated to weigh on the recovery of demand for fuels, while high costs of the crude oil feedstock and energy utilities will continue squeezing refining margins. On the supply side, it is unlikely that ongoing capacity rationalization will help absorb product surpluses on the short term. Also retail and wholesale marketing activities of refined products will be affected by sluggish demand and product oversupply that is expected to trigger pricing competition. See "Item 3 – Risk factors" and "Regulation" below.

Due to the challenging market environment and industry downturn, we plan to implement all available levers to improve operations efficiency and profitability. The main planned initiatives in our refining operations are:

•		to pursue better integration of refineries and logistic assets and seek synergies with the Exploration & Production segment to monetize equity crudes and proprietary technologies;
•		to maximize refinery flexibility and conversion to extract value from heavy crudes;
•		to convert the Venice plant into a "bio-refinery" to produce bio-fuels;
•		to achieve energy efficiency initiatives and ensure higher rates of plant reliability;
•		to rationalize logistic costs and implement other cost-saving measures;
•		to strictly select capital expenditures; and
•		to boost margins leveraging on risk management activities.

In the marketing activity, we plan to preserve our profitability by:

•		strengthening our leadership in the Italian retail market leveraging on opportunities deriving from the liberalization process (i.e. rationalizing stations with low throughput, boosting full "iperself" mode and development of non-oil activities);
•		preserving our customer base by effective marketing actions, rolling out our "eni" brand and service excellence;
•		boosting margins by increasing the number of fully automated outlets and the contribution from non-oil products and services; and
•		selectively growing our market share in European markets.

In the 2013-2016 period, we plan to make capital expenditures amounting to euro 2.4 billion carefully selecting capital projects. Management plans to invest approximately euro 1.7 billion to convert the Venice plant into a bio-refinery, upgrade the Company’s best refineries mainly by completing and starting-up the EST (Eni Slurry Technology) project at the Sannazzaro unit which will upgrade the conversion capacity of the refinery, as well as improving plant efficiency and reliability. Retail activities will attract some 25% of the planned expenditure which will be mainly directed to upgrade and modernize our service stations in Italy and in selected European countries, and to complete the network rebranding.

Based on the planned initiatives, management expects Eni’s refining and marketing operations to break-even in the next four-year period assuming a constant trading environment.

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.

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Supply

In 2012, a total of 62.21 mmtonnes of crude were purchased by the Refining & Marketing segment (59.02 mmtonnes in 2011), of which 26.92 mmtonnes from Eni’s Exploration & Production segment, 24.95 mmtonnes on the spot market and 10.34 mmtonnes were purchased under long-term supply contracts with producing countries. Approximately 25% of crude purchased in 2012 came from Russia, 19% from West Africa, 12% from the North Sea, 10% from North Africa, 8% from the Middle East, 6% from Italy and 20% from other areas. In 2012, some 36.56 mmtonnes of crude purchased were marketed (down 4.46 mmtonnes from 2011, or 13.9%). In addition, 4.53 mmtonnes of intermediate products were purchased (4.26 mmtonnes in 2011) to be used as feedstock in conversion plants and 20.52 mmtonnes of refined products (15.85 mmtonnes in 2011) were purchased to be sold on markets outside Italy (17.24 mmtonnes) and on the domestic market (3.28 mmtonnes) as a complement to available production.

 

Refining

In 2012, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 38.3 mmtonnes (equal to 767 kBBL/d) and a conversion index of 61%. Conversion index let to evaluate 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 28.7 mmtonnes (equal to 574 kBBL/d), with a 64% conversion index. In 2012, Eni’s refineries throughputs in Italy and outside Italy was 30.01 mmtonnes.

The table below sets forth certain statistics regarding Eni’s refineries as of December 31, 2012.

Refining system in 2012

Ownership share (%)

Distillation capacity (total) (kBBL/d)

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

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

Conversion index (1) (%)

Fluid catalytic cracking - FCC (2) (kBBL/d)

Residue conversion (kBBL/d)

Go-Finer (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				685		685		574		64		69		42		37		29		89		46		61		73
Italy
Sannazzaro		100		223		223		190		59		34		12				29		29				75		88
Gela		100		129		129		100		142		35				37						46		33		42
Taranto		100		120		120		120		72				30						38				66		66
Livorno		100		106		106		84		11														76		96
Porto Marghera		100		107		107		80		20										22				44		59
Partially owned refineries (3)				874		245		193		51		167		25				99		27				79		100
Italy
Milazzo		50		248		124		80		76		45		25				32						73		113
Germany
Vohburg/Neustadt (Bayernoil)		20		215		43		41		36		49						43						92		96
Schwedt		8.33		231		19		19		42		49								27				101		104
Czech Republic
Kralupy e Litvinov		32.4		180		58		53		30		24						24						75		83
Total refineries				1,559		930		767		61		236		67		37		128		116		46		72		80

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(1)		Stated in fluid catalytic cracking equivalent/topping (% by weight), based on 100% of balanced primary distillation capacity.
(2)		Conversion plant where vacuum feedstock undergoes cracking at high pressure and moderate temperature thus producing mostly high quality gasoline. This kind of plant guarantees high operating flexibility to the refinery.
(3)		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 190 kBBL/d and a conversion index of 59%. 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 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. The most important currently underway project is EST (Eni Slurry Technology) a conversion plant with a 23 kBBL/d

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capacity in order to process extra heavy crude with high sulphur content increasing middle distillates, reducing fuel oil. Start-up of this facility is scheduled by 2013. Therefore, Eni is developing conversion technology of Slurry Dual Catalyst (an evolution of EST), based on a combination of two nano-catalysts, could lead to a relevant breakthrough in the EST process, increasing its productivity and improving product quality, reducing expenditure and operating costs.

A further project is the proprietary process for hydrogen production, Hydrogen SCT-CPO (Short Contact Time-Catalytic Partial Oxidation) and the design is nearly over. 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 72%. This refinery process most of oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2012 a total of 2.26 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 has balanced refining capacity of 100 kBBL/d and a conversion index of 142%. Located on the Southern coast of Sicily, it is integrated with upstream operations processing heavy crude produced from Eni’s nearby offshore and onshore fields. Its high conversion level is ensured by an FCC unit with go-finer for feedstocks upgrading and two coking plants enabling conversion of heavy residues topping or vacuum residues. In order to achieve full compliance with the tightest environmental standards, in the power station there is SNOx plant to remove suphur dioxide, nitrogen oxides and particulates from flue gases. An underway refurbishment of the Gela power plant, substantially renewing pet-coke boilers, will increase profitability maximizing synergies from refining and power generation.

Livorno refinery, with balanced refining capacity of 84 kBBL/d and a conversion index of 11%, 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 refinery, with balanced refining capacity of 80 kBBL/d and a conversion index of 20%, supplies mainly markets in North-Eastern Italy and Austria. Besides its primary distillation plants, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) to increase yields of valuable products.

Eni will turn the refinery into a "bio-refinery" based on proprietary technology for the production of bio-diesel based on its Ecofining technology. The conversion to a Green Refinery will begin in the second quarter of 2013 and start bio-fuel production in 2014 and will be associated with a logistics center.

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 Czech Republic, Eni’s share is 32.4% in Ceska Rafinerska, that includes two refineries, Kralupy and Litvinov. Eni’s refining capacity amounts to about 53 kBBL/d to supply Eastern Europe.

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

Availability of refined products		2010		2011		2012

(mmtonnes)

ITALY
Refinery throughputs
At wholly-owned refineries		25.70			22.75			20.84
Less input on account of third parties		(0.50	)		(0.49	)		(0.47	)
At affiliated refineries		4.36			4.74			4.52
Refinery throughputs on own account		29.56			27.00			24.89
Consumption and losses		(1.69	)		(1.55	)		(1.34	)
Products available for sale		27.87			25.45			23.55
Purchases of refined products and change in inventories		4.24			3.22			3.35
Products transferred to operations outside Italy		(4.18	)		(1.77	)		(2.36	)
Consumption for power generation		(0.92	)		(0.89	)		(0.75	)
Sales of products		27.01			26.01			23.79
OUTSIDE ITALY
Refinery throughputs on own account		5.24			4.96			5.12
Consumption and losses		(0.24	)		(0.23	)		(0.23	)
Products available for sale		5.00			4.73			4.89
Purchases of finished products and change in inventories		10.61			12.51			17.29
Products transferred from Italian operations		4.18			1.77			2.36
Sales of products		19.79			19.01			24.54
Refinery throughputs on own account		34.80			31.96			30.01
of which: refinery throughputs of equity crude on own account		5.02			6.54			6.39
Total sales of refined products		46.80			45.02			48.33
Crude oil sales		36.17			32.10			36.56
TOTAL SALES		82.97			77.12			84.89

In 2012, refining throughput was 30.01 mmtonnes, decreased of 1.95 mmtonnes, or 6.1% versus 2011. Processed volumes in Italy, decreased of 7.8% compared to 2011, due to scheduled shutdowns in order to mitigate negative scenario impact mainly in Gela (shutdown of two production lines since June 2012) and Taranto (TSTC shutdown). Throughput reduction is partly offset by higher volumes processed in Venice ( shutdown from November 2011 to April 2012). Outside Italy, Eni’s refining throughputs increased by 3.2% (approximately 160 ktonnes) in particular in CRC for the Litvinov refinery shutdown in 2011. Wholly-owned refineries throughput is 20.84 mmtonnes, decreased of 1.91 mmtonnes (down 8.4%) versus 2011 with a refinery utilization rate of 73%, in reduction versus 2011 according to negative scenario. Approximately 22.8% was supplied by segment representing a 0.5 percentage point increase from 2011 (22.3%).

Eni’s Exploration & Production segment supplied approximately 22.8% of crudes, up 0.5% versus 2011.

 

Logistics

Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 20 directly managed storage sites and a network of petroleum product pipelines for products sale and storage of LPG and crude. Located in the Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) sites, they reduce logistic costs, and increase efficiency.

Eni’s logistic model is based on a hub structure covering five main areas. These hubs monitor and centralize products flows in order to lower collection and delivery costs. Eni holds five partnerships with major Italian operators.

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 1,447-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		2010		2011		2012

(mmtonnes)

Italy
Retail		8.63		8.36		7.83
Wholesale		9.45		9.36		8.62
		18.08		17.72		16.45
Petrochemicals		1.72		1.71		1.26
Other sales		7.21		6.58		6.08
Total		27.01		26.01		23.79
Outside Italy
Retail		3.10		3.01		3.04
Wholesale		4.30		4.27		4.38
		7.40		7.28		7.42
Other sales		12.39		11.73		17.12
Total		19.79		19.01		24.54
TOTAL SALES		46.80		45.02		48.33

In 2012, sales volumes of refined products (48.33 mmtonnes) increased by 3.31 mmtonnes from 2011, up 7.4%, due mainly to increased volumes sold to oil companies and traders outside Italy.

 

Retail sales in Italy

In 2012, retail sales in Italy of 7.83 mmtonnes decreased by approximately 530 ktonnes, down 6.3%, from 2011 driven by lower consumption of gasoil and gasoline, in particular in highway service stations related to the decline in freight transportation. Average gasoline and gasoil throughput (1,976 kliters) decreased by approximately 197 kliters from 2011. Eni’s retail market share for 2012 was 31.2%, up 0.7 percentage points from 2011.

At December 31, 2012, Eni’s retail network in Italy consisted of 4,780 service stations, 79 more than at December 31, 2011 (4,701 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (92 units) and the opening of new service stations (10 units), partly offset by the closing of service stations with low throughput (23 units).

In 2012, sales of premium fuels (fuels of the "Eni Blu+" line with high performance and lower environmental impact) were also affected by the decline in domestic consumption and were lower than the previous year. In particular, sales of Eni bludiesel+ amounted to approximately 292 ktonnes (approximately 350 mmliters) with a decline of approximately 201 ktonnes from 2011 and represented 6% of volumes of gasoil marketed by Eni’s retail network. At December 31, 2012, service stations marketing BluDiesel+ totaled 4,123 units (4,130 at 2011 year-end) covering approximately 86% of Eni’s network. Retail sales of BluSuper+ amounted to 35 ktonnes (approximately 47 mmliters), decreasing by 27 ktonnes from 2011, and covered 1.5% of gasoline sales on Eni’s retail network (down 0.9% from a year ago). At December 31, 2012, service stations marketing BluSuper+ totaled 2,505 units (2,703 at December 31, 2011), covering approximately 52% of Eni’s network.

Within the initiatives aimed to spur consumption in a negative economic scenario and create sounder customer relationships, Eni launched two relevant campaigns: (i) in the summer of 2012 for twelve weekends in Eni stations the "riparti con eni" initiative provided customers in the hyperself mode of service an exceptionally lower price equal all over the Country; and (ii) the launch of a new "loyalty card", consisting in reloadable, prepaid and credit card versions, through which customers can accumulate many more points in the Eni and Agip branded service stations that can be used for all daily purchases made outside of the Eni network in over 30 million stores.

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Retail sales in the rest of Europe

Eni’s strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany, Austria and Eastern Europe (e.g. Czech Republic) leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities.

In 2012, retail sales of refined products marketed in the rest of Europe (3.04 mmtonnes) were basically stable (up 1%). Volume additions in Austria and Switzerland reflecting successful commercial policies were almost completely offset by lower sales in Eastern Europe due to declining demand.

At December 31, 2012, Eni’s retail network in the rest of Europe consisted of 1,604 service stations, an increase of 18 units from December 31, 2011 (1,586 service stations). The network evolution was as follows: (i) the closing of 28 low throughput service stations mainly in Austria and France; (ii) the positive balance of acquisitions/releases of lease concessions (33 units) in particular in Austria; (iii) the purchase of 11 service stations, in particular in Austria; and (iv) the opening of 2 new outlets. Average throughput (2,319 kliters) increased by 20 kliters from 2011 (2,299 kliters).

The key markets of Eni’s presence are: Austria with a 11.7% market share, Hungary with 11.9%, Czech Republic with 10.8%, Slovakia with 9.7%, Switzerland with 7.1% 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 1,083 service stations (Eni owned network), of which 320 are in Germany, 208 in Austria and 135 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 high quality Eni standard, 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 all over Italy and articulated in local marketing offices and a network of agents and concessionaires.

In 2012, sales volumes on wholesale markets in Italy (8.62 mmtonnes) declined by approximately 740 ktonnes, down 7.9%, mainly due declining sales of gasoline and gasoil related to a decline in demand from transports and industrial customers due to a generalized slowdown and lower jet fuel sales related to declining demand. Bitumen sales increased due increased product availability of Eni products related to downtime in competing refineries, in particular in the final part of the year. Average market share in 2012 was 29.5% (28.6% in 2011). Supplies of feedstock to the petrochemical industry (1.26 mmtonnes) dropped from 2011 (down 450 ktonnes) due to lower demand from industrial customers. Wholesale sales in the rest of Europe of approximately 3.96 mmtonnes increased by 3.1% from 2011 due to increased sales in Switzerland, the Czech Republic, Slovenia and France. Sales declined in Hungary, Austria and Germany. Other sales (23.20 mmtonnes) increased by 4.89 mmtonnes, or 27%, mainly due to higher sales volumes to oil companies.

Eni also markets jet fuel directly at 45 airports, of which 26 are in Italy. In 2012, these sales amounted to 2.0 mmtonnes (of which 1.6 mmtonnes are in Italy). Eni is also active in the international market of bunkering, marketing marine fuel mainly in 106 ports, of which 72 are in Italy. In 2012, marine fuel sales were 1.75 mmtonnes (1.67 mmtonnes in Italy).

 

LPG

In Italy, Eni is leader in LPG production, marketing and sale with 614 ktonnes sold for heating and automotive use equal to a 19.8% market share. An additional 206 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 4 owned storage sites, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna.

Outside Italy, LPG sales in 2012 amounted to 515 ktonnes of which 389 ktonnes in Ecuador where LPG market share is around 37.8%.

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Lubricants

Eni operates six (owned and co-owned) blending plants, in Italy, Europe, North and South America, Africa 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 2012, retail and wholesale sales in Italy amounted to 96 ktonnes with a 24.3% market share. Eni also sold approximately 4 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 140 ktonnes, of these about 60% were registered in Europe (mainly Spain, Germany, Austria and France).

 

Oxygenates

Eni, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 1.10 mmtonnes/y of oxygenates, mainly ethers (approximately 3.1% of world demand) and methanol (approximately 0.6% of world demand). About 76% of oxygenates are produced in Eni’s plants in Italy (Ravenna), in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic) and the remaining 24% 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. Starting from March 1, 2010, Italian regulation on bio-fuels minimum content changed from 3% to 3.5%.

From January 1, 2012, the compulsory content of bio-fuels increases to 4.5% from 2011 4% and through Bio-ETBE and bio-diesel (of 1^st and 2^nd generation) blending into fossil fuels Eni covered the compliance within 109.6% in 2012.

Eni plans to cover compliance through Bio-ETBE, FAME, green diesel from Porto Marghera site, and direct blending of ethanol in gasoline in particular in some extents of Sannazzaro refinery inland.

 

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 43%), and Saipem’s controlled entities. Saipem boasts a strong competitive position 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 petrochemicals plants, pipeline laying and offshore and onshore drilling services. The Company owes its market position to technological and operational skills which we believe are acknowledged in the marketplace due to its capabilities to operate in frontier areas and complex ecosystems, efficiently and effectively managing large projects, engineering competencies and availability of technologically-advanced vessels and rigs which have been upgraded in recent years through a large capital expenditure plan. Despite the above mentioned factors, in the short term the profitability prospects of this business are expected to be adversely affected by the conclusion of highly-profitable projects, an anticipated slowdown in order acquisitions and the start of lower margin projects in the Onshore and Offshore Engineering & Construction businesses.

Management expects a weak profitability outlook in 2013 due to the completion of highly-profitable orders, a slowdown in activities at the Onshore and Offshore construction business units as well as the start-up of low-margin works.

However management believes that medium to long-term prospects of the business remains sound.

Management expects to preserve Saipem’s competitive position in the medium term, leveraging on its business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. In particular Saipem plans to implement the following

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strategic guidelines: (i) to maximize efficiency in all business areas at the same time maintaining top execution and security standards, preserve competitive supply costs, optimize the utilization rate of the fleet, increase structure flexibility in order to mitigate the effects of negative business cycles as well as develop and promote a company culture that will permit identification and management of risks and business opportunities; (ii) to continue focusing on the more complex and difficult projects in the strategic segments of deepwater, FPSO, heavy crude and LNG (offshore and onshore, for the gas monetization) upgrading; (iii) to promote local content in terms of employment of local contractors and assets in strategic countries where large projects are carried out supporting the development of delocalized logistic hubs and construction yards when requested by clients in order to achieve a long-term consolidation of its market position in those countries; (iv) to leverage on the capacity to execute internally more phases of large projects on an EPC and EPIC basis, pursuing better control of costs and terms of execution adapting with flexibility to clients’ needs, thus expanding the Company’s value proposition; and (v) to complete the expansion and revamping program of its construction and drilling fleet in consideration of the future needs of the oil&gas industry, in order to confirm the Company’s leading position in the segment of complex projects with high profitability.

Saipem expects to invest approximately euro 2.8 billion over the next four years to complete the upgrading program of its fleet of vessels and rigs, further expanding the operational features, the dimension and the geographical reach and of its fleet as well as to support the activities related to the execution of projects in portfolio and the acquisition of new orders.

Orders acquired amounted to euro 13,391 million as of December 31, 2012 (euro 12,505 million as of December 31, 2011), of these projects to be carried out outside Italy represented 96%, while orders from Eni companies amounted to 5% of the total. Order backlog amounted to euro 19,739 million at December 31, 2012 (euro 20,417 million at December 31, 2011), of these projects to be carried out outside Italy represented 91%, while orders from Eni companies amounted to 13% of the total.

		2010		2011		2012

Orders acquired		(euro million)		12,935		12,505		13,391
Engineering & construction offshore				4,600		6,131		7,477
Engineering & construction onshore				7,744		5,006		3,972
Offshore drilling				326		780		1,025
Onshore drilling				265		588		917
Originated by Eni companies		(%)		7		7		5
To be carried out outside Italy		(%)		94		91		96
Order backlog and breakdown by business		(euro million)		20,505		20,417		19,739
Engineering & construction offshore				5,544		6,600		8,721
Engineering & construction onshore				10,543		9,604		6,701
Offshore drilling				3,354		3,301		3,238
Onshore drilling				1,064		912		1,079
Originated by Eni companies		(%)		16		14		13
To be carried out outside Italy		(%)		94		91		91

 

Engineering & Construction offshore

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 EPIC 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. Over the next years, Saipem will invest in the upgrading of its fleet, the construction of a large construction yard in Brazil and the acquisition of new rigs in the drilling segments.

Saipem’s offshore construction fleet is made up 35 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 dynamic 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 2012 in Engineering & Construction offshore construction were: (i) the EPCI contract with INPEX for the installation of an underwater pipeline 889-kilometer long linking the offshore Ichthys field with the onshore shut-off valves in the area of Darwin, Australia; (ii) an EPCI contract with Lukoil for the installation of two underwater pipelines linking the offshore Vladimir Filanovsky block in the northern area of the Caspian Sea, with the onshore facility 20 kilometers inland in the Russian Republic of Kalmyk. Works offshore will be performed mainly by the pipelaying barge Castoro 12 and the trenching vessel Castoro 16; and (iii) an EPIC contract with Petrobras for the project Sapinhoa Norte and Cernambi Sul, within the development of the Pre-Salt Risers in the Santos Basin, approximately 300-kilometer off the coasts of the Rio de Janeiro and Sao Paulo states, Brazil, in water depths of 2,200 meters.

 

Engineering & Construction onshore

In the Engineering & Construction onshore construction business, Saipem is one of the largest operators on turnkey contract base at a worldwide level in the oil&gas segment, especially through the acquisition of Snamprogetti. 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 its technology excellence granted by 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 2012 in Engineering & Construction onshore were: (i) a turn-key contract for Shell concerning the SSAGS (Southern Swamp Associated Gas) project related to the construction of four compression stations and new production facilities for the treatment of collected gas in various areas of the Delta State in Nigeria; (ii) an EPC contract for Saudi Aramco and Sumitomo Chemical for the Naphtha and Aromatics Package (RP2) of the Rabigh II project which provides for the expansion of the integrated petrochemical and refining complex of Rabigh, a city located on the western coast of Saudi Arabia; and (iii) an EPC contract for Transportadora de Gas Natural Norte-Noroeste (a wholly-owned Transcanada subsidiary) for a 30 inches in diameter and approximately 550-kilometer long pipeline between El Encino, located in the Chihuahua State, to Topolobampo, in the Sinaloa State on the western coast of Mexico.

 

Offshore drilling

Saipem is the only engineering and construction contractor that 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 order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. 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 18 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. In 2010, those vessels operated in West Africa and Far East. Other relevant vessels are Scarabeo 8 and 9, sixth generation semi-submersible rigs able to operate at depths of 3,000 and 3,600 meters of water, respectively. Average utilization of drilling vessels in 2012 stood at 100% (100% in 2011).

The most significant orders awarded in 2012 in Offshore drilling were: (i) the 15-month extension of the drilling contract of the Scarabeo 7 operating offshore Indonesia; (ii) the 24-month extension of the contract of the Perro Negro jack-up operating offshore Italy; and (iii) the 36-month lease contract of Scarabeo 5 operating in the Northern Sea.

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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 2012 stood at 97.2% (96.1% in 2011). The 92 rigs (in addition to 5 rigs under completion) owned by Saipem at year end were located as follows: 28 in Venezuela, 18 in Peru, 12 in Saudi Arabia, 7 in Colombia, 6 in Algeria, 5 in Kazakhstan, 4 in Bolivia, 4 in Ecuador, 3 in Brazil, 2 in Congo, 1 in Italy, 1 in Ukraine and 1 in Mauritania and Saipem also used rigs owned by third parties (6 in Peru, 3 in Kazakhstan and 1 in Congo) as well as rigs owned by the joint company Saipar.

The most significant orders awarded in 2012 in Onshore drilling were: (i) a contract on behalf of Saudi Aramco for the lease of 15 facilities for a term ranging from three to five years in Saudi Arabia; and (ii) the contracts for 8 facilities to be employed in South America, Saudi Arabia, Kazakhstan, Algeria, Mauritania and Italy for periods ranging from 2 months to two years.

 

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.

Eni’s strategy in its chemical business is to effectively and efficiently manage operations in order to lower the break-even considering the volatility of costs of oil-based feedstock, cyclicality in demand, strong competitive pressures from operators with lower cost structure especially in the Middle and Far East, taking into account the commoditized nature of many of Eni’s products.

In fact, Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. See "Item 3 – Risk factors".

In 2012, the Chemical segment reported sharply higher operating losses from 2011 mainly reflecting the fall in commodities demand due to the economic downturn and the unprofitable product margins of oil-based commodities which were squeezed by high crude oil costs.

Management expects that a weak macroeconomic outlook for 2013 which will weigh on a rebound in demand for petrochemical products while ongoing trends in crude oil prices could pressure unit margins of commodities. In light of this, management is planning to implement a strategy intended to refocusing the chemical business, reducing the exposure to loss-making commodity chemicals while at the same time developing innovative and niche productions which are expected to yield better returns such as elastomers and the expansion of the specialties segment.

We intend to grow the green chemistry business leveraging on the ongoing project of converting our Porto Torres site in a modern plant for the manufacture of eco-compatible chemical products. This will allow us to: (i) diversify its petrochemical core business in the direction of an innovative sector with very high potential, supplying products with low environmental impact; and (ii) settle the issues at critical industrial sites, re-qualifying and restructuring them.

In 2012 Matrìca SpA, a new 50-50 joint venture with Novamont, started the construction of the first two plants of the Green Pole project (bio-monomers and bio-lubricants). When fully operational in 2016-2017, the pole will include 7 plants and one research centre, with a total expenditure of approximately euro 500 million (including interventions on local infrastructure). New research lines have been activated in the area of products from renewable sources. In this field, Eni signed an agreement with Genomatica, a company active in bio-technologies.

Management expects sales of higher value added and bio-based products to improve consistently, with a contribution on total sales amounting to 50% in a long-term scenario.

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The Company will also leverage on international expansion especially in Asia and Latin America trough licensing activities, product alliances and joint ventures. In 2012, Versalis signed strategic alliances in Asia, supported by our technological know-how and the enhancement of Eni’s proprietary technology platform.

The Company’s strategy will also continue to leverage on efficiency actions to reduce operating costs and on the rationalization program of our plants in order to improve yields and efficiency, restructuring our unprofitable sites, in particular cutting the Company’s ethylene and polyethylene capacity.

Based on the planned initiatives, management expects its chemical operations to break-even in the next four-year period.

To target those objectives, management plans to make selective capital expenditures amounting to approximately euro 1.9 billion over the next four year. The main investment will target the conversion of the Porto Torres unit in Sardinia, Italy, into an innovative bio-based chemical complex to produce bio-plastics and other bio-based chemical products. In addition, the Company plans to develop the product line in the elastomers and intermediates businesses, upgrade and revamp the Company’s cracking units as well as complying with all applicable regulations on environment, health and safety issues.

In 2012, sales of chemical products (3,953 ktonnes) decreased by 87 ktonnes (down 2.1%) from 2011 mainly due to a substantial decrease in demand reflecting the current economic downturn in the main reference markets. Average unit sales prices increased slightly (up 1.3%) from 2011, in particular aromatics (up 12%), phenol derivatives (up 10%) and styrene (up 6%). Elastomer average unit prices declined (down 1.3%).

Chemical production (6,090 ktonnes) decreased by 155 ktonnes from 2011, or 2.5%. Main decreases were registered in styrenes and elastomers (down 10.3% and 9.4%, respectively). Excluding the shutdown of the Porto Torres plant (except for nytrilic rubber) for the start of the green chemistry project and the divestment of the Feluy plant, volumes increased by approximately 2%.

Outside Italy, production increased at the Dunkerque site (up 20%) that in 2011 had been affected by a slow start of the new EVA/LDPE swing line. Nominal capacity of plants declined from the previous year due to the mentioned divestment of the Feluy plant and the shutdown of the Porto Torres plant, while the average plant utilization rate, calculated on nominal capacity, was 66.7% (65.3% in 2011).

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

	Year ended December 31,

		2010		2011		2012

(ktonnes)

Itermediates		4,860			4,101			4,112
Polymers		2,360			2,144			1,978
Total production		7,220			6,245			6,090
Consumption and losses		(2,912	)		(2,631	)		(2,545	)
Purchases and change in inventories		423			426			408
		4,731			4,040			3,953

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

	Year ended December 31,

		2010		2011		2012

(euro million)

Itermediates		2,833			2,987			3,110
Polymers		3,126			3,299			3,128
Other revenues		182			205			180
Total revenues		6,141			6,491			6,418

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Intermediate

Intermediate revenues (euro 3,110 million) increased by euro 123 million from 2011 (up 4%) due to the positive performance of derivatives, reflecting increased sales volumes (up 21%) and average unit prices (up 10%) due to a more dynamic market and product availability. Sales volumes of olefins and aromatics declined (down 2% and 4.5%, respectively) due to the shutdown of the polyethylene line in the Sicilian plants due to their lack of profitability and demand decline. Average unit prices of olefins were stable, while aromatics prices increased by 12% driven by the price of benzene (up 18.7%).

Intermediates production (4,112 ktonnes) was in line with last year (up 0.3%). An increase was registered in derivatives (up 12%) for phenol derivatives and styrene monomer that last year had been affected by the planned facility downtimes at the Mantova plant.

Production of olefins and aromatics declined (down 2.7% and 5.4%, respectively). The latter were affected by the planned facility downtime at the Sarroch plant and the decline in activity at the Priolo plant aimed at countering the negative scenario.

 

Polymers

Polymer revenues (euro 3,128 million) decreased by euro 171 million from 2011 (down 5.2%) due to decreased sales volumes (down 5.8%) resulting from a steep decline in demand in particular on Italian and European markets, offset in part by slight increases in the markets of Eastern Europe.

Unit prices of elastomers declined (down 1.3%) due to lower unit prices for SBR rubbers, affected by the downturn of the automotive industry and of polyethylene (down 0.4%), despite an improvement in the second part of the year. Average styrene prices increased by 6%, driven by the price of expandable polystyrene.

Polymer production (1,978 ktonnes) decreased by 167 ktonnes from 2011 (down 7.8%), due mainly to a decline in elastomer production (down 9.4%) at Ravenna and Ferrara for the downturn of the automotive industry and of polyethylene (down 6%). At the beginning of the year production at the Sicilian plants was shutdown, including the cracker, due to the sharp decline in demand for polyethylene.

The decline in styrene production (down 10.3%) was due to the divestment of compact and expandable polystyrene plant of Feluy (Belgium) at the end of 2011.

 

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 Adfin SpA, Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance Ltd, Eni carries out cash management activities lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an inter-company 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.

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Seasonality

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

 

Research and development

Technological research and development ("R&D") and continuous innovation represent key success factors in implementing Eni’s business strategies as they support our long-term competitive performance.

The Company believes that the oil industry has to face a number of challenges in the near future and that technology will play a vital role in helping it to effectively manage them. In particular:

•		continuing uncertainty about the future evolution of prices and demand for oil&gas;
•		limited access to new hydrocarbon resources, with the consequent problems for production growth and reserve replacement; increasing role for unconventional oil&gas resources and basins;
•		a growing importance of renewable sources in satisfying energy need; and
•		greater attention to operations safety and energy efficiency increase in the industry.

Eni has identified a number of key technological guidelines:

•		improving the ability to describe the subsoil and to estimate the amount and quality of fluids contained in sedimentary fields, with special focus on the most complex areas;
•		targeting operating excellence, in particular in frontier fields, in terms of operational safety and reduced environmental impact;
•		increasing the hydrocarbon recovery factor, both in conventional and unconventional oil reservoirs;
•		exploiting unconventional and marginal gas reservoirs, as well as allowing the up-grading of poor gas (for example with high CO2 content);
•		allowing the upgrading of unconventional oil (extra-heavy crude and bitumen), increasing the yield and quality of the distillates and at the same time eliminating the production of fuel oil and by-products;
•		producing high quality fuels with low environmental impact, as well as developing bio-fuels that do not compete with the food supply chain;
•		reducing the polluting potential of the hydrocarbon operating activities both locally (e.g. treatment of production water and industrial waste, sludge management) and globally (reduction of CO2 emissions);
•		efficiently and effectively converting renewable energy sources, especially solar and bio-mass energy, into electrical energy or energy vectors; and
•		promoting the Sustainable Chemistry business, for example by introducing bio-components into the pool of petrochemical products.

In 2012, Eni filed 74 patent applications (79 in 2011), 44 of these coming from Eni’s segments and Eni Corporate, 17 from Versalis and 13 from the Engineering & Construction activities of Saipem.

In 2012, Eni’s overall expenditure in R&D amounted to euro 211 million which were almost entirely expensed as incurred (euro 190 million in 2011 and euro 218 million in 2010).

The overall expenditure toward academic institutions and research centers amounted to euro 30 million in 2012. In 2011, Eni signed a new agreement with Stanford University which will develop a research program focused on oil&gas technologies and environmental issues for an overall expenditure of $10 million over the next four years. At the beginning of 2013, the agreement between Eni and MIT was renewed for 4 years and a total amount of $20 million.

At December 31, 2012, a total of 975 persons were employed in research and development activities. Below, we describe the main results achieved in the development and application of innovative technologies in 2012.

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Exploration & Production

- Eni Common Reflection Surface Stack (e-crs™). The proprietary seismic processing technology enhances the signal/noise ratio in challenging imaging areas. In 2012, its application in Pakistan allowed the successful placement of the discovery well Badhra B North-1.

- Reverse Time Migration (RTM)@60Hz. The Eni proprietary technology for seismic data processing was enhanced to process high frequency seismic data. This technology allowed the reconstruction of the subsoil image in highly complex areas, where the potentially mineralogical structure is "hidden" by layers of salt, faults, or overlying channels. In 2012, the new version was successfully applied in Angola and Ghana.

- Coastal Oil Spill Preparedness Improvement Program in the Barents Sea and sub-Arctic areas. The emergency plan developed for the Goliat field in the Barents Sea was completed and tested, verifying all the operative phases needed to contain an oil spill. The test involved the operator Eni, the partner, and the Norwegian Clean Seas Association for Operating Companies (NOFO) as well as other staff and resources of the private and public sectors. In particular, coast cleaning methods were tested and new methodologies for a rapid response were implemented by using vessels normally dedicated to fishing activities. The Norwegian Authorities appointed the Goliath project as a reference standard for future initiatives in the area.

- Pump power supply in desert locations using photovoltaic systems. The realization of a hybrid fossil/solar plant, located in the Aghar field (Egypt), was completed for the power supply of artificial lift systems (Sucker Rod Pumps). This technology allows fuel savings during the production phase through the parallel use of photovoltaic panels and traditional power generator.

 

Gas & Power

- Eni Kassandra Meteo Forecast (e-km™). Since 2009, Eni has been developing a short-long term proprietary meteorological forecast system in collaboration with EPSON Meteo, which can be used for managing energy resources and improving the power generation process. This system for forecasting temperatures trend on global and regional scale, from 1 to 90 days, provides an innovative solution towards statistical systems. In 2012, the system was further developed to expand the geographical coverage in Europe, and it was used by all EniPower’s power plants and the gas market selling in Italy.

- Eni Vibroacoustic Pipeline Monitoring System (e-vpms™). The Eni proprietary technology allows a continuous detection of third-party intrusions and leaks in fluid filled pipelines by a remote control station. In 2012, the technology has been successfully tested in Italy on transportation pipelines for crude oil, products and natural gas.

 

Refining & Marketing

- Green Refinery. The project Green Refinery was launched for the conversion of the Venice plant into a "bio-refinery", using the Ecofining^TM technology, (co-patented by Eni and UOP), aimed at the production of innovative and high quality bio-fuels by the conversion of various organic feedstock (such as vegetable oils, animal fats, cooking oils, oils from algae). The project, which investment is estimated in euro 100 million, is the first case in the world for the conversion of a conventional refinery into a bio-refinery.

- Zero Waste. The technology is based on a thermal process for the treatment of industrial oily and biological residues generated by the petroleum industry production activities. The process was validated on a pilot scale plant. The main environmental benefits obtained are: (i) a reduction of the waste to be disposed >90%; and (ii) a production of a syngas capable both to thermally self-support the process and (in case of surplus with respect to the self-sustaining) to recover hydrocarbons from the sludge.

 

Versalis

Joint venture Genomatica-Novamont. In June 2012, a Memorandum of Understanding was signed with Genomatica and Novamont, for the creation of a joint venture based in Italy. The joint research program, which will last four years, focuses on the development of a new technology for the production of butadiene from renewable sources. The joint venture will also hold exclusive rights for the industrial exploitation of research results including the licensing activities of the technology to a third party.

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Eni Corporate

- Photoactive materials. A Luminescent Solar Concentrator consists of a slab of transparent material (acrylic or glassy) to which fluorescent molecules, patented by Eni, are added acting as microscopic light emitters. The emitted radiation is partially confined within the slab by total internal reflections and is waveguided and concentrated toward its edges where PV cells are placed. The positive results obtained at lab level allowed the construction of the first demonstration unit, which consists in a photovoltaic shelter to park and re-charge electrical bicycles.

 

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 a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni makes recourse to insurance companies who we believe are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.1 billion for offshore events and $1.5 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1 billion for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment and FPSOs used by the Exploration & Production segment for developing offshore fields; $500 million for time charters.

Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one occurred in the Gulf of Mexico in 2010 which could have a material impact on our results and liquidity. 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 the safety of the workplace and health of communities 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.

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

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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 (Environmental Code). The Environmental Code sets up rules that refer to: Environmental Impact Assessment (EIAs), the Integrated Prevention and Pollution Control (IPPC), procedures for Strategic Environment Assessment (SEA), 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 has been subject to a number of amendments. The most important changes introduced regarded reclamation and remediation activities as this Decree provided a site-specific risk-based approach to determine objectives of reclamation and remediation projects, cost-effective analysis required to evaluate remediation solutions, and criteria for waste classification. In 2012 the application of the Integrated Environmental permit under IPPC regulation was extended to all off-shore Italian platforms. Furthermore, by the end of 2013, the environmental law will be updated again in order to transpose the Directive on industrial emissions No. 2010/75/UE (IED directive).

In 2012, Law No. 35 of April 4, 2012, was enacted to introduce certain innovations in the environmental regulation regarding administrative procedures (with particular reference to Integrated Environmental Authorization and Environmental Impact Assessment). The law delegates the Government to approve a regulation on the unique environmental authorization to simplify procedures and reduce costs for small and medium-sized enterprises. In fact such a regulation was approved in February 2013, and a Unique Environmental Authorization (AUA) is now in force. AUA is dedicated to environmental businesses and installations not subject to integrated environmental authorization and greatly simplifies the administrative burden, in particular for small and medium-sized enterprises; the new authorization replaces up to seven different procedures.

Other significant legislation includes Criminal offences relating to the environment – Legislative Decree No. 231 of June 8, 2001, as recently 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. Particularly, the Italian legislator broadened the scope of corporations’ liabilities for the crimes committed by employees to include crimes relating the illicit discharge of industrial waste water, violations in reporting, record keeping and other omitted evidence in the matter of waste, unauthorized waste management, illegal trafficking of waste, as well as crimes relating the application in Italy of the Convention on International Trade in animal and plant species threatened with extinction, violations of measures intended to protect stratospheric ozone and the environment and pollution caused by ships.

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 February 12, 2013, Legislative Decree No. 250/2012 amending Legislative Decree No. 155/2010 transposing Directive No. 250/2008/EC on air quality entered in force. The changes introduced by the new decree were necessary to overcome some critical points appeared in the first phase of application of the new discipline and to better regulate the relations with local governments and to better define the role of the Institute for Environmental Protection and Research (ISPRA).

Italy has regulated the Emission Trading System by Legislative Decree No. 216 of April 4, 2006, amended by Legislative Decree No. 257 of December 30, 2010, transposing requirements of Directive No. 2008/101/EC. In 2012, a pattern of legislative decree implementing Directive No. 2009/29/EC (amending Directive No. 2003/87/EC to extend the Community trading system of CO₂ emission) was prepared and is expected to be approved by the Government. Moreover on November 13, 2012, the National Committee on implementation of the Directive No. 2003/87/EC has approved the Deliberation No. 27 on monitoring and communication of GHG according to Commission Regulation No. 601/2012.

Decree No. 205/2010 implemented the Directive No. 2008/98/EC about waste and adopted SISTRI (an automated tracking system of special and hazardous waste). This new system aimed at real time monitoring of the route of waste from production through disposal/recycling, also prosecuting any unlawful act in waste management, and was expected to be fully implemented by June 2012. Law No. 234/2012 extended the application of the previous documental tracking system, in order to check the adequacy of the implemented choices, forwarding the start-up of the new system up to June 30, 2013.

On October 5, 2011, Legislative Decree No. 162/2011 implementing Directive No. 2009/31/EC (CCS Directive) came into force. The decree represents a key point to launch and support, from an institutional point of view, the implementation of demonstrative projects which are finalized to investigate and analyze from a scientific point of view, the technological aspects of the CCS, in order to optimize current technologies or to find new solutions with a marginal and sustainable economic impact for the capture and storage processes.

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Legislative Decree No. 81/2008 concerned the protection of health and safety in the work place and was designed to regulate the work environments, equipments and individual protection devices, physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees.

On November 23, 2011, the legislation regulating works in confined spaces has come into effect (Decree No. 177/2011), in application of Legislative Decree No. 81/2008.

Moreover, during 2012 some specific decrees were published to implement the Legislative Decree No. 81/2008:

•		Ministerial Decree of November 30, 2012 implementing Article 29 of Legislative Decree No. 81/2008, on standardization of the evaluation methods for health and safety risk assessment;
•		Ministerial Decree of August 6, 2012 which replaces the previous Annex XXXVIII to Legislative Decree No. 81/2008, on limit values of professional exposure to some substances; and
•		Ministerial Decree of February 16, 2012, No. 51, implementing Article 3 of Legislative Decree No. 81/2008 on health and safety protection at the workplace abroad.

Furthermore, as to Legislative Decree No. 81/2008, at the end of 2011 a specific Italian national agreement (between different government bodies) on training on health and safety at work entered into force. As a consequence, in 2012 Eni has defined a dedicated compulsory training model and started the related training activities, which were dedicated to the various Company’s roles (e.g. Safety managers – as defined by the Italian legislation – managers and employees) and differentiated according to the levels of risk of Company’s activities.

Moreover, it is important to note that at regional level Italian local authorities are appealing more often to Health Impact Assessment (HIA) and are integrating this procedure with Environmental Impact Assessment (EIA) and Strategic Impact Assessment (SIA). During 2012, a strong correlation has been observed between health issues and environmental aspects. In fact, various HIA, SIA and EIA methodologies are being developed as a unique regulation (e.g. "Cervellera Law" in Puglia Region). Eni is involved in an internal multidisciplinary project on health and environmental assessment of plants impacts.

The complexity and scale of situations and contexts where Eni is operating requires the adoption of business processes, guidelines and principles for improving its performance in health and prevention. To this end Eni upholds:

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

 

European Union

Since January 2012, according to the Directive No. 2008/101/EC, emissions from international aviation are included in the EU Emission Trading System (EU ETS). Like industrial installations covered by the EU ETS, airlines receive tradable allowances covering a certain level of CO₂ emissions from their flights per year.

On June 21, 2012, the Commission adopted two Regulations on monitoring and reporting of greenhouse gas 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 October 26, 2012, the Commission adopted a proposal for a new directive on EIA (Environmental Impact Assessment) that would amend the current Directive. The proposal is intended to facilitate the assessment of potential impacts, without weakening existing environmental safeguards and to reinforce the decision-making process and improve current levels of environmental protection. Moreover a new proposal updates EIA with emerging challenges in areas like resource efficiency, climate change, biodiversity and disaster prevention that will be reflected in the assessment process.

On December 17, 2012, the Directive No. 2012/33/EC on sulphur content in marine fuels has entered into force. The directive modifies the Directive No. 1999/32/EC and brings EU regulations in line with current International Maritime Organization (IMO) regulations for sulphur emissions from ships under Marpol Annex VI. The new directive has not only updated with IMO limits for sulphur in emission control areas (ECA), but it also promotes a

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stronger monitoring and enforcement regime to improve compliance, possibly with stricter penalties, along with a reference to IMO procedures for sulphur verification that opens the door to a stricter interpretation of what is common in the EU at present.

According to the new directive, the sulphur limit in ECAs is now 1.00%, falling to 0.10% in 2015 (before it was 1.5%) and marine fuels used in the EU must meet the global 3.50% sulphur limit, except for on ships using an exhaust gas cleaning system (EGCS) operating in closed mode.

Member States have time until June 18, 2014 to bring into force the laws, regulations and administrative provisions necessary to comply with the revised sulphur directive.

On November 15, 2012, European Commission presented a Blueprint to Safeguard Europe’s Water Resources that outlines actions that concentrate on better implementation of current water legislation, integration of water policy objectives into other policies, and filling the gaps in particular as regards water quantity and efficiency.

In November 2012, the European Parliament rejected the proposal for a moratorium on shale gas and endorsed two reports: on the environmental impacts of shale gas extraction and on its industrial and energy aspects. Studies carried out indicate that there are a number of uncertainties or gaps in current EU legislation and the Commission intends to deliver next year a framework to manage risks, address regulatory shortcomings, and to provide maximum clarity and predictability to market operators and citizens across the EU.

On October 25, 2012, the EU adopted the Directive No. 2012/27/EU on energy efficiency which establishes a common framework of measures for the promotion of energy efficiency within the Union in order to ensure the achievement of the EU’s 20-20-20 headline target on energy efficiency. The directive is a game-changer for energy companies, which are now required to achieve 1.5% energy savings every year among their final clients. The EU law is also expected to trigger the largest revamp of Europe’s existing building stock to date and set new standards for public procurement and energy audits. EU countries are requested to draw up a roadmap to make the entire buildings sector more energy efficient by 2050 (commercial, public and private households included). In the first half of 2014, the Commission will review the progress towards the 20% energy-efficiency target, report on it and assess whether further measures are needed.

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 Chemical and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed by chemicals, while enhancing the competitiveness of the EU chemicals industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to European Chemicals Agency (ECHA) how the substance can be safely used and they must communicate the risk management measures to the users. If the risks cannot be managed, authorities can restrict the use of substances in different ways. Over time, the hazardous substances should be substituted with less dangerous ones. The deadline of REACH registration depends on the tonnage band of a substance and the classification of a substance; next deadline is 2013 and the last one 2018. Eni recognizes the importance of the Regulation REACH (CE) 1907/2006, 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 and compounds 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 (GHS). 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.

The European Commission has put forward its new Energy Policy for Europe - EPE, so-called "20-20 by 2020", a far-reaching package of proposals that will deliver on the European Union’s ambitious commitments to fight climate change, promote renewable energy and increase energy security. The following regulations were published in order to define the criteria for cutting emissions cost-effectively by 2020 compared with levels recorded in 2005:

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•		Directive No. 2009/28/EC: fixing target of 20% share of energy from renewable sources in 2020. It creates cooperation mechanisms so that the EU can achieve the targets in a cost effective way. It also includes a flat 10% target for renewables in transport (bio-fuels, "green" electricity, etc.); this legislation also sets out sustainability criteria that bio-fuels should meet to ensure they deliver real environmental benefits.
•		Directive No. 2009/29/EC: improves and extends to the third phase (2013-2020) the greenhouse gas emission allowance trading scheme of the European Community to provide for a more efficient, homogeneous and fair system. It defines criteria and targets for cutting GHG emissions from the sectors covered by the system (energy and manufacturing industries) by 21% by 2020 compared with levels in 2005. The Auctioning Regulation contains a set of rules for the auctioning processes that should be undertaken for the auction of allowances from 2013. On December 14, 2010, Climate Change Committee voted the benchmark decision, which describes the rules for the free allocation from 2013.
•		Directive No. 2009/30/EC: defines the fuel quality and places an obligation on suppliers to reduce greenhouse gases from the entire fuel life cycle of 6% by 2020, mostly by an increased use of bio-fuels.
•		Decision 2011/278/EU: implements transitional Union-wide rules for harmonized free allocation of emission allowances pursuant to Article 10a of Directive No. 2003/87/EC: legislation that set the benchmark for the quantification of the free allowances allocated to the industry. For industry and heating sectors, allowances will be allocated for free based on ambitious (greenhouse gas performance-based) benchmarks. Installations that meet the benchmarks (and thus are among the most efficient installations in the EU) will in principle receive all allowances they need.
•		Directive No. 2009/31/EC: defines a scenario in order to promote the development and safe use of Carbon Capture & Storage (CCS), a suite of technologies that allows the carbon dioxide emitted by industrial processes to be captured and stored underground.
•		Regulation 443/2009/EC: sets emissions standards for new passenger cars and targets a reduction to an average of 120 g CO2/km by 2015, decreasing to a stringent long-term target of 95 g CO2/km by 2020.
•		Decision 406/2009/EC: defines, for sectors not included in the EU ETS, such as transport, housing, agriculture and waste, emissions reduction target of 10% from 2005 levels by 2020 (the Italian reduction target is fixed at 13%).
•		Decision 540/2011/EC: amending Decision 2007/589/EC as regards the inclusion of monitoring and reporting guidelines for greenhouse gas emissions from new activities and gases.
•		Decision 2012/432/EC: on recognition of the "REDcert" scheme for demonstrating compliance with the sustainability of bio-fuels.

On December 17, 2010, the Directive No. 2010/75/EC on industrial emissions (IED) was published in the Official Journal of the European Union No. 334. The objective of the new directive is to avoid or to minimize polluting emissions in the atmosphere, water and soil, as well as waste from industrial and agricultural installations, and to achieve a high level of environmental and health protection. The Directive brings together the IPPC Directive (Directive No. 2008/1/EC) and six other sector-specific Directives (Large Combustion Plants, VOC – Volatile Organic Compounds – emissions, incineration of waste and titanium industry). The Directive contains special provisions for the combustion plants with thermal input below 50 MW. Any industrial installation which carries out the activities listed in Annex I must meet certain obligations, as preventive measures taken against pollution, minimum emission values, apply the best available techniques (BAT), monitoring rules and permit and reporting conditions. The Article 14 of the new Directive defines the permit necessary measures (as emission limit values for polluting substances, rules guaranteeing protecting of soil, water and air, suitable emission monitoring measures, waste monitoring and management measures, communication of monitoring results to the competent national authorities, requirements concerning the maintenance and surveillance of soil and groundwater, measures relating to exceptional circumstances as leaks, malfunctions, momentary or definitive stoppages, etc.). The Directive defines more restricting emission limits to be observed by the end of 2012, although includes some derogation, as the TNP Transitional National Plan and the option Opt-Out for those installations that are going to shut down their operations by 2023. On February 28, 2011, the European IPPC Bureau (EIPPCB) started the review process of the Reference Documents on Best Available Techniques for Large Combustion Plants "BREF-LCP" and in 2012 the consultation process was completed. On February 10, 2012, the Commission approved a implementing Decision 2012/119/EU laying down rules concerning guidance on the collection of data and on the drawing up of BAT reference documents and on their quality assurance referred to in Directive No. 2010/75/EU. Also on February 2012, the Commission implementing decision laying down rules concerning the transitional national plans referred to in Directive No. 2010/75/EU was published. Moreover in 2012, the EIPPCB published the Draft 2 Refining Bref and related BAT conclusion, which will be completed by the end of 2013 with the BAT conclusion. The Member States have to transpose the IED Directive into national legislation by December 2012. The Italian Government will adopt the IED directive into the Legislative Decree No. 152/2006 "Environment Regulation".

With the aim of taking the lead in the negotiations on the Climate Agreement after 2012, on March 15, 2011, the European Commission presented a Roadmap for transforming the European Union into the worldwide forerunner of low carbon economy by 2050. The Roadmap objective is cutting greenhouse gas emissions by 80-95% versus 1990 levels within 2050, by implementing cost effective measures aiming mostly at improving energy efficiency. The analysis takes into consideration costs and savings related to potential measures such as sector policies, national and regional low carbon strategies and long-term investments. On December 15, 2011, the European Commission adopted the Communication "Energy Roadmap 2050". This Communication takes into account "decarbonization scenarios":

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•		energy efficiency scenario;
•		diversified supply technologies scenario;
•		high renewable energy scenario;
•		delayed carbon capture and storage (CCS) scenario (a "high nuclear" pathway); and
•		low nuclear scenario (a "high CCS" pathway).

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 are still in place.

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

Following a resolution of the European Parliament of one year earlier, rejecting a moratorium on new oil platforms and requiring a single European system for prevention and response to intra-community oil spills, on October 27, 2011, the European Parliament proposed a new law which will ensure that European offshore oil and gas production will respect the world’s highest safety, health and environmental standards everywhere in the EU. On February 21, 2013, the European Union reached preliminary agreement on a Directive specifying toughened rules for offshore oil and gas operations. The proposed directive is expected to be formally approved in coming months (first 2013 semester) by EU member countries and the European Parliament, and implemented within 2 years after being approved. The main elements of the preliminary 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, will verify the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties will be implemented if companies do not respect the minimum 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 will need to be submitted to national authorities.
•		Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation.
•		Companies will publish on their websites information about standards of performance of the industry and the activities of the national competent authorities. The confidentiality of whistle-blowers will be protected. Operators will be requested to submit reports of incidents overseas to enable key safety lessons to be studied.
•		Companies will 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. EU member states will likewise take full account of these plans when they compile national emergency plans. The plans will be periodically tested by the industry and national authorities.
•		Oil and gas companies will be fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone will be 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).
•		Offshore inspectors from Member States will work together to ensure effective sharing of best practices and contribute to developing and improving safety standards.
•		The EU Commission will work with its international partners to promote the implementation of the highest safety standards across the world. Operators working in the EU will be expected to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.

Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices could 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 (HFRS) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.

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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 chemicals classification, mainly regarding the 2008 European Regulation on the Classification, Labeling and Packaging (CLP) 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 2012

Eni is committed to continuously improve 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 2012, 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 330 (303 in 2011), of which 106 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) and 97 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

In 2012, Eni total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to euro 1,486 million, in line with the 2011 figure.

Environment. In 2012, Eni incurred total expenditures amounting to euro 743.6 million for the protection of the environment (with a reduction of 17% with respect to 2011). Current environmental expenses decreased by approximately 16% from 2011, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure decreased by 19.5% and mainly related to remediation and reclamation activities and energy efficiency and climate change. Eni expects to continue incurring amount of environmental expenditures and expenses in line with or above 2012 levels in future years.

Safety. Eni is committed to safeguard the safety of our employees and contractors as well as of all people living in the areas where our activities are conducted and our assets located. In 2012, 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 awareness through all levels of the Company’s organization continued in 2012; 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 conduct of 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 2012 Eni has started its safety roadshow, 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.

Results of efforts to achieve a better safety in all activities has brought an improvement of Eni employee lost time injury frequency to 0.57 and of the severity rate to 0.026, the first one decreasing by 12% and the second one slightly increasing (4%) from 2011.

As to emergency preparedness, Eni has joint the Oil Spill Response Joint Industry Project (OSR-JIP) launched in December 2011 by OGP (International Association of oil&gas Producers) and IPIECA (International Petroleum Industry Environmental Conservation Association). 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.

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Costs incurred in 2012 to support the safety levels of operations and to comply with applicable rules and regulations were euro 371 million, up 12% from 2011. Eni expects to continue incurring amounts of expenses for safety which will be in line with 2012 levels in future years.

Health. Eni’s activities for protecting health aim at the continuous improvement of work conditions. Results have been achieved, as in the past years, through:

•		efficiency and reliability of plants;
•		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, identifying 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 more than 424 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 Health Impact Assessment (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 Health Impact Assessment 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 2012, Eni incurred a total expense of euro 48.3 million, down 39% from 2011, to protect the health of its employees. The 2012, figure is in line with the level of expenditure of 2010. Eni expects to continue incurring amounts of expenses for health which will be in line with 2012 levels in future years.

 

Managing GHG emissions and implementation of the Kyoto Protocol

In December 2012 in Doha, the 18^th Conference of the Parties to UNFCCC has achieved an agreement on the second commitment of the Kyoto Protocol, thus extending the former international agreement after 2012 and until 2020.

Only some industrialized parties to the Kyoto Protocol have extended their commitments and, in particular, the EU will reduce in 2020 its GHG emissions by 20% compared to 1990 levels. Parties should define a new regime for post 2020 by 2015.

Regarding GHG emissions mitigation, Eni’s management believes that the best solutions for mitigating GHG emissions are the use of low emission energy sources and the adoption of highly efficient technologies. Therefore Eni has carried out a detailed analysis and identified a number of projects aiming at energy saving and emission reductions from its plants. In particular, significant projects are being implemented in order to economically exploit gas associated with the production of liquids and reduce gas flaring. The Company plans to invest approximately euro 470 million over the next four years in Libya, Congo and Nigeria, to execute projects intended to monetize the reserves of associated gas and cut volumes of flared gas. Particularly in the period 2013-2016, Eni plans to cut by 71% the volumes of gas flaring compared to 2007 levels. Moreover, Eni is implementing measures targeting energy efficiency in various installations and facilities including refineries, petrochemicals plants and electricity plants, and actions to better manage gas emissions in transport and distribution activities.

Italy 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.

As required by the Directive, Italy has approved two National Allocation Plans (NAP) covering the periods 2005-2007 and 2008-2012 which set out the allowances issued to each sector and installation. The EU-ETS Directive provides that each Member State shall ensure 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. The excess emissions penalty for the period 2008-2012 amounts to euro 100 for each tonne of carbon dioxide equivalent produced in excess of the allowances acquired on the market. The payment of the penalty shall not release the operator from the obligation to surrender an amount of allowances equal to those excess emissions when surrendering allowances in relation to the following calendar year. All companies are expected to identify and carry out projects for emission reductions.

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Eni participates in the ETS scheme with 36 plants in Italy and 3 outside Italy, which collectively represent more than 40% of all greenhouse gas emissions generated by Eni’s plants worldwide. In the period 2008-2012 Eni was entitled to allowances equal to 122.9 mmtonnes of carbon dioxide for existing installations and further 3.3 mmtonnes in relation to new installations for the 2008-2012 period. Based on the implementation of projects designed to reduce emissions, particularly the start-up of high efficiency combined cycles for the cogeneration of electricity and steam, the amount of carbon dioxide emitted by Eni’s plants has complied with mandatory limits in each of the reported periods up to 2012.

Due to stricter allocation rules in the third phase (2013-2020) of the Emissions Trading Scheme, Eni shall receive a lower amount of free allowances. As a consequence, in the next four-year period (2013-2016), Eni shall buy on the market an higher amount of allowances to cover GHG emissions of its industrial plants. The majority of the deficit (over 85%) is concentrated in the power sector, because electricity producers will not receive any free allowances in the third phase. Nevertheless, current wholesale power prices are incorporating CO₂ cost, and Eni has a very modern and efficient fleet, so the expectation is to be able to reflect the cost of CO₂ in the price of electricity sold. On the other hand, the remaining Eni sectors will incur in a higher CO₂ cost. This cost will be mainly incurred in the period 2014-2016, because in 2013 Eni’s installations can benefit from the allowances in banking coming from the 2012. The total cost in 2014-2016 can be estimated in euro 80 million⁶.

To ensure 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), which is an essential requirement for emission 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 2012 to be in compliance with the new Monitoring and Reporting Guideline (European Regulation No. 601/2012) and with the best practices reference document (American Petroleum Industry Compendium - August 2009). For safer and more accurate management of GHG emissions and with a view to supporting 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. To improve the Eni accounting and reporting process, in 2012 Eni provided independent verification of its 2011 equivalent CO₂ emissions data, as submitted to the Carbon Disclosure Project, and obtain the verification statement in accordance with ISO 14063-3.

In the medium term, work is underway on the separation of carbon dioxide and its permanent storage in geologic reservoirs, a part of the CO₂ Capture Project, an international R&D program carried out in conjunction with other oil companies. Eni is currently implementing Italy’s first CO₂ injection project in Cortemaggiore.

In both the medium and long term, management believes that compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Eni’s commitment to the transition to a lower-carbon economy may create expectations for our activities and related liabilities, and the level of participation in alternative energies carries reputational, economic and technology risks.

 

Regulation of Eni’s businesses

Overview

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

 

Regulation of exploration and production activities

Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil and gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with

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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 Product Sharing Agreements (PSA), 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 a production concession, in each case granted by the Ministry of Productive Activities through competitive auctions. 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. 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 and subsequent modifications and integrations, royalties are equal to 10% onshore and 7% offshore both for gas and oil production; particularly in 2012 the royalties for offshore production have been increased from 4% to 7%.

 

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 according to Article 30, lines 6 and 7, of Law July 23, 2009, No. 99

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

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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 cap provided by the Legislative Decree No. 130/2010 to its market share in Italy rises from 40% to 55%. In the case of violations of the mandatory threshold, Eni will be 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 is reserved to industrial customers and their consortium (3 BCM, already allocated) and to gas fired power plants (1 BCM). Furthermore, the decree establishes that upon request, industrial customers are granted, for the new storage capacity which is not yet at their disposal:

•		up to March 2012, a financial anticipation of the benefit they will have once disposing of the new storage capacity (i.e. the gap between summer and winter gas prices minus the cost of storage services); and
•		starting from April 2012 a "virtual storage service", which consists of the possibility to deliver gas in summer to a "virtual storage operator" at a European hub – TTF, Zeebrugge or PSV – and to be re-delivered equivalent gas quantities in winter at the Italian PSV, paying for the service a fee equivalent to the cost of storage plus transmission costs, if any. The Italian Gestore of Servizi Energetici has elected certain virtual storage operators to be the providers of those services. Industrial investors will then benefit from the price differentials due to the seasonal swings of gas demand. Eni, in compliance with Legislative Decree No. 130/2010 provisions, participated to the tender procedure for the selection of "virtual storage operators" for 50% of the requested quantities, bidding a price fixed by the Italian Regulator (AEEG).

Eni’s management is monitoring this issue with a view of assessing any possible financial or economic impact associated with the enacted measures and their evolution. Management also believes that this new gas regulation 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 Italian Regulator (AEEG), 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. The AEEG also intends to progressively align the cost component relating to the raw material to spot prices, granting to operators with long-term contracts a component of price related to the security of supply. Similarly other regulatory authorities in European countries where Eni operates are planning to issue a regulation aimed at 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; and
•		reduce the cost of natural gas for industrial customers by giving them direct access to storage capacity. This will be possible with a redefinition of the binding modulation for residential customers in case of rigid winter conditions and by freeing up a percentage of strategic storage volumes. For this purpose, the Ministry for Economic Development enacted a Law Decree on February 15, 2013, introducing changes to the criteria of assignment of storage capacity in application of Article 14 of Law Decree No. 1, 2012 setting forth that:

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the storage capacity that would be available as a result of new mechanisms for determining the volumes of strategic storage, as well as new modalities of calculation of obligation limitations based on the criteria issued by the Ministry for the Economic Development, are assigned, for a space determined by the Ministry itself, for the offer to industrial sector, integrated transportation services through International pipelines and re-gasification, including natural gas storage, allowing the supplies of natural gas from abroad, in accordance with security criteria requested, as well as by re-gasification companies, as a guaranty for the respect of re-gasification programs of their customers when non predictable events occur; and

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is determined part of the space of modulation storage devoted to the needs of "vulnerable events", to be assigned, for the needs of the clients themselves, with procedure of competitive bid, and the part of the same space of storage modulation to be assigned with ongoing allocation procedures.

Based on the principles described above, at the beginning of 2013 the Minister of Economic Development and the Italian Authority for Electricity and Gas introduced new criteria for the allocation of gas storage capacities for the thermal year 2013-2014. In particular, the decree on gas storage capacity allocation rules that, starting from the period April 1, 2013 to March 31, 2014, 4.2 BCM of storage is to be allocated through auction, of which 2.5 BCM is reserved to domestic users and 1.7 BCM for other users, including those without domestic consumers in their portfolios.

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A further 4.2 BCM of storage capacity reserved to domestic users would still be allocated through the current system, which assigns pro-rata storage volumes to operators based on the size of the market they cover.

 

Mandatory disposal of Eni’s interest in Snam

On October 15, 2012, following the satisfaction of certain conditions precedent, including, in particular, antitrust approval, Eni finalized the divestment to Cassa Depositi e Prestiti SpA ("CDP"), an entity controlled by the Italian Ministry of Economy and Finance, of 1,013,619,522 ordinary shares of Snam SpA, corresponding to 30% less 1 share of the voting shares at a price of euro 3.47 a share, as provided for by the sale and purchase contract of June 15, 2012.

The transaction implemented the provisions of Article 15 of Law Decree No. 1 of January 24, 2012 (enacted into Law No. 27 of March 24, 2012), pursuant to which Eni divested its shareholding in Snam in accordance with the model of ownership unbundling set out in Article 19 of Legislative Decree No. 93 of June 1, 2011, and in accordance with the criteria, terms and conditions defined in the Decree of the President of the Council of Ministers issued on May 25, 2012 (the "DPCM") and designed to ensure the complete independence of Snam from the largest gas production and sale Company in Italy.

Furthermore, the DPCM provided the divestment of the residual shareholding of Eni in Snam through transparent and non-discriminatory sales procedures targeted to both retail and institutional investors. On July 18, 2012, Eni finalized the sale of a further 5% interest in Snam (178,559,406 ordinary shares) through an accelerated book-building procedure reserved to Italian and foreign institutional investors.

The mandatory disposal of Eni’s interest in Snam SpA was originally provided by Italian Law No. 290/2003 which prohibits vertically-integrated companies operating in the natural gas and power industries to retain an interest in excess of 20% in the share capital of companies owning and managing national networks for the transmission of natural gas and power.

 

Negotiation platform for gas trading

In compliance with the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry for Economic Development published a Decree that implements a trading platform for natural gas starting 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 GME (Gestore dei Mercati Energetici). 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. Under these provisions, importers were expected to supply given amounts of gas (from 5% to 10% of total gas import) to the virtual exchange in order to receive permission to import, as well as volumes corresponding to royalties due by owners of mineral rights to the Italian State (and to Basilicata and Calabria Regions). Eni was required to offer at that platform about 200 mmCM related to the residual obligation for volumes imported in thermal year October 1, 2008-September 30, 2009, and to the offer obligation for the October 1, 2009-September 30, 2010 thermal year, as well as approximately 215 mmCM related to royalties due for 2009 full year. Operators, also non-importers, are allowed to negotiate additional gas volumes over the compulsory amounts on the platform according to the supply rules determined by the AEEG. 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). We believe that these measures have increased the level of liquidity in the Italian spot market of gas.

 

Natural gas prices

Following the liberalization of the natural gas sector introduced in 2000 by Decree No. 164, prices of natural gas sold to industrial and power generation customers as well as to wholesalers are freely negotiated. However the AEEG holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the AEEG) and Legislative Decree No. 164/2000.

Furthermore, the AEEG has been entrusted by the Presidential Decree dated October 31, 2002 with the power of regulating natural gas prices to residential and commercial customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which engage in selling natural gas through local networks are currently required to offer to those customers the regulated tariffs set by AEEG beside their own price proposals. Clients who are currently eligible to the safeguard regime set by the Authority are those residential clients who did not opt for choosing a supplier at the opening of the market in 2003 (including those who consume less than 200,000 CM/y and residential buildings). The above mentioned Legislative Decree No.

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130/2010 enlarged this category by including all customers consuming less than 50,000 CM/y and certain public services (for example hospitals and other assistance facilities).

The pricing mechanism established by the AEEG indexes the cost of gas to a predetermined basket of hydrocarbons for the purpose of setting tariffs to customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. Law Decree No. 1 enacted by the Italian Government on January 24, 2012 (the so-called Liberalization Decree), converted to Law No. 20 on March 24, 2012, has put the AEEG in charge with the task of gradually introducing reference to the price of certain benchmarks quoted at continental hubs in the indexation mechanism of the cost of gas in the pricing of sales to the above mentioned customers from the second quarter of 2012. The AEEG has updated the indexation mechanism by increasing the weight of spot prices in the indexation of the supply costs of gas whereby spot prices have represented a share of 3% and 4% of the cost of gas in the second and third quarter of 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. Furthermore, the AEEG is planning to progressively align the cost component relating to the raw material to spot prices, granting to operators with long-term contracts a component of price related to the security of supply. Similarly other regulatory authorities in European countries where Eni is present are planning to issue a regulation aimed at 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.

The same decree on liberalizations provides a measure intended to reduce the supply cost of gas to businesses by enabling them to directly access certain new storage capacity. This new capacity would be available as a result of new mechanisms for determining the volumes of strategic storage and storage capacity that operators engaged in natural gas marketing are obliged to set aside to cover demand peaks from households and residential clients during wintertime. This additional flexibility would make available an integrated set of services from transport to storage to businesses in compliance with the public criteria of supply security.

 

Refining and marketing of petroleum products

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

Marketing. Following the enactment of the above mentioned Law Decree No. 1 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012 principals will be allowed to supply freely up to 50% of their requirements. In such case the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing Eni’s market share in Italy.

Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) upon the closure of at least 7,000 service stations, the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third party access to unused storage capacity for petroleum products. With the same goal of renewing the Italian distribution network, Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001

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establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities.

After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012 all service stations must be provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas.

Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations which might prejudice the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours. Management believes that those measures will favor competition in the Italian retail market and support efficient operators.

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

Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 ("Decree 22/2001") enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis.

The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain.

As of December 31, 2012, Eni owned 6.2 mmtonnes of oil products inventories, of which 4.2 mmtonnes as "compulsory stocks", 1.6 mmtonnes related to operating inventories in refineries and depots (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.4 mmtonnes related to specialty products.

Eni’s compulsory stocks (as of December 31, 2012) were held in term of crude oil (31.5%), light and medium distillates (47%), fuel oil (17%) and other products (4.5%) and they were located throughout the Italian territory both in refineries (79%) and in storage sites (21%).

 

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 ("Article 101" and "Article 102", respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 ("EU Regulation 139"). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of

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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, 2012, there were 252 fully consolidated subsidiaries and 62 associates that were accounted for under the equity or cost method. For a list of subsidiaries of the Company, see "Exhibit 8. List of Eni’s fully consolidated subsidiaries for year 2012".

 

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 (IFRS) as issued by the IASB.

In the Group’s 2012 financial statements the Italian regulated businesses managed by Snam SpA and its subsidiaries (Snam) have been reported as discontinued operations because they represented a major line of business and Eni was mandated to divest the control over and any residual interest in the investee to comply with provisions of the Italian Law on Liberalizations No. 27/2012 requiring the ownership unbundling of Eni from Snam. On October 15, 2012 Eni divested a 30% interest less one share in Snam to an Italian entity "Cassa Depositi e Prestiti" and relinquished control over the entity as part of the transaction. The residual interest of Eni in Snam was equal to 20.2% of the share capital of the investee as of the balance sheet date. Eni is forbidden from exercising the underlying voting rights by applicable laws and therefore cannot influence the financial and operating policy decisions of the investee. The Company also has the intention to dispose of the residual 20.2% interest and as a result this was accounted for as a financial instrument at December 31, 2012, as described in "Item 18 – note 17 – Financial instrument – Investments – Other investments – of the Notes to the Consolidated Financial Statements".

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 of euro 4,198 million for the year ended December 31, 2012, representing a decrease of 39.2% from 2011. That amount represented net profit from continuing operations attributable to Eni’s shareholders.

The Group’s operating profit from continuing operations for the year ended December 31, 2012 amounted to euro 15,026 million, down 10.6% from 2011 mainly due to sharply higher operating losses reported by the Gas & Power, Refining & Marketing and Chemical segments. Those losses were driven by the economic downturn in Europe and continuing margin decline due to rising costs of oil-based raw materials, oversupplies and ongoing tough competition. Additionally, the reduced profitability outlook in those businesses led management to recognize material amounts of asset impairments in the region of euro 4 billion to align the book values of goodwill and other intangible commercial assets in the gas business and refineries to their lower values-in-use. Also, operating profit was impacted by the recognition of a lower inventory holding gain amounting to euro 17 million (euro 1,113 million in 2011). Further information on inventory holding gains and losses is provided on page 117.

These negative factors were partly offset by higher operating profit reported by the Exploration & Production segment, up by 16.1% due to an ongoing recovery in Libyan activities and the appreciation of the dollar over the euro.

Eni’s net profit from continuing operations for 2012 benefited from gains in the range of euro 2 billion which were recorded with respect to its Galp shareholding reflecting the divestment of part of Eni’s interest in the investee, the revaluation at fair market value of the residual stake and other transactions. In 2011, Eni recorded significant gains on the divestment of certain international gas pipelines (euro 1,044 million).

Finally, income taxes increased by euro 1,756 million driven by higher taxes currently payable recorded by the Exploration & Production segment reflecting increased taxable profit and a write down of deferred tax assets (euro 1,030 million) incurred at Italian subsidiaries. This impairment was recognized to reflect a lower likelihood that deferred tax assets of Italian subsidiaries can be recovered in future periods due to an expected reduction in taxable income generated in Italy, and as Eni has lost the availability of Snam taxable profit against which Italian tax assets can be utilized following the deconsolidation of Snam.

Management also evaluated the Company’s performance of continuing operations in 2012 by excluding certain losses, mainly asset impairments, risk and other provisions and the above mentioned write down of deferred tax assets, capital and revaluation gains on the interest in Galp and other capital gains on the divestment of minor assets from net profit. Under this assumption, net profit would have been slightly better than the previous year.

Net cash provided by operating activities from continuing operations amounted to euro 12,356 million for the year ended December 31, 2012 and proceeds from divestments amounted to euro 6,014 million. Those cash inflows funded cash outflows relating to capital expenditure totaling euro 12,761 million and investments (euro 569 million) relating to the acquisition of Nuon in Belgium and joint venture projects, as well as dividend payments amounting to euro 4,379 million (of which euro 1,956 million relating to the 2012 interim dividend, euro 1,884 million to the balance of the

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dividend for fiscal year 2011 to Eni’s shareholders and the remaining part related to other dividend payments mainly relating Saipem and Snam).

Disposals of assets primarily related to the divestment of a 30% interest less one share in Snam to Cassa Depositi e Prestiti (euro 3,517 million), two tranches of the interest in Galp for an overall amount of euro 963 million (a 5% interest sold to Amorim BV and a 4% sold through an accelerated book-building procedure), a 10% interest in the Karachaganak field (euro 500 million) and other non-strategic assets in the Exploration & Production segment (euro 695 million). The proceeds on the sale of a 5% interest in Snam to institutional investors (euro 612 million) before loss of control over the investee, were recognized as an equity transaction, without impact on the profit and loss.

As of December 31, 2012 net borrowings amounted to euro 15,511 million, a decrease of euro 12,521 million from December 31, 2011, reflecting the divestment of a 30% interest in Snam to Cassa Depositi e Prestiti (euro 3,517 million) and, following the loss of control in this entity, the deconsolidation of Snam net borrowings of euro 12,448 million.

In 2012, oil and natural gas production available for sale averaged 1,631 kBOE/d. Production for the year expressed in barrel-of-oil equivalent was computed assuming a natural gas conversion factor which was updated to 5,492 cubic feet of gas equals 1 barrel of oil. See disclosure in the footnote to the "Conversion Table" on page vi. On a comparable basis, i.e. when excluding the effect of updating the gas conversion factor, production showed an increase of 7% for the full year. Production growth was driven by an ongoing recovery in Libyan production and continuing production start-up and ramp-up particularly in Russia, Australia and Iraq. Those additions were partly offset by unplanned downtime at the Elgin/Franklin field (Eni’s interest 21.87%) in the UK due to a gas leak, losses in Nigeria due to force majeure and mature field declines.

Worldwide gas sales in 2012 amounted to 95.32 BCM, a decrease of 1.44 BCM from 2011 or 1.5%, reflecting an ongoing demand downturn. Natural gas sales in Italy were substantially unchanged from 2011, while lower volumes were recorded in a number of European markets (down by 1.96 BCM, or 3.7%) such as Benelux and the Iberian Peninsula due to the exclusion of Galp sales after loss of significant influence on the investee (for more detailed information see "Item 4 – Portfolio developments"). Sales increased in France, Germany/Austria, and in the LNG business in Extra-European Markets.

In 2012, capital expenditures of continuing operations amounted to euro 12,761 million (euro 11,909 million in 2011) and mainly related to:

•		oil and gas development activities (euro 8,304 million) deployed mainly in Norway, the United States, Congo, Italy, Kazakhstan, Angola and Algeria;
•		exploration projects (euro 1,850 million) of which 98% was spent outside Italy, primarily in Mozambique, Liberia, Ghana, Indonesia, Nigeria, Angola and Australia;
•		upgrading the fleet used in the Engineering & Construction segment (euro 1,011 million); and
•		refining, supply and logistics with projects designed to improve the conversion rate and flexibility of refineries (euro 622 million), in particular at the Sannazzaro refinery, as well as upgrading and rebranding of the refined product retail network (euro 220 million).

During the 2013-2016 four-year period, Eni expects to invest approximately euro 56.8 billion in capital expenditures and exploration projects to implement its growth strategy, based on the assumptions discussed below under "Management’s expectation of operations".

 

Trading environment

		2010		2011		2012

Average price of Brent dated crude oil in U.S. dollars (1)		79.47		111.27		111.58
Average price of Brent dated crude oil in euro (2)		59.89		79.94		86.83
Average EUR/USD exchange rate (3)		1.327		1.392		1.285
Average European refining margin in U.S. dollars (4)		2.66		2.06		4.83
Euribor - three month euro rate % (3)		0.8		1.4		0.6

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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	Price per barrel. FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data.

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When the term margin is used in the following discussion, it refers to 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 petrochemicals products). Margin trends 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 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 2012, Eni’s results were achieved in a trading environment characterized by a marker Brent price of $111.58 per barrel, almost in line with 2011. The gas market was influenced by weak demand as a consequence of the European economic slowdown. At the same time, the marketplace was well supplied, with very liquid continental hubs for spot transactions. Price competition among operators has been stiff taking into account minimum off-take obligations provided by gas purchase take-or-pay contracts and reduced sales opportunities. Spot prices in Europe increased by 5% from 2011, although this was not reflected in gas margins because of higher oil-linked supply costs and increasing competitive pressure. Refining margins showed a recovery from the depressed levels in 2011 (the benchmark margin on Brent crude averaged $4.83 per barrel, up $2.77 per barrel). However the margins remained unprofitable due to the volatility of the trading environment and weak fuel demand on the back of the economic downturn, excess capacity, competitive pressures and high costs of oil feedstock and oil-linked energy utilities. Furthermore, Eni’s complex refineries were impacted by narrowing price differentials between light and heavy crudes. Results were helped by the appreciation of the U.S. dollar over the euro (up 7.7%).

 

Key consolidated financial data

		2010		2011		2012

(euro million)

Net sales from operations from continuing operations				96,617		107,690			127,220
Operating profit from continuing operations				15,482		16,803			15,026
Net profit attributable to Eni from continuing operations				6,252		6,902			4,198
Net profit attributable to Eni from discontinued operations				66		(42	)		3,590
Net profit attributable to Eni				6,318		6,860			7,788
Net cash provided by operating activities - continuing operations				14,140		13,763			12,356
Capital expenditures - continuing operations				12,450		11,909			12,761
Acquisitions of investments and businesses				410		360			569
Shareholders’ equity including non-controlling interest at year end				55,728		60,393			62,713
Net borrowings at year end				26,119		28,032			15,511
Net profit attributable to Eni basic and diluted from continuing operations		(euro per share)		1.72		1.90			1.16
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
Dividend per share		(euro per share)		1.00		1.04			1.08
Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) (1)				0.47		0.46			0.25

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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,

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intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the oilfield services construction and engineering businesses. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates follows.

 

Oil and gas activities

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Field reserves will only be categorized as proved when all the criteria for attribution of proved status have been met. At this stage, all booked reserves are classified as proved undeveloped. Volumes are subsequently reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings occur at the point of first oil or gas production. 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 and upward and 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 as 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 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, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment.

 

Impairment of assets

Assets, including goodwill, are impaired when there are events or changes in circumstances that indicate the 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 for crude oil, natural gas, commodity chemicals and refined products. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred costs – see also item "Current assets") related to natural gas volumes not collected under long-term purchase contracts with take-or-pay clauses as well as in order to test 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 related to the activity involved. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. Oil, natural gas and petroleum product prices (and prices from products which are derived there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. 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 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 an indefinite useful life are not subject to amortization. The Company tests for impairment such assets at the cash

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generating unit level on an annual basis and whenever there is an indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash generating unit is lower than the carrying amount, goodwill attributed to that cash generating unit is impaired up to that difference; if the carrying amount of goodwill is less than the amount of impairment, assets of the cash generating unit are impaired pro-rata on the basis of their carrying amount for the residual difference.

 

Asset retirement obligations

Obligations to remove tangible 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 future asset retirement obligations 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 subjectivity of these estimates is also increased by the accounting method used that requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically, at the time the asset is installed at the production location). When liabilities are initially recorded, the related fixed assets are increased by an equal corresponding amount. The liabilities are updated with the passage of time (i.e. interest accretion) and any change in the estimates following the modification of future cash flows and discount rate adopted. The recognized asset retirement obligations are based on future retirement cost estimates and incorporate many assumptions such as: expected recoverable quantities of crude oil and natural gas, abandonment time, future inflation rates and the risk-free rate of interest adjusted for the Company’s credit costs.

 

Business combinations

Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business at their respective fair values. Any positive residual difference is recognized as "Goodwill". Negative residual differences are credited to the profit and loss account. Management uses all available information to make these fair value determinations and, for major business combinations, typically engages independent external advisors to assist in the fair value determination of the acquired assets and liabilities.

 

Environmental liabilities

Together with other companies in the industries in which it operates, 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 has been incurred and the amount can be reasonably 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 insurance recoveries.

 

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 return on plan assets, 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. The inflation rates reflect market conditions observed Country

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by Country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved; and (v) determination of the expected rates of return on assets is made through compound averaging. For each plan, the distribution of investments among bonds, equity and cash and their specific average expected rate of return is taken into account. Differences between expected and actual costs and between the expected return and the actual return on plan assets routinely occur and are called actuarial gains and losses. Eni applies the corridor method to amortize its actuarial losses and gains. This method amortizes on a pro-rata basis the net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period that exceed the greater of 10% of: (i) the present value of the defined benefit obligation; and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan. Additionally, obligations for other long-term benefits are determined by adopting actuarial assumptions. The effects of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety.

 

Contingencies

In addition to accruing the estimated costs for environmental liabilities, asset retirement obligation and employee benefits, Eni accrues for all contingencies that are both probable and estimable. These other contingencies are primarily related to litigation and tax issues. Determining the appropriate amount to accrue is a complex estimation process that includes subjective judgments of the management.

 

Revenue recognition in the Engineering & Construction segment

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 income, derived from a change in the scope of work, is 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.

 

2010-2012 Group results of operations

Overview of the profit and loss account for three years ended December 31, 2010, 2011 and 2012

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. Eni’s financial statements include Snam Group in the manner discussed above. Previous periods have been restated accordingly.

 

 

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	Year ended December 31,

		2010		2011		2012

(euro million)

Net sales from operations		96,617			107,690			127,220
Other income and revenues (1)		967			926			1,546
Total revenues		97,584			108,616			128,766
Operating expenses		(73,202	)		(83,199	)		(100,021	)
Other operating (expense) income		131			171			(158	)
Depreciation, depletion, amortization and impairments		(9,031	)		(8,785	)		(13,561	)
OPERATING PROFIT		15,482			16,803			15,026
Finance income (expense)		(749	)		(1,146	)		(1,307	)
Income (expense) from investments		1,112			2,123			2,881
PROFIT BEFORE INCOME TAXES		15,845			17,780			16,600
Income taxes		(8,581	)		(9,903	)		(11,659	)
Net profit - continuing operations		7,264			7,877			4,941
Net profit - discontinued operations		119			(74	)		3,732
Net profit		7,383			7,803			8,673
Attributable to:
Eni’s shareholders:		6,318			6,860			7,788
- continuing operations		6,252			6,902			4,198
- discontinued operations		66			(42	)		3,590
Non-controlling interest:		1,065			943			885
- continuing operations		1,012			975			743
- discontinued operations		53			(32	)		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,

		2010		2011		2012

(%)

Operating expenses		75.8		77.3		78.6
Depreciation, depletion, amortization and impairments		9.3		8.2		10.7
OPERATING PROFIT		16.0		15.6		11.8

 

2012 compared to 2011. Net profit attributable to Eni’s shareholders from continuing operations in 2012 was euro 4,198 million, a decrease of euro 2,704 million from 2011, or 39.2%. This decrease was driven by:

(i)		a lower operating performance (down by euro 1,777 million, or 10.6% from 2011) which was mainly reported by the Gas & Power, Refining & Marketing and Chemical segments due to a downturn in demand, competitive pressure and unprofitable unit margins. Results also reflected higher impairments of property, plant and equipment and intangible assets, mostly in the gas marketing and refining businesses due to a reduced profitability outlook on the back of the ongoing European downturn. The negative factors were partly offset by better results reported by the Exploration & Production segment (up by 16.1%);
(ii)		the lower operating performance was also affected by the recognition of lower inventory holding gains in particular in the Refining & Marketing and, to a minor extent, Gas & Power segments (down euro 1,096 million from a year ago). Further information on inventory holding gains and losses is provided on page 117; and
(iii)		higher income taxes (up euro 1,756 million compared to 2011 full year) currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit. The Company also recognized a write down of euro 1,030 million 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, and as Eni has lost the availability of Snam taxable profit against which Italian tax assets can be utilized following the deconsolidation of Snam.

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These decreases were partly offset by higher profits reported from equity-accounted and cost-accounted entities and financial assets, mainly reflecting the recording of gains on disposal and revaluation of interests relating to the divestment of part of Eni’s interest in Galp (an overall gain of approximately euro 2 billion). These gains were partly offset by the fact that in 2011 Eni benefited from gains recorded on the divestment of Eni’s interests in international gas pipelines (euro 1,044 million).

2011 compared to 2010. Net profit attributable to Eni’s shareholders from continuing operations in 2011 was euro 6,902 million, an increase of euro 650 million from 2010, or 10.4%. This increase was driven by:

(i)		an improved operating performance (up by 8.5% from 2010) which was mainly related to the results reported by the Exploration & Production segment (up by 14.6%), reflecting a favorable trading environment and by the Engineering & Construction segment due to strong business trends. These positive factors were partly offset by sharply lower results reported by the Gas & Power, the Chemical and the Refining & Marketing segments due to a downturn in demand and unprofitable unit margins;
(ii)		recognition of higher inventory holding gains in particular in the Refining & Marketing segment; and
(iii)		higher profits reported from equity-accounted and cost-accounted entities, mainly reflecting the gains recorded on the divestment of international pipelines (euro 1,044 million).

These increases were partly offset by higher income taxes (up euro 1,322 million compared to 2010 full year) currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit. The Company also recognized an adjustment to deferred taxation (euro 573 million) due to a changed tax rate applicable to a production sharing agreement in the Exploration and Production segment.

The table below sets forth, for the periods indicated, details of certain gains and charges included in net profit attributable to Eni’s shareholders from continuing operations.

	Year ended December 31,

Eni Group		2010		2011		2012

(euro million)

Profit (loss) on stock		881			1,113			17
Provisions for Antitrust and other Authorities proceedings		246			(69	)
Environmental provisions		(1,360	)		(176	)		(63	)
Impairment losses		(692	)		(1,031	)		(4,029	)
Net gains on disposal of assets		252			57			548
Risk provisions		(95	)		(88	)		(945	)
Provision for redundancy incentives		(400	)		(203	)		(64	)
Fair value gains/losses on commodity derivatives		2			(15	)		1
Other		19			(100	)		(271	)
Net (charges) gains in operating profit		(1,147	)		(512	)		(4,806	)
Capital gains and revaluation gains on Galp								2,011
Other capital gains/write downs on investments		324			879			(73	)
Write down of deferred tax assets/recognition of deferred tax liabilities					(552	)		(803	)
Tax effects on the above listed items		340			151			864
Other		(35	)		(2	)		(123	)
Net (charges) gains in net profit		(518	)		(36	)		(2,930	)

 

Discontinued operations

In accordance with IFRS 5, results of the Italian regulated businesses managed by Snam have been reported as discontinued operations throughout the whole of 2012 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 are reported separately from the Group’s continuing operations, including gains on the disposal and the revaluation of the residual interest. IFRS also requires that the profits earned by the discontinued operations, in this case the Snam operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa. This representation does not indicate

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the profits earned by continuing or discontinued operations, as if they were standalone entities. To allow a like-for-like comparison, results of the previous reporting periods have been modified accordingly.

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

	Year ended December 31,

		2010		2011		2012

(euro million)

Net profit - discontinued operations		119		(74	)		3,732
attributable to:
- Eni		66		(42	)		3,590
- non-controlling interest		53		(32	)		142

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.

 

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 128,766 million, euro 108,616 million and euro 97,584 million for the year ended December 31, 2012, 2011 and 2010, 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 127,220 million, euro 107,690 million and euro 96,617 million for the year ended December 31, 2012, 2011 and 2010, respectively, and its other income and revenues totaled euro 1,546 million, euro 926 million and euro 967 million, respectively, in these periods.

 

 

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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 intra-group sales, together with consolidated net sales from operations.

	Year ended December 31,

		2010		2011		2012

(euro million)

Exploration & Production		29,497			29,121			35,881
Gas & Power (1)		27,806			33,093			36,200
Refining & Marketing		43,190			51,219			62,656
Chemicals		6,141			6,491			6,418
Engineering & Construction		10,581			11,834			12,771
Other activities		105			85			119
Corporate and financial companies		1,386			1,365			1,369
Impact of unrealized intragroup profit elimination (2)		100			(54	)		(75	)
Consolidation adjustment (3)		(22,189	)		(25,464	)		(28,119	)
NET SALES FROM OPERATIONS		96,617			107,690			127,220

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2012 compared to 2011. Eni’s net sales from operations (revenues) from continuing operations for 2012 (euro 127,220 million) increased by euro 19,530 million from 2011 (or up 18.1%) primarily reflecting higher realizations on oil, products and natural gas in dollar terms and the positive impact of the appreciation of the U.S. dollar against the euro.

Revenues generated by the Exploration & Production segment (euro 35,881 million) increased by euro 6,760 million (or up 23.2%) due to higher volumes of production sold following a production recovery in Libya, higher realizations in dollar terms (oil up 0.5%; natural gas up 9.9%) as well as currency translation effects.

Revenues generated by the Gas & Power segment (euro 36,200 million) increased by euro 3,107 million (or up 9.4%) due to trends in energy parameters which are reflected in gas prices to the retail segment mainly in Italy where retail prices are linked to the price of oil and certain refined products with certain time lags. Also a slight recovery in spot prices recorded at European continental hubs benefited revenues in this segment.

Revenues generated by the Refining & Marketing segment (euro 62,656 million) increased by euro 11,437 million (or up 22.3%) mainly reflecting higher average selling prices of refined products and the positive impact of the appreciation of the U.S. dollar against the euro, as well as higher sales volumes (up 3.31 mmtonnes, or 7.4%).

Revenues generated by the Chemical segment (euro 6,418 million) decreased by euro 73 million (or down 1.1%) from 2011 mainly due to a decline in volumes sold (down 2.1%) reflecting continuing weakness in commodity demand, which was partly offset by slightly better average sale prices.

Revenues generated by the Engineering & Construction segment (euro 12,771 million) increased by euro 937 million, or 7.9%, as a result of increased activities in the Engineering & Construction business, mainly in the Middle and Far East.

2011 compared to 2010. Eni’s net sales from operations (revenues) from continuing operations for 2011 (euro 107,690 million) increased by euro 11,073 million from 2010 (or up 11.5%) primarily reflecting higher realizations on oil, products and natural gas in dollar terms.

Revenues generated by the Exploration & Production segment (euro 29,121 million) were down by euro 376 million (down by 1.3%) due to a disruption in production flows from Eni’s activities in Libya. This negative was partly offset by higher realizations in dollar terms (oil up 40.3%; natural gas up 7.7%). The settlement of certain commodity derivatives relating to the sale of 9 mmBBL in 2011 lowered Eni’s average liquid realizations by 1.50 $/BBL to 102.11 $/BBL.

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Revenues generated by the Gas & Power segment (euro 33,093 million) increased by euro 5,287 million (or up 19%) mainly due to higher spot and oil-linked gas prices which are reflected in Eni’s revenues and increased volumes sold in Italy (up 0.39 BCM, or 1.1%) and in key European markets (up 3.66 BCM, or 7.9%).

Revenues generated by the Refining & Marketing segment (euro 51,219 million) increased by euro 8,029 million (or up 18.6%) mainly reflecting higher average selling prices of refined products partly offset by lower sales volumes (down by 1.78 mmtonnes, or 3.8%).

Revenues generated by the Chemical segment (euro 6,491 million) increased by euro 350 million (up 5.7%) due to an average 20% increase in prices of petrochemical commodities which were partly offset by a decline in volumes sold (down 15%, in particular polyethylene) due to weak demand.

Revenues generated by the Engineering & Construction business (euro 11,834 million) increased by euro 1,253 million, or 11.8%, from 2010, as a result of increased activities in the Onshore and Offshore Engineering & Construction businesses.

 

b) Operating expenses

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

	Year ended December 31,

		2010		2011		2012

(euro million)

Purchases, services and other		68,774		78,795		95,363
Payroll and related costs		4,428		4,404		4,658
Operating expenses		73,202		83,199		100,021

2012 compared to 2011. Operating expenses from continuing operations for the year (euro 100,021 million) increased by euro 16,822 million from 2011, up 20.2%, primarily reflecting higher supply costs of purchased gas, and refinery and petrochemical feedstock reflecting trends in the oil environment and the appreciation of the dollar against the euro.

Purchases, services and other costs included risk provisions amounting to euro 945 million 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 (for detailed information see "Item 4 – Gas & Power"), as well as environmental and other risk provisions. The unfavorable ruling in the arbitration proceeding with GasTerra also impacted the cost of gas volumes purchased in the year, as well as the cost that the Company expects to incur in future reporting periods unless Eni is successful in renegotiating pricing terms.

Payroll and related costs (euro 4,658 million) increased by euro 254 million, or 5.8%, from 2011 due to a higher average number of employees outside Italy (following higher activity levels in the Engineering & Construction and Exploration & Production segments) and higher unit labor cost outside Italy and the appreciation of the dollar against the euro. These increases were partly offset by a reduction in the average number of employees in Italy and a lower provision for redundancy incentives.

2011 compared to 2010. Operating expenses from continuing operations for the year (euro 83,199 million) increased by euro 9,997 million from 2010, up 13.7%, reflecting primarily higher supply costs of purchased gas, and refinery and petrochemical feedstock reflecting trends in the oil environment.

Purchases, services and other costs included environmental and other risk provisions amounting to euro 344 million. Particularly, the Group took a provision of euro 69 million relating to an antitrust proceeding in the area of elastomers based on an adverse ruling of the European Court of Justice which is disclosed in more detail in "Item 18 – note 34 - Guarantees, commitments and risks - Legal Proceedings – of the Notes to the Consolidated Financial Statements".

Payroll and related costs (euro 4,404 million) were substantially in line with the previous year (down by 0.5%). Higher per-employee labor costs in Italy and outside Italy (mitigated by the positive impact of exchange rates), and an increased average number of employees outside Italy (following higher activity levels in the Engineering

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& Construction segment), were partly offset by a reduction in the average number of employees in Italy and a lower provision for redundancy incentives.

 

c) Depreciation, depletion, amortization and impairments

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

	Year ended December 31,

		2010		2011		2012

(euro million)

Exploration & Production (1)		6,928			6,251			7,988
Gas & Power (2)		425			413			405
Refining & Marketing		333			351			331
Chemicals		83			90			90
Engineering & Construction		513			596			683
Other activities		2			2			1
Corporate and financial companies		79			75			65
Impact of unrealized intragroup profit elimination (3)		(20	)		(23	)		(25	)
Total depreciation, depletion and amortization		8,343			7,755			9,538
Impairments		688			1,030			4,023
		9,031			8,785			13,561

2012 compared to 2011. In 2012, depreciation, depletion and amortization charges (euro 9,538 million) increased by euro 1,783 million from 2011, or 23%, mainly in the Exploration & Production segment (up euro 1,737 million) reflecting higher output levels in Libya, following an ongoing recovery in activities, rising capitalized expenses incurred in connection with ongoing exploration activities, the start-up of new fields and the appreciation of the U.S. dollar against the euro (up 7.7%). The increase recorded in the Engineering & Construction business (up euro 87 million, or 14.6%) was due to new vessels and rigs which were brought into operations.

In 2012, impairments charges of euro 4,023 million mainly related to goodwill and other intangible assets in the gas Marketing activity (euro 2,494 million) and impairment losses of refining plants (euro 843 million). In performing the impairment review, management assumed a reduced profitability outlook in those businesses driven by a deteriorating European macroeconomic environment, volatility in commodity prices and margins, and rising competitive pressures. Other impairment losses were incurred at a number of proved and unproved properties in the Exploration & Production segment (euro 547 million) reflecting downward reserves revisions, price changes and revised profitability outlook mainly at certain oil and gas assets in the United States, a gas asset in India and an oil asset in Turkmenistan as well as marginal lines of business in the Chemical segment (euro 112 million) due to lack of profitability prospects.

2011 compared to 2010. In 2011, depreciation, depletion and amortization charges (euro 7,755 million) decreased by euro 588 million from 2010, or 7%, mainly in the Exploration & Production segment (down euro 677 million) reflecting a lowered output in Libya and negative currency translation differences due to the appreciation of the euro over the dollar (up 4.9%). The Engineering & Construction business recorded higher charges (up euro 83 million) as new vessels and rigs were brought into operations.

In 2011, impairments charges of euro 1,030 million mainly regarded impairment losses of refining plants (euro 488 million) based on management’s medium term forecast that points to continuing weak fundamentals and unprofitable margins resulting in the projection of lower future cash flows of those assets. Impairment charges of oil and gas properties in the Exploration & Production segment (euro 189 million) were triggered by a changed pricing environment and downward reserve revisions. An impairment charge amounting to euro 149 million was recognized on the goodwill allocated to the European Market cash generating unit in the Gas & Power Marketing business segment. In performing the impairment review of the business, management revised downwardly the profitability expectations

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driven by continuing margin pressure and declining sales opportunities against the backdrop of weak fundamentals. Minor impairment losses related to marginal lines of business in the Chemical segment.

 

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,

		2010		2011		2012

(euro million)

Exploration & Production		13,866			15,887			18,451
Gas & Power (1)		896			(326	)		(3,221	)
Refining & Marketing		149			(273	)		(1,303	)
Chemicals		(86	)		(424	)		(683	)
Engineering & Construction		1,302			1,422			1,433
Other activities		(1,384	)		(427	)		(302	)
Corporate and financial companies		(361	)		(319	)		(345	)
Impact of unrealized intragroup profit elimination		1,100			1,263			996
Operating profit		15,482			16,803			15,026

---

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,

		2010		2011		2012

(%)

Exploration & Production		47.0			54.6			51.4
Gas & Power		3.2			(1.0	)		(8.9	)
Refining & Marketing		0.3			(0.5	)		(2.1	)
Chemicals		(1.4	)		(6.5	)		(10.6	)
Engineering & Construction		12.3			12.0			11.2
Other activities
Corporate and financial companies		(26.0	)		(23.4	)		(25.2	)
Group		16.0			15.6			11.8

Exploration & Production. Operating profit in 2012 amounted to euro 18,451 million, up euro 2,564 million from 2011, or 16.1%, due to an ongoing recovery in Libyan activities which came almost to a halt in 2011. In fact the 2011 production performance was negatively impacted by disruptions in the Company’s output from Libya fields due to the internal conflict that occurred in 2011 and the consequent declaration of force majeure on the execution of the petroleum contracts in Country throughout the duration of the internal crisis.

The 2012 result of the Exploration & Production segment also benefited from the appreciation of the dollar over the euro for an estimated amount of approximately euro 1,100 million. These positives were partly offset by higher exploration costs incurred due to increased activities as well as higher operating costs and depreciation charges in connection with new field start-ups/ramp-ups.

In 2012, the Company’s liquids and gas realizations increased on average by 1.6% in dollar terms, driven by oil prices for market benchmarks (Brent crude price increased by 0.3%). Eni’s average oil realizations increased on average by 0.5%. Eni’s average gas realizations increased by 9.9%, due to time lags in oil-linked pricing formulas which were recorded in certain geographic areas, whereas gas spot prices declined in other areas, mainly in the U.S. market.

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Operating profit in 2011 amounted to euro 15,887 million, up euro 2,021 million from 2010, or 14.6%. The increase in operating profit was driven by higher liquids and gas realizations in dollar terms (up by 40.3% and 7.7%, respectively). The negative drivers were: (i) a disruption in the Company’s output from Libya due to the conflict that occurred in that Country in 2011 (an estimated loss of production of 200 kBOE/d); and (ii) the appreciation of the euro against the U.S. dollar for an estimated amount of euro 490 million. The impact on operating profit of higher oil and gas dollar realizations outweighed the negative drivers; however revenues for the year were mainly impacted by those negative factors and the Company reported a decline compared to the prior year (down by 1.3%).

In 2011, the Company’s liquids and gas realizations increased on average by 30% in dollar terms, driven by higher oil prices for market benchmarks (Brent crude price increased by 40%). Eni’s average oil realizations increased on average by 40.3%. Eni’s average liquids realizations were reduced on average by 1.50 $/BBL due to the settlement of certain commodity derivatives relating to the sale of 9 mmBBL in the year at contractually fixed prices. This was the last portion of a multi-year derivative transaction the Company entered into in order to hedge exposure to the variability in cash flows on the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmBBL in the 2008-2011 period.

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

Exploration & Production	Year ended December 31,

		2010		2011		2012

(euro million)

Environmental provisions		(30	)
Impairment losses		(127	)		(190	)		(550	)
Risk provisions								(7	)
Net gains on disposal of assets		241			63			542
Provision for redundancy incentives		(97	)		(44	)		(6	)
Fair value gains/losses on commodity derivatives					(1	)		(1	)
Other		(5	)		(18	)		(54	)
		(18	)		(190	)		(76	)

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.

Gas & Power. Following the divestment and deconsolidation of Snam, from 2012 the Gas & Power segment includes results of operations of the gas marketing business and the international transport business. Prior year results have been presented on a comparable basis, i.e. excluding the performance of the regulated gas business in Italy managed by Snam and its subsidiaries.

In 2012, the Gas & Power segment reported an operating loss of euro 3,221 million, materially down from 2011 when this segment reported an operating loss of euro 326 million. Those sharply higher losses were mainly incurred by the Marketing business, while the International Transport business remained profitable albeit reporting a lower profits compared to 2011 due to the divestment of Eni’s interests in the entities engaged in the transport of gas from Northern Europe and Russia which was completed in 2011.

The negative performance in the Marketing business was driven by a demand downturn and escalating competitive pressures fuelled by oversupplies in the marketplace which impacted our operations both in Italy and outside Italy. The reduced profitability outlook in this business due to changed underlying fundamentals also resulted in the write down of goodwill and other intangibles which were recognized as part of certain business combinations, among which Distrigas in 2008 and other minor European gas marketing companies in later years (Altergaz in France). Operating profit was also impacted by the negative effects of price revisions at certain long-term gas suppliers and customers; this was also due to the settlement of a number of arbitration proceedings, including settlement of an arbitration proceeding with GasTerra.

However, excluding impairment losses and the risk provisions accrued in connection with the above mentioned arbitration proceedings involving price revisions for gas volumes purchased in previous reporting periods, the Gas Marketing business underlying results improved compared to 2011. Those trends benefited from the renegotiation of better economic terms for certain supply contracts, including the recognition of better supply costs retroactive to the beginning of 2011, and an ongoing recovery in Libyan supplies which improved the average costs of gas supplies to the Company compared to the 2011 performance.

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In 2011, the Gas & Power segment reported an operating loss of euro 326 million, materially lower than 2010 when this segment reported an operating profit of euro 896 million, due to an operating loss of euro 710 million incurred by the Marketing business compared to the prior-year profit of euro 555 million (down by euro 1,265 million). This negative was partly offset by a better performance achieved by the International Transport business (up by 12.6%).

The negative performance in the Marketing business was driven by a demand downturn and escalating competitive pressures fueled by oversupplies in the marketplace which impacted our operations both in Italy and outside Italy. Those trends contributed to the very strong contraction reported in selling margins due to rising costs of gas supplies indexed to the price of oil and certain refined products, which increases were only in part absorbed by selling prices at continental spot markets capped by competition. Another important factor which influenced the loss was the disruption in the supplies of Libyan gas, which negatively impacted both the supply mix and sales to shippers. Finally, there were negative trends in the energy parameters and exchange rates to which gas purchase costs and selling prices are indexed considering the time lags of contractual formulas and unusual winter weather conditions impacting seasonal sales, as well as a tariff freeze to residential customers in certain European countries. The results of the Marketing business did not fully benefit from the ongoing renegotiation of gas supply contracts as certain renegotiations were rescheduled, thus postponing the recognition of the economic effect. An agreement on such renegotiations was reached early in 2012 leading to recognition of the benefit retroactive by from the beginning of 2011, in 2012 profit.

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

	Year ended December 31,

		2010		2011		2012

(euro million)

Marketing		555			(710	)		(3,531	)
International transport		341			384			310
Operating profit of the Gas & Power segment		896			(326	)		(3,221	)

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

Gas & Power	Year ended December 31,

		2010		2011		2012

(euro million)

Profit (loss) on stock		117			166			(163	)
Settlement/payments on Antitrust and other Authorities proceedings		270
Environmental provisions		(16	)					2
Impairment losses		(426	)		(154	)		(2,494	)
Net gains on disposal of assets								3
Risk provisions		(78	)		(77	)		(831	)
Provision for redundancy incentives		(52	)		(34	)		(5	)
Fair value gains/losses on commodity derivatives		(30	)		(45	)
Other		38			(17	)		(138	)
		(177	)		(161	)		(3,626	)

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 the unprecedented amount of impairment losses of euro 2,494 million which were recorded at the Company’s cash generating unit European market impacting goodwill and other intangibles which were recognized upon prior years’ business combinations. The driver 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. Also, in evaluating the terminal value of the cash generating unit management adopted a cyclical view of the business leading to a reduction in the commercial margins of the perpetual cash flow. For further information see "Item 18 – note 16 – Intangible assets – of the Notes to the Consolidated Financial Statements". Risk provisions presented in the table above mainly related to price revisions on the renegotiation of certain long-term supply contracts which 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.

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Refining & Marketing. In 2012, the Refining & Marketing segment reported an operating loss of euro 1,303 million, down by euro 1,030 million, compared to a loss of euro 273 million in 2011. The loss was driven by unprofitable refining margins due to an ongoing demand downturn for refined products, particularly in Italy, and excess capacity which prevented product prices from fully absorbing high supply costs of oil-based feedstock and oil-linked plant utilities. The 2012 operating loss in the Refining & Marketing segment was also affected by material impairment losses (down by euro 846 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. Furthermore, the segment reported a much lower inventory holding gain (stock profit) from 2011, down to euro 29 million from euro 907 million. However, excluding asset impairments and a negative change in the inventory holding gain, the segment underlying results of operations improved compared to 2011. That trend reflected a slightly more favorable refining scenario as the benchmark margin on 2012 Brent crude rose by 2.77 $/BBL from 2011 and as management continued to focus on achieving efficiency gains, optimization measures and reduced refinery downtime. The Marketing activity reported lower results, due to lower retail and wholesale demand for gasoline and gasoil, and other products impacted by the economic downturn and high competitive pressure. Results were also affected by increased expenses associated with certain marketing initiatives including a special discount on prices at the pump during the summer week-ends in Italy.

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 distorting effect on reported income. 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 2011, the Refining & Marketing segment reported an operating loss of euro 273 million, reversing a prior-year profit of euro 149 million. The segment suffered from unprofitable refining margins due to rising costs of oil-based feedstock and energy utilities that could not be transferred to final prices pressured by weak demand and excess capacity in the Mediterranean Basin. In addition, Eni’s complex refineries were hit by shrinking price differentials between light and heavy crudes which reduced the conversion premium. These negatives were offset in part by efficiency enhancement measures, the optimization of supply activities and lower throughputs at the weakest refineries. The Marketing results albeit positive, declined due to lower retail and wholesale demand for gasoline and gasoil, and other products destined to industries affected by the economic downturn, and competitive pressures. The operating profit of the Refining & Marketing segment included the following gains and charges:

Refining & Marketing	Year ended December 31,

		2010		2011		2012

(euro million)

Profit (loss) on stock		659			907			29
Environmental provisions		(169	)		(34	)		(40	)
Impairment losses		(76	)		(488	)		(846	)
Net gains on disposal of assets		16			(10	)		(5	)
Risk provisions		(2	)		(8	)		(49	)
Provision for redundancy incentives		(113	)		(81	)		(19	)
Fair value gains/losses on commodity derivatives		10			3
Other		(5	)		(27	)		(53	)
		320			262			(983	)

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 as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies.

Chemicals. In 2012, the Chemical segment incurred a larger operating loss, down by euro 259 million, or 61.1%, compared to 2011 (from a loss of euro 424 million in 2011 to a loss of euro 683 million in 2012). This negative

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performance was driven by falling commodity demand due to the economic downturn and unprofitable product margins of oil-based commodities which were squeezed by high crude oil costs, as signaled by a negative benchmark margin of cracking. Sales volumes decreased by 2.1%.

In 2011, the Chemical segment incurred a deeper operating loss, down by euro 338 million from a year-earlier (from a loss of euro 86 million in 2010 to a loss of euro 424 million in 2011). This trend was negatively impacted by falling product margins, with the cracker margin severely hit by higher supply costs of oil-based feedstock which were not recovered in sales prices on end markets pressured by weak demand for commodities particularly in the final quarter of the year as the economic activity registered a sharp contraction. Also sale volumes were lower (down 14.6% compared to 2010).

Chemicals	Year ended December 31,

		2010		2011		2012

(euro million)

Profit (loss) on stock		105			40			(63	)
Settlement/payments on Antitrust and other Authorities proceedings					(10	)
Environmental provisions					(1	)
Impairment losses		(52	)		(160	)		(112	)
Risk provisions								(18	)
Net gains on disposal of assets								(1	)
Provision for redundancy incentives		(26	)		(17	)		(14	)
Fair value gains/losses on commodity derivatives								(1	)
Other					(3	)
		27			(151	)		(209	)

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.

Engineering & Construction. Operating profit in 2012 amounted to euro 1,433 million, substantially in line with the previous year result (up euro 11 million, or 0.8% compared to 2011). This result reflected higher revenues and better margins on the works executed, mainly in the third quarter of 2012, in the Engineering & Construction business unit, in the Middle and Far East, as well as in Offshore Drilling, where the Scarabeo 8 and Scarabeo 9 activity compensated the negative impact of the upgrade shutdown of the semi-submersible platforms Scarabeo 3 and Scarabeo 6. However, from the second half of 2012, business trends commenced to reverse due to reduced activity and a slowdown in new orders acquisitions mainly in the onshore and offshore construction businesses, leading the Company to negatively revise the profitability outlook for 2013.

Operating profit in 2011 amounted to euro 1,422 million, an increase of euro 120 million, or 9.2% compared to 2010. This improvement was driven by revenue growth and a higher profitability of acquired orders, primarily in the Onshore and Offshore Engineering & Construction businesses, reflecting higher level of activities in Middle East, Canada and Australia, and in the Offshore Drilling business due to the full operation of the drillships Saipem 10000 and 12000 and of the Perro Negro 8, which partly offset the negative impact of the Scarabeo 5 planned maintenance.

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

Engineering & Construction	Year ended December 31,

		2010		2011		2012

(euro million)

Loss provisions on Antitrust and other Authorities proceedings		(24	)
Impairment losses		(3	)		(35	)		(25	)
Net gains on disposal of assets		(5	)		(4	)		(3	)
Provision for redundancy incentives		(14	)		(10	)		(7	)
Fair value gains/losses on commodity derivatives		22			28			3
		(24	)		(21	)		(32	)

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.

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This subsidiary reported operating losses of euro 302 million for 2012, euro 427 million for 2011 and euro 1,384 million for 2010. The magnitude of losses was mainly influenced by the recognition of risk provisions mainly related to environmental issues and litigation whose break-down is provided below. See "Item 4 – Environmental regulation" for further details.

Other activities	Year ended December 31,

		2010		2011		2012

(euro million)

Loss provisions on Antitrust and other Authorities proceedings					(59	)
Environmental provisions		(1,145	)		(141	)		(25	)
Impairment losses		(8	)		(4	)		(2	)
Net gains on disposal of assets					7			12
Risk provisions		(7	)		(9	)		(35	)
Provision for redundancy incentives		(10	)		(8	)		(2	)
Other		(9	)		13			(26	)
		(1,179	)		(201	)		(78	)

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 around the world, information technology, employee selection, training and retention, real estate and other general purpose services.

The aggregate Corporate and financial companies reported an operating loss of euro 345 million for 2012, representing an increase of euro 26 million, compared to the loss recorded in 2011 (euro 319 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 319 million for 2011, representing a reduction of euro 42 million, compared to the loss recorded in 2010 (euro 361 million), mainly reflecting the implementation of cost efficiency measures.

 

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,

		2010		2011		2012

(euro million)

Gains (losses) on derivative financial instruments		(131	)		(112	)		(251	)
Exchange differences, net		92			(111	)		131
Interest income		17			22			27
Finance expense on short and long-term debt		(765	)		(922	)		(980	)
Finance expense due to the passage of time		(236	)		(235	)		(308	)
Other finance income and expense, net		124			100			(76	)
		(899	)		(1,258	)		(1,457	)
Finance expense capitalized		150			112			150
		(749	)		(1,146	)		(1,307	)

2012 compared to 2011. In 2012, net finance expense was euro 1,307 million, up by euro 161 million compared to 2011 due to negative estimate revisions of certain discounted provisions due to a changed interest rate environment recorded in the line item "Finance expense due to the passage of time" (down by euro 73 million), higher finance charges (down by euro 58 million) and other finance expense (down by euro 176 million) reflecting finance charges accrued on amounts due to certain gas suppliers following the definition of contractual price revisions. The higher balance of gains and losses due to exchange differences (up by euro 242 million) was partly offset by losses on exchange rate derivatives (down euro 166 million, from a gain of euro 29 million to a loss of euro 137 million)

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recognized through profit as lacking the formal criteria for hedge accounting. Finally, a loss of euro 26 million was recognized on the fair value evaluation of a call option embedded in a convertible bond whose underlying shares were represented by a stake in Galp equaling to 8% of the share capital of the investee. This loss was matched by a market fair value gain through profit which was recorded on the Galp shares underlying the convertible bond and reported in the line item "Income on investments". More information on this transaction is reported in "Item 4 – Significant business and portfolio developments".

2011 compared to 2010. In 2011, net finance expense was euro 1,146 million, up by euro 397 million compared to 2010. Higher finance charges (up by euro 157 million) were recorded, driven by the increased level of average net borrowings and higher borrowing costs driven by movements in both key market benchmarks and spreads applicable to the Company, particularly on euro-denominated loans (the Euribor rate was up by 0.6 percentage points). Higher losses were recognized in connection with the fair value valuation through profit and loss of certain derivative instruments on interest rates (down by euro 102 million) which did not meet all formal criteria to be designated as hedges under IFRS. Lower negative exchange differences net (down by euro 203 million) were partly offset by gains on exchange rate derivatives (from a loss of euro 111 million to a gain of euro 29 million) recognized through profit and loss as lacking the formal criteria for hedge accounting.

 

f) Net income from investments

2012 compared to 2011. Net income from investments in 2012 was a net gain of euro 2,881 million and mainly related to: (i) Eni’s share of profit of entities accounted for under the equity-accounting method (euro 278 million) mainly in the Gas & Power segment; (ii) dividends received by entities accounted for at cost (euro 431 million); (iii) gains on disposal of assets (euro 349 million) mainly relating to the divestment of a 9% interest in Galp (euro 311 million) in two tranches (a 5% interest sold to Amorim BV and a 4% sold to institutional investors through an accelerated book-building procedure in November 2012); and (iv) other net income (euro 1,823 million) which reflected revaluation gains recorded on the Company’s interest in Galp. Those gains are further explained in "Item 18 – note 17 – Investments – of the Notes to the Consolidated Financial Statements".

2011 compared to 2010. Net income from investments in 2011 was a net gain of euro 2,123 million and mainly related to: (i) gains on disposal of assets (euro 1,121 million) mainly related to a gain of euro 1,044 million recorded on the divestment of Eni’s interests in the international pipelines which transport gas from Northern Europe and Russia and in Gas Brasiliano Distribuidora (euro 50 million); (ii) dividends received by entities accounted for at cost (euro 659 million), mainly relating to Nigeria LNG Ltd; (iii) Eni’s share of profit of entities accounted for with the equity method (euro 500 million), mainly in the Gas & Power, Exploration & Production and Refining & Marketing segments; and (iv) an impairment loss of an interest in a refinery plant in Eastern Europe reflecting a reduced profitability outlook (euro 157 million).

 

g) Taxes

2012 compared to 2011. In 2012, income taxes amounted to euro 11,659 million, up by euro 1,756 million compared to 2011, or 17.7%, mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit and a write down of euro 1,030 million which was recorded at deferred tax assets of Italian subsidiaries.

The Group’s consolidated tax rate increased compared to 2011, up from 55.7% to 70.2% (up 14.5 percentage points). This increase was due to:

(i)		a write down of euro 1,030 million which was recognized 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, and as Eni has lost the availability of Snam taxable profit against which Italian tax assets can be utilized following the deconsolidation of Snam;
(ii)		a shift from profit earned by associates to increased taxable income reported by the Exploration & Production segment, subject to higher tax rates; and
(iii)		the significant amount of non-deductible charges (mainly the goodwill impairment of the European market cash generating unit).

These negatives were partly offset by the non-taxable gains which were recorded on the Galp interest and the fact that based on the accounting provided by IFRS 5 the Group taxable income from continuing operations benefited from Snam’s margins on intercompany transactions which are deprived of any tax impact.

Excluding the deferred tax assets write down which was a non-recurring item, as well as capital and revaluation gains on investments and goodwill impairments which are non-taxable, non-deductible items, management estimated that the Group underlying tax rate increased in 2012 compared to 2011 due to a higher share of taxable profit earned by

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the Exploration & Production segment which normally incurs an above-average rate of taxes compared to the rest of the Group operations. We expect that in the short-to-medium term the Group underlying tax rate will continue trending higher due to an increasing share of taxable profit earned by the Exploration & Production segment. Subsequently, we expect that improved profitability at other Group segments will partly rebalance that trend.

2011 compared to 2010. In 2011, income taxes amounted to euro 9,903 million, up by euro 1,322 million from a year ago, or 15.4%, mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit.

The Group consolidated tax rate increased compared to 2010, up from 54.2% to 55.7% (up 1.5 percentage points). This increase was due to the recognition of higher deferred taxes (euro 573 million) due to a changed tax rate applicable to a production sharing agreement, including an adjustment to deferred taxation which was recognized upon allocation of the purchase price as part of a business combination when the mineral interest was acquired by Eni.

These negatives were partly offset by the above mentioned gains on international transport interests (euro 1,044 million) which were non-taxable items, as well as lower non-deductible tax charges (in particular impairment of goodwill).

 

h) Non-controlling interest

2012 compared to 2011. Net profit pertaining to non-controlling interest was euro 743 million and concerned primarily Saipem SpA (euro 627 million).

2011 compared to 2010. Net profit pertaining to non-controlling interest was euro 975 million and concerned primarily Saipem SpA (euro 552 million).

 

Liquidity and capital resources

Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures and acquisitions over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of non-strategic assets. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and well-balanced financing structure.

 

 

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

	Year ended December 31,

		2010		2011		2012

(euro million)

Net profit - continuing operations		7,264			7,877			4,941
Adjustments to reconcile net profit to net cash provided by operating activities:
- amortization and depreciation charges, impairment losses and other non monetary items		8,521			8,606			11,354
- net gains on disposal of assets		(558	)		(1,176	)		(875	)
- dividends, interest, taxes and other changes		8,829			9,918			11,923
Changes in working capital related to operations		(1,158	)		(1,696	)		(3,373	)
Dividends received, taxes paid, interest (paid) received during the period		(8,758	)		(9,766	)		(11,614	)
Net cash provided by operating activities - continuing operations		14,140			13,763			12,356
Net cash provided by operating activities - discontinued operations		554			619			15
Net cash provided by operating activities		14,694			14,382			12,371
Capital expenditures - continuing operations		(12,450	)		(11,909	)		(12,761	)
Capital expenditures - discontinued operations		(1,420	)		(1,529	)		(756	)
Capital expenditures		(13,870	)		(13,438	)		(13,517	)
Investments and purchases of consolidated subsidiaries and businesses		(410	)		(360	)		(569	)
Disposals		1,113			1,912			6,014
Other cash flow related to investing activities (*)		202			668			(219	)
Changes in short and long-term finance debt		2,272			1,104			5,947
Dividends paid and changes in non-controlling interests and reserves		(4,099	)		(4,327	)		(3,746	)
Effect of changes in consolidation and exchange differences		39			10			(16	)
Change in cash and cash equivalent for the year		(59	)		(49	)		6,265
Cash and cash equivalent at the beginning of the year		1,608			1,549			1,500
Cash and cash equivalent at year end		1,549			1,500			7,765

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		(euro million)				2010		2011		2012

		Financing investments:
		- securities		(50	)		(21	)
		- financing receivables		(13	)		(26	)		(1,131	)
				(63	)		(47	)		(1,131	)
		Disposal of financing investments:
		- securities		5			71			4
		- financing receivables		32			17			1,044
				37			88			1,048
		Net cash flows from financing activities		(26	)		41			(83	)

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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,

		2010		2011		2012

(euro million)

Net cash provided by operating activities		14,694			14,382			12,371
Capital expenditures		(13,870	)		(13,438	)		(13,517	)
Acquisitions of investments and businesses		(410	)		(360	)		(569	)
Disposals		1,113			1,912			6,014
Other cash flow related to capital expenditures, investments and divestments		228			627			(136	)
Net borrowings (1) of acquired companies		(33	)					(2	)
Net borrowings (1) of divested companies					(192	)		12,446
Exchange differences on net borrowings and other changes		(687	)		(517	)		(340	)
Dividends paid and changes in minority interest and reserves		(4,099	)		(4,327	)		(3,746	)
Change in net borrowings (1)		(3,064	)		(1,913	)		12,521
Net borrowings (1) at the beginning of the year		23,055			26,119			28,032
Net borrowings (1) at year end		26,119			28,032			15,511

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

In 2012, 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 amounting to euro 11,354 million, which primarily related to depreciation, depletion amortization and impairment charges of tangible and intangible assets (euro 13,561 million). Adjustments to net profit from continuing operations also included gains on disposals (euro 875 million) and movements in net working capital (euro 3,373 million), while the difference between accrued amounts of income taxes, interest expenses and other items as opposed to amounts actually disbursed was immaterial.

In 2011, 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 amounting to euro 8,606 million, which primarily regarded depreciation, depletion amortization and impairment charges of tangible and intangible assets (euro 8,785 million). Adjustments to net profit also included gains on disposals (euro 1,176 million), movements in net working capital (euro 1,696 million), income taxes (euro 9,893 million) and interest expenses (euro 927 million) accrued in the year as opposed to amounts actually paid.

 

a) Changes in working capital related to operations

In 2012, changes in working capital absorbed cash flows amounting to a negative euro 3,373 million as a result of: (i) increasing inventories (up euro 1,395 million) mainly related to higher contract work in progress in the Engineering & Construction segment due to the fact that clients at certain important contracts have yet to formally accept the work in progress due to project complexity and, in certain other projects, important changes in work orders have been recognized but formal acceptance by the client remains pending; (ii) increased trade receivables net of increased trade payables (up by euro 1,155 million) which were mainly recorded in the Gas & Power segment due to a deteriorating credit environment; and (iii) and cash pre-payments amounting to approximately euro 500 million made to the Company’s gas suppliers which were recorded on the take-or-pay position accrued in 2012 including payment of outstanding receivables at the beginning of the year. For further details on that asset see "Item 18 – note 14 - Other non current assets – of the Notes to the Consolidated Financial Statements".

In 2011, changes in working capital absorbed cash flows amounting to a negative euro 2,176 million as a result of: (i) increasing oil, gas and petroleum products inventories (up euro 1,422 million) due to the impact of rising oil prices on inventories stated at the weighted average cost; (ii) cash pre-payments amounting to euro 324 million made to the Company’s suppliers of gas under long-term gas supply contracts whereby the Company has the contractual obligation to lift minimum annual quantities of gas or in case of failure, pre-pay the whole price or a fraction of those quantities as provided by the so-called take-or-pay clause. The amount was net of certain limited volumes make-up in the year. For further details on that asset see "Item 18 – note 14 - Other non current assets – of the Notes to the Consolidated Financial Statements"; and (iii) an increasing balance of trade receivables versus payables towards certain joint venture partners in the Exploration & Production segment.

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These negatives were partly offset by a reduced balance between trade payables and receivables also resulting from a higher volume of trade receivables due beyond the balance sheet date which were transferred without recourse to factoring institutions, amounting to euro 1,779 million in 2011 compared to euro 1,279 million at December 31, 2010.

 

b) Investing activities

	Year ended December 31,

		2010		2011		2012

(euro million)

Exploration & Production		9,690			9,435			10,307
Gas & Power		265			192			225
Refining & Marketing		711			866			842
Chemicals		251			216			172
Engineering & Construction		1,552			1,090			1,011
Other activities		22			10			14
Corporate and financial companies		109			128			152
Impact of unrealized intragroup profit elimination		(150	)		(28	)		38
Capital expenditures - continuing operations		12,450			11,909			12,761
Capital expenditures - discontinued operations		1,420			1,529			756
Capital expenditures		13,870			13,438			13,517
Acquisitions of investments and businesses		410			360			569
		14,280			13,798			14,086
Disposals		(1,113	)		(1,912	)		(6,014	)

Capital expenditures totaled euro 13,517 million and euro 13,438 million, respectively in 2012 and in 2011.

For a discussion of capital expenditures by business segment and a description of year-on-year changes see "Capital expenditures by segment".

Acquisitions of investments and businesses totaled euro 569 million in 2012 and euro 360 million in 2011.

In 2012, disposals amounted to euro 6,014 million and mainly related to: (i) the divestment of 30% interest less one share in Snam to Cassa Depositi e Prestiti (euro 3,517 million); (ii) the sale in two tranches of the interest in Galp for an overall amount of euro 963 million (a 5% interest sold to Amorim BV and a 4% sold through an accelerated book-building procedure); (iii) the disposal of a 10% interest in the Karachaganak field (euro 500 million); (iv) the disposal of a 1.43% interest in the Gassled JV, a network of gas pipelines and terminals for natural gas transportation (euro 130 million); and (v) the disposal of other non-strategic assets in the Exploration & Production segment (euro 565 million). The proceeds on the divestment of an interest of 5% in Snam before loss of control to institutional investors (euro 612 million) were recognized as an equity transaction.

In 2011, disposals amounted to euro 1,912 million and mainly related to: (i) the divestment of the Company’s interests in the entities engaged in the international transport of gas from Northern Europe and Russia (euro 1,463 million); (ii) the divestment of the 100% stake in Gas Brasiliano Distribuidora, engaged in the distribution activities in Brazil (euro 167 million); and (iii) non-strategic assets in the Exploration & Production segment (euro 154 million).

 

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

In 2012, dividends paid and changes in non-controlling interests and reserves (euro 3,746 million) mainly related to: (i) cash dividends to Eni shareholders (euro 3,695 million, which euro 1,956 million relating to 2012 interim dividend and euro 1,884 million to the balance dividend for fiscal year 2011 to Eni’s shareholders); and (ii) the distribution of dividends to non-controlling interests by Snam SpA and Saipem SpA (euro 486 million) and other consolidated subsidiaries (euro 53 million). Those outflows were partly absorbed by an equity transaction involving 5% of the share capital of Snam which was divested to third-party investors before loss of control for euro 612 million.

In 2011, dividends paid and changes in non-controlling interests and reserves (euro 4,327 million) mainly related to: (i) cash dividends to Eni shareholders (euro 3,695 million, of which euro 1,811 million related to the balance for the

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dividend relating the fiscal year 2010 and euro 1,884 million as an interim dividend for fiscal year 2011); and (ii) the distribution of dividends to non-controlling interests by Snam Rete Gas SpA and Saipem SpA (euro 518 million) and other consolidated subsidiaries (euro 34 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. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight on 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 according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to 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,

		2010		2011		2012

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)		7,478			20,305		27,783			6,495			23,102		29,597			5,184			19,279		24,463
Cash and cash equivalents		(1,549	)				(1,549	)		(1,500	)				(1,500	)		(7,765	)				(7,765	)
Securities not related to operations		(109	)				(109	)		(37	)				(37	)		(34	)				(34	)
Non-operating financing receivables		(6	)				(6	)		(28	)				(28	)		(1,153	)				(1,153	)
Net borrowings		5,814			20,305		26,119			4,930			23,102		28,032			(3,768	)		19,279		15,511

	As of December 31,

		2010		2011		2012

Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS		(euro million)		55,728			60,393			62,713
Ratio of total debt to total shareholders’ equity including non-controlling interest				0.50			0.49			0.39
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest				(0.04	)		(0.03	)		(0.14	)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage)				0.46			0.46			0.25

In 2012, net borrowings amounted to euro 15,511 million, representing a euro 12,521 million decrease from 2011. This decrease was mainly due to the divestment of a 30% interest in Snam to Cassa Depositi e Prestiti (euro 3,517

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million) and, following the loss of control in this entity, the deconsolidation of Snam net borrowings of euro 12,448 million, which entered finance arrangements with third-party lenders to reimburse intercompany loans.

Non-operating financing receivables related to a short-term financing granted to Cassa Depositi e Prestiti as part of a transaction to divest a 30% stake in Snam and related agreements to defer part of the cash consideration. The financing was reimbursed early in 2013.

Net cash provided by operating activities of continuing operations (euro 12,356 million) and proceeds from disposals of euro 6,014 million funded cash outflows relating to capital expenditures totaling euro 12,761 million and investments (euro 569 million) relating to the acquisition of Nuon in Belgium and joint venture projects, as well as dividend payments to shareholders.

The Group leverage was 0.25 at December 31, 2012 declining from 0.46 as of end of 2011 due to the lower level of net borrowings. The Group total equity increased due to net profit for the year, the revaluation of Eni’s residual interests in Galp and Snam at fair market value through equity at period end (up euro 133 million and euro 8 million, respectively) as they were classified as a financial instrument excluding those portions of interest revaluation that were recognized through profit because management elected the fair value option for the shares underlying convertible bonds in accordance with IFRS. Total equity also increased due to the divestment of a 5% non-controlling interest in Snam to institutional investors that occurred in July 2012, i.e. before loss of control which also determined an increase in the Group’s equity as the transaction consideration was higher than the corresponding book value disposed of (euro 371 million). On the negative side, shareholders’ equity was impacted by foreign currency translation differences (euro 713 million) in translating to euro amounts the net equity of subsidiaries whose functional currency is the U.S. dollar due to the dollar revaluation in exchange rates recorded at year end (up by 2% due to the exchange rate recorded on December 31, 2012 at euro 1= $1.32 compared to euro 1= $1.294 at December 31, 2011).

Total debt of euro 24,463 million consisted of euro 5,184 million of short-term debt (including the portion of long-term debt due within twelve months equal to euro 2,961 million) and euro 19,279 million of long-term debt.

Total debt included bonds for euro 16,824 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 3,051 million (including accrued interest and discount). Bonds issued in 2012 amounted to euro 1,864 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (87%), U.S. dollar (9%), pound sterling (3%) and 1% in other currencies.

In 2011, net borrowings amounted to euro 28,032 million, representing a euro 1,913 million increase from 2010. This increase was mainly due to the large amount of capital expenditures made in the year and dividend payments to shareholders. These outflows were partially funded with cash flows from operations and divestments. However, the Group leverage was 0.46 at December 31, 2011 declining from 0.47 as of end of 2010 due to the fact that the higher level of net borrowings was balanced by a greater total equity. The Group total equity increased due to net profit for the year and currency translation differences recorded in translating to euro amounts the net equity of subsidiaries whose functional currency is the U.S. dollar due to the dollar revaluation in exchange rates recorded at year end (up by 3.1% due to the exchange rate recorded on December 31, 2011 at euro 1= $1.294 compared to euro 1= $1.336 at December 31, 2010).

 

Capital expenditures by segment

Exploration & Production. In 2012, capital expenditures of the Exploration & Production segment amounted to euro 10,307 million, representing an increase of euro 872 million, or 9.2%, from 2011 mainly related to the development of oil and gas reserves (euro 8,304 million). Significant expenditures were directed mainly outside Italy, in particular Norway, the United States, Congo, Kazakhstan, Angola and Algeria. 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, Liberia, Ghana, Indonesia, Nigeria, Angola and Australia.

In 2011, capital expenditures of the Exploration & Production segment amounted to euro 9,435 million, representing a decrease of euro 255 million, or 2.6%, from 2010 mainly due to the development of oil and gas reserves (euro 7,357 million). Significant expenditures were directed mainly outside Italy, in particular Norway, Kazakhstan, Algeria, the United States, Congo and Egypt as well as blocks and interests in licenses awarded amounting to euro 754 million, mainly in Nigeria. Development expenditures in Italy concerned well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to euro 1,210 million were directed outside Italy in particular in Australia, Angola, Mozambique, Indonesia, Ghana, Egypt, Nigeria and Norway.

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Gas & Power. In 2012, capital expenditures in the Gas & Power segment totaled euro 225 million and mainly related to initiatives to improve flexibility of the combined cycle power plants (euro 131 million) and to develop the gas marketing activity (euro 81 million).

In 2011, capital expenditures in the Gas & Power segment totaled euro 192 million and mainly related to initiatives to improve flexibility of the combined cycle power plants (euro 87 million) and to develop the gas marketing activity (euro 97 million).

Refining & Marketing. In 2012, capital expenditures in the Refining & Marketing segment amounted to euro 842 million and mainly related to: (i) refining, supply and logistics with projects designed to improve the conversion rate and flexibility of refineries (euro 622 million), in particular at the Sannazzaro refinery; and (ii) upgrading and rebranding of the refined product retail network (euro 220 million).

In 2011, capital expenditures in the Refining & Marketing segment amounted to euro 866 million and mainly related to: (i) refining, supply and logistics in Italy and outside Italy (euro 629 million), with projects designed to improve the conversion rate and flexibility of refineries, in particular the Sannazzaro refinery, as well as expenditures on health, safety and environmental upgrades; and (ii) upgrade and rebranding of the refined product retail network in Italy (euro 168 million) and in the rest of Europe (euro 60 million).

Chemicals. In 2012, capital expenditures in the Chemical segment amounted to euro 172 million and mainly related to: (i) plant upgrades (euro 53 million) in particular in Ravenna; (ii) energy recovery (euro 41 million), mainly related to energy savings projects aimed at reducing CO₂ emissions; (iii) environmental protection, safety and environmental regulation (euro 38 million), relating primarily to the optimization of discharge water treatment; and (iv) upkeep of plants (euro 25 million).

In 2011, capital expenditures in the Chemical segment amounted to euro 216 million and mainly related to: (i) upkeep (euro 59 million); (ii) plant upgrades (euro 53 million), mainly regarding the project "Management of fugitive emissions" aimed at identifying the number of sites of potential emissions where the Company operates, putting Polimeri Europa in a leading position at international level; (iii) environmental protection, safety and environmental regulation (euro 46 million); and (iv) energy recovery project (euro 42 million), mainly related to energy savings projects aimed at reducing CO₂ emissions.

Engineering & Construction. In 2012, capital expenditures in the Engineering & Construction segment (euro 1,011 million) mainly related to: (i) construction of a new pipelayer, the construction of a new fabrication yard in Indonesia, the construction of a new fabrication yard in Brazil and upkeep works in the Engineering & Construction Offshore business; (ii) activities for the completion of the construction of the Scarabeo 8 and the upgrading of the Scarabeo 6 to make it capable of drilling up into 1,100 meters of water; (iii) realization/development of operating structures 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.

In 2011, capital expenditures in the Engineering & Construction segment (euro 1,090 million) mainly related to: (i) construction of a new pipelayer, the ultra-deep Field Development Ship FDS 2, activities for the conversion of a tanker into an FPSO and the construction of a new fabrication yard in Indonesia; (ii) activities for the completion of Saipem 12000, a new ultra-deep water drilling ship, construction of the Scarabeo 8 and 9 semi-submersible rigs and of the Perro Negro 6 jack-up; and (iii) realization/development of operating structures in the Onshore Drilling business unit.

 

 

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Recent developments

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

		Three months ended March 31,

		2012		2013

Average price of Brent dated crude oil in U.S. dollars (1)		118.49		112.60
Average price of Brent dated crude oil in euro (2)		90.38		84.66
Average EUR/USD exchange rate (3)		1.311		1.330
Average European refining margin in U.S. dollars (4)		2.92		3.92
EURIBOR - three month euro rate % (3)		1.0		0.2

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

 

Significant transactions

On March 13, 2013, Eni signed an agreement with CNPC/Petrochina to sell 28.57% of the share capital of the subsidiary Eni East Africa, which currently owns 70% interest in Area 4 for an agreed price equal to $4,210 million. The deal is subject to approval by relevant authorities. Once finalized, CNPC will indirectly acquire, through its 28.57% equity investment in Eni East Africa, a 20% interest in Area 4, while Eni will retain the 50% interest through the remaining controlling stake in Eni East Africa.

The Company’s Annual General Shareholders Meeting scheduled on May 10, 2013, is due to approve the full year dividend proposal. Eni expects to pay the balance of the dividend for fiscal year 2012 amounting to euro 0.54 per share in May 2013. The total cash-out is estimated at euro 1.96 billion.

 

Management’s expectations of operations

Management expects an uncertain macroeconomic outlook in 2013, particularly in the Euro-zone where businesses and households are cautious about investments and consumption decisions. We expect that a number of factors will support the price of crude oil including ongoing geopolitical risks as well as an improved balance between world demand and supplies of crude oil. For investment evaluation purposes and short-term financial projections, Eni assumes a full-year average price of $90 a barrel for the Brent crude benchmark. Management expects continuing weak conditions in the European gas, refining and marketing of fuels and chemical sectors. Demand for energy commodities is anticipated to remain sluggish due to the ongoing economic stagnation; unit margins are exposed to competitive pressures and the risk of new increases in the costs of oil-based raw materials in an extremely volatile environment. In this scenario, the recovery of profitability in the Gas & Power, Refining & Marketing and Chemical segments will depend greatly on management actions to optimize operations and improve the cost position.

Management expects that year-on-year comparability of results from continuing operations in 2013 will be affected by the fact that in 2012 Snam margins on intra-group transactions relating to the supply of gas transport and other services have been eliminated upon consolidation, while in 2013 those transactions will be accounted as third-party transactions, thus affecting the Group operating costs and profits.

 

Exploration & Production

The outlook of the production of liquids and natural gas is positive in 2013. Management expects to grow production by ramping-up fields started in 2012 and major project start-ups in 2013, mainly Kashagan in Kazakhstan, Angola LNG and the gas assets in Algeria. Based on those ongoing trends, we expect that oil and gas production will grow in 2013 compared to 2012.

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According to management’s plans, production growth will continue in the coming years as the Company is targeting an annual growth rate higher than 4% on average in the next 2013-2016 four-year period, based on our long-term Brent price assumptions of 90 $/BBL. 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 PSAs will decrease on average by approximately 1,000 BBL/d for a $1 increase in oil prices compared to current Eni’s assumptions for oil prices. Our production growth target factors in an average decline rate of 4% per annum at our currently producing fields throughout the plan period. To achieve that decline rate, we plan to carry out effective reservoir management and intense production optimization activities. The main driver of future growth will be the start-up of new fields which we estimate to add more than 700 kBOE/d of new production by the end of the plan horizon. We have a good level of visibility on those new projects as we have already sanctioned 65% of these projects and we expect to arrive at 90% by the end of 2013.

Management will focus on delivering the planned projects on time and on budget. We acknowledge that most 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. We plan to mitigate those risks in the future by continuing deployment of our capabilities and operational excellence and managing the industry constraints by means of: (i) in-sourcing critical engineering and project management activities and redeploying to other areas key competences which will be freed with the start-up of certain strategic projects and increasing direct control and governance on construction activities; and (ii) 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 expects that a number of factors will drive cost increase in the Exploration & Production operations over future years. Those factors include: (i) the growing complexity and scale of the Company’s planned development projects due to the circumstance that several planned or ongoing projects will be executed offshore or in remote/hostile environments where the Company has been experiencing above-average cost increases; (ii) increasing investing activities that are necessary to support production plateaus at existing fields and counteract natural depletion; and (iii) steady trends in costs for purchasing upstream goods and services. Due to those trends, operating costs and depreciation and amortization charges might trend higher in future years. We believe that a number of actions will help the Company absorb inflationary and cost pressures including tighter cost control, operation efficiency and increasing exposure to large fields which enable the Company to benefit from economies due to scale of operations. Management also plans to increase the share of operated production in the Company’s portfolio. Project operatorship enables the Company to better schedule and control project execution, expenditures and timely achievement of project milestones. In addition, 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

The outlook for natural gas sales is uncertain in 2013 due to macroeconomic headwinds, weak demand growth, continuing oversupplies and strong competition. Against this backdrop, management expects to achieve stable natural gas sales in 2013 compared to 2012 on a homogeneous basis, i.e. excluding the impact of the Galp divestment whereby Eni ceased reporting its share of Galp sales by mid-2012, having lost significant influence over the investee and other changes (91.46 BCM in 2012, including consolidated sales and Eni share of the joint ventures).

Management expects that continuing margin pressures will erode the business’s profitability in 2013 and beyond, particularly in the Italian market. A weaker-than-anticipated demand growth over the short-term and rising competitive pressures fuelled by ongoing oversupplies in the European market will reduce sales opportunities and trigger pricing competition also fuelled by rigidities at long-term supply contracts with take-or-pay clauses. We expect that minimum off-take obligations in connection with take-or-pay, long-term gas supply contracts and the necessity to minimize the associated financial exposure will force gas operators to compete more aggressively on pricing in consideration of lower selling opportunities, with negative effects on selling prices and profitability. Unit margins are expected to remain under pressure due to depressed spot prices at continental hubs which have become the contractual benchmark in selling formulas outside Italy. In addition, as long as the cost of gas supplies to the Group remains indexed to oil prices, the Company will be exposed to the risk of rising oil prices.

In Italy we expect that gas margins will also weaken, due to a number of negative catalysts including competitive pressure, an ongoing shift to index selling prices to hub benchmarks at large client segments, the current level of minimum take volumes at Italian operators which are well above market dimension, and finally the expected measures to be implemented by the Italian administration to cut the gas tariffs to residential customers. See also the other risk factors described in Item 3. These drivers will substantially reduce spot prices in the Italian market and negatively impact the profitability at our Italian operations.

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Against this scenario the Company has set the following priorities: preserve the operating cash flow during the worst phase of the downturn which is expected to continue well into 2013 and recover profitability in subsequent years as a result of contract renegotiations and an expected realignment of actual market imbalances.

The main driver to recover profitability in the Company’s gas marketing business is the renegotiation of pricing and other conditions of our supply contracts. In fact, take-or-pay supply contracts include revisions clauses allowing the counterparties to renegotiate the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Currently management is seeking to renegotiate approximately 80% of the Company’s supplies in order to reduce the purchase costs by aligning them to the spot prices at continental hubs. This can be achieved by increasing the exposure to spot gas in the indexation mechanism in the pricing formulas of gas supplied.

The outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately achieved and the timing of recognition in profit. Furthermore in case counterparties fail to arrange revised contractual terms, ongoing supply contracts provide a chance to each of them to recur to an arbitration proceeding for a definition of a commercial transaction. This adds to the level of uncertainty surrounding the outcome of those renegotiations. Considering also ongoing price renegotiations with Eni long-term clients, results of Gas Marketing activities are subject to an increasing rate of volatility and unpredictability.

Difficult market conditions in the European gas sector are expected to continue at least over the next two years. Looking beyond, management expects that a number of positive trends might help rebalance the European market. European gas demand is expected to recover in the long run driven by continuing expansion in the use of gas in electricity production, also benefiting from possible tighter European regulations on GHG emissions and the use of coal in firing power plants; in addition macroeconomic stability will help demand. Possible reductions in the role of nuclear energy in crucial countries like Japan, Taiwan and in Europe might support long-term trends in gas demand. In addition, excess supplies of LNG will be absorbed by continuing growing energy needs from the developing economies of China, India and other emerging countries in East Asia, the Middle East and South America. On the supply side, production rates at European fields are projected to decline, thus increasing the need for gas import requirements. However, there exist a number of downside risks to this outlook, particularly the possible long-term impacts on gas demand associated with the current economic downturn, an ongoing shift to renewable sources in the production of electricity and home heating and the other risk factors described in Item 3. Also it is possible that the United States government might accelerate the process to monetize the country’s large reserve base of shale gas by giving permission to reconvert existing re-gasification plants into LNG export facilities. Finally, new upstream projects might be started up in the long run adding to global LNG supplies (particularly the projects to develop gas reserves in Mozambique).

In a scenario of continuing weak demand and strong competition, management plans to seek to retain the Company’s market share in Italy and Europe by leveraging on improved costs in procurement and logistics, and effective commercial actions.

The Company intends to increase sales to business clients, including thermoelectric utilities, large industrial accounts and medium and small enterprises, 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 off-takes (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, a distinctive offer and competitive cost to serve; a wide range of sale channels and continuing innovation in processes, promotion and customer care and post-sale assistance. Thirdly we are targeting continuing expansion in the LNG international business by boosting the Company’s presence in the more profitable markets of the Far East and South America. Finally, the Gas & Power segment will continue to benefit from the stable profit stream coming from the semi-regulated international, transport activity.

Based on the above outlined trends and industrial actions, management believes that profitability in the Company’s gas marketing business will gradually recover along the plan period, however the visibility into future results of operations is constrained by the ongoing volatility in marketing margins. Our profitability outlook factors in the expected benefits of ongoing renegotiations at the Company long-term supply contracts which the Company is seeking to finalize over time during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3. Management will also seek to improve profitability by means of cost efficiencies, streamlining business support activities and reducing marketing and general and administrative costs. In addition, 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, customer base and market position). This can be achieved through strategies of asset-backed trading by entering into arbitrage contracts to leverage on commodity price volatility exploiting the flexibility provided by the Company’s assets. For further information on the market risk and how the

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Company manages it see "Item 11 – Quantitative and qualitative disclosures about market risk" and "Item 18 – note 34 of the Notes to the Consolidated Financial Statements".

Management believes that the weak industry outlook adversely affected by declining demand 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. From the beginning of the downturn in the European gas market to date, Eni has triggered the take-or-pay clause as the Company off-took lower volumes than its minimum take obligations accumulating deferred costs for an amount of euro 2.37 billion (net of limited amounts of volume make-up) paying the associated cash advances to its gas suppliers. Considering the Company’s outlook for its sales volumes which are expected to remain stable in 2013 and to grow at a moderate pace in the subsequent years, management intends to adopt the necessary initiatives to mitigate the financial risk related to take-or-pay obligations mainly in the domestic market where the expected volume of demand is lower in comparison with the minimum contracted supplies which Eni and other Italian gas importers are obliged to fulfill. The initiatives to mitigate the take-or-pay risk include the benefits expected from contract renegotiations which may temporarily reduce the annual minimum take, and provide more flexible off-take conditions such as changes in the delivery point or the possibility to replace supplies via pipeline with equivalent volumes of LNG. Based on the Company’s selling programs and higher flexibility already achieved or to be achieved through the above mentioned renegotiations, management believes that it is likely that in the next four year plan 2013-2016 Eni will manage to fulfill its minimum take obligations associated with its supply contracts thus minimizing the risk to liquidity.

These projections could be subject to the risks of further contraction in demand or the total addressable market. As to the deferred costs stated in the balance sheet, based on management’s outlook for gas demand and offer in Europe, and projections for sales volumes and unit margins in future years, the Company believes that the pre-paid volumes of gas due to the incurrence of the take-or-pay clause will be off-taken in the long term in accordance with contractual terms thus recovering the cash advances paid to suppliers. For more information see the specific risk paragraph in "Item 3 – Risk factors".

For a discussion of certain risks relating to the impact of the evolution of Italian regulation of the natural gas sector on Eni’s take-or-pay contracts see "Item 3 – Risk factors – Natural gas market".

 

Refining & Marketing

Management expects that the trading environment will show limited improvement throughout the next four years covered by the industrial plan. This business segment will continue facing a challenging refining outlook due to an anticipated weak demand, excess capacity and risks of margin pressure in case of upward trends in oil-linked raw material costs. As a result of those trends, we expect refining margins to remain at unprofitable levels in the foreseeable future. Furthermore, compressed differentials between heavy and light crudes will continue eroding Eni’s advantage of having complex refining capacity in place.

In the refining activity Eni will seek to mitigate the expected impacts of a negative scenario by stepping up efforts to: (i) optimize plant set-up and logistics operations by means of higher flexibility and process integration; (ii) improve efficiency by cutting fixed and logistics costs and pursue energy savings; (iii) make selective capital expenditure mainly aimed at upgrading conversion capacity and improving asset integrity. In particular we expect that the coming online of the EST (Eni Slurry Technology) plant in the Sannazzaro refinery aimed at the full conversion of the barrel will improve the competitiveness of our refining system; and (iv) implement a project to convert the Venice plant into a "bio-refinery" to produce bio-fuels and a logistic hub, as well as licensing proprietary technologies.

In Marketing activities, we expect a gradual improvement in results of operations leveraging effective marketing initiatives to retain customers by product innovation and a continuing focus on the quality of service and attractive promotional campaigns, the strength of the Eni brand targeting to complete the rebranding of the network, the automation of petrol stations and the expansion of non-oil activities. Management plans to improve the efficiency of the retail network by closing low-throughput outlets and other rationalizations. Our aim is to maintain the current market share in the Italian network market along the plan period. Retail operations abroad will be developed selectively.

With respect to short-term targets, management expects refining throughputs on Eni’s account to remain substantially in line with those processed in 2012 (30.01 mmtonnes in 2012). This projection assumes the restart of the Gela plant in June 2013 and the start-up of the new EST technology conversion plant at Sannazzaro, as well as the shut-down of the Venice plant to start the Green Refinery project. Retail sales of refined products in Italy and the Rest of Europe are expected to be in line with those of 2012 (10.87 mmtonnes, 2012 total), net of the effect of the "riparti con Eni" marketing campaign which was executed in the summer of 2012. Management expects a fall in domestic retail volumes due to an anticipated contraction in domestic demand, the effect of which will be absorbed by the expected increase in sales in the Rest of Europe.

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Based on the planned industrial actions, management expects the Refining & Marketing business to break even by 2014, assuming the same trading environment as in 2012.

 

Engineering & Construction

The Engineering & Construction segment is expected to face a declining profitability in 2013 compared to 2012. This trend will be negatively affected by the conclusion of highly-profitable projects, an anticipated slowdown in order acquisitions and the start of lower-margin projects in the Onshore and Offshore Engineering & Construction businesses.

Over the four year plan we confirm the segment’s target of consolidating the global competitive position achieved in the offshore and onshore businesses and its role as high-quality niche player in the deepwater drilling business. Saipem will 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 to regain profitability. In this light, Saipem aims to strengthen its construction ability particularly in large, highly-complex projects, in harsh environments, keeping a selective commercial approach.

 

Chemicals

Eni’s petrochemical 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. In 2012, Eni’s chemicals business reported wider operating losses of euro 485 million due to falling commodity demand due to the economic downturn and unprofitable product margins.

Short-to-medium term prospects of the business remain uncertain due to a weak macroeconomic outlook which will hamper a sustainable recovery in demand and ongoing trends in crude oil prices. Against this backdrop management intends to recover profitability by progressively reducing the exposure to loss-making commodity chemicals while at the same time developing innovative and niche productions which are expected to yield better returns, such as elastomers, with targeted production growth of over 60% to 2016 and the expansion of the specialties segment including bio-chemicals. Particularly, Eni intends to grow the latter business leveraging on the ongoing project of converting its Porto Torres site into a modern plant for the manufacture of eco-compatible chemical products. Management plans to continue efficiency actions and rationalization initiatives involving loss-making plants.

Eni is committed to expand its best production lines in emerging markets through strategic partnerships to which the Company plans to contribute technological know-how and Eni’s proprietary technologies. Management expects to achieve the break-even in the chemical business by end of the plan period also assuming the trading environment to be as unfavorable as in 2012.

 

Capital expenditure plan

Over the next four years, the Company plans to invest euro 56.8 billion in its businesses to support continued organic growth; approximately 83%, 2%, 4%, 6% and 4% of planned capital expenditures is expected to be directed to the Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction and Chemical segments, respectively. The planned amounts of expenditures also include capital allocation to joint venture projects and associates.

We plan to allocate the largest portion of resources amounting to some euro 39.9 billion to continuing 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 Nigeria, Angola, Norway, Venezuela, Mozambique, Indonesia and Iraq.

Exploration projects will be allocated approximately euro 5.5 billion, which are intended to pursue finding projects in well-established basins and in high potential frontier areas including in Angola, Russia, the United States, Nigeria, Egypt, Norway, Indonesia and Libya.

In the Gas & Power business the main investment projects will target the improvement of combined cycle power plants’ flexibility and initiatives in marketing activities in Italy and abroad.

In the Refining & Marketing segment we plan to make selective capital expenditure mainly targeted to refinery upgrade of conversion capacity and flexibility as well as plant reliability and security. We plan to finalize the project to

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convert the Venice plant into a "bio-refinery" to produce bio-fuels. Other capital projects will be directed to network upgrading and the completion of the rebranding of service stations to the "Eni" logo.

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 and to develop strategic initiatives in the field of elastomers in emerging markets.

Finally, in the Engineering & Construction business segment we plan to complete the construction of certain rigs and vessels and continuously enhance our fleet and logistic centers.

Eni’s capital expenditure program is expected to be in line with the previous industrial plan. Excluding the impact of the assumption of a stronger U.S. dollar exchange rate versus the euro compared to the previous industrial plan, the capital expenditure program shows an increase of euro 1.6 billion, or less than 3%. The increase is due to the pursuing of new growth opportunities in the Exploration & Production segment, including cash-outs dedicated to projects which will contribute beyond the plan horizon.

In the year 2013, management expects a capital budget in line with 2012 (euro 12.76 billion in capital expenditure and euro 0.57 billion in financial investments in 2012, relating to continuing operations). In 2013, management plans to focus on the development of hydrocarbons reserves in West and North Africa, Norway, Iraq and Venezuela, the exploration projects in West Africa, Egypt, the United States and emerging areas, as well as optimization and selective growth initiatives in other sectors, the start-up of the Green Refinery works in Venice, and elastomers and green businesses in the Chemical sector.

Management expects to pursue strict capital discipline when assessing individual capital projects. Management assumed an oil price of 90 $/BBL in the next four-year period; longer-term management assumed an oil price of 90 $/BBL that is adjusted to take account of expected inflation from 2017 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 2012, management assessed that the cost of capital to the Group marginally decreased from the previous year reflecting a reduction in the financial parameters used for assessing the cost of capital: cost of borrowings to Eni determined by expected trends for borrowing spreads and management’s estimates about the composition of the Company’s financial debt and reduced risk-free yields reflecting an expected decline in the risk premium of Italy. Those positive factors were partially absorbed by the increased weight of net equity in the determination of the cost of capital to the Group as the Board of Directors has reassessed the optimal mix between internally-generated funds versus third parties borrowings following the divestment of Snam. Management notes that the increased equity risk of Eni shares due to the divestment of a business with low volatility had no impact on the assessment of the cost of capital used for the capital evaluations in the Exploration & Production, Refining & Marketing and Chemical segments. This conclusion is supported by the fact that in the past management adopted discount rates which excluded the mitigating effect of the lower volatility of Snam in the Eni’s portfolio; (ii) an appreciation of the country risk which factors in the perceived level of risk associated with each country of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework as well as the consensus outlook; and (iii) a premium for the business risk.

 

Liquidity and leverage

In the foreseeable future, management is focused on preserving a solid balance sheet and strengthening the Company’s financial structure. Following the divestment of a significant interest in Snam and deconsolidation of the investee’s net borrowings as well as the transaction involving Eni’s interest in Galp, the Group achieved a substantial improvement in its leverage at 2012 year end down to 0.25. Management believes that this improved financial position is consistent with the Company’s new business profile, which features greater exposure to the Exploration & Production segment. See "Item 4 – Business developments".

For planning purposes, management projected the Company’s expected cash flows assuming a scenario of Brent prices at 90 $/BBL for the years 2013-2016 to assess the financial compatibility of its capital expenditure programs and dividend policy with internal targets of ratio of total equity to net borrowing. Under that assumption, in 2013 the ratio of net borrowings to total equity is projected to be substantially in line with the level achieved at the end of 2012 leveraging on cash flows from operations and portfolio management.

Going forward, management currently expects to seek to maintain this ratio within a target range of 0.1-0.3. This range will allow us to absorb temporary fluctuations in oil prices, the market environment and business results. The projected future cash flow from operations are estimated to fully fund capital expenditure plans. Furthermore management expects to deliver more than euro 10 billion of additional cash flows from asset disposal, mainly the divestment of the residual interest of Eni in Snam and Galp, the announced divestment of the 28.57% interest in Eni

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East Africa and other marginal assets in the Exploration & Production segment. See "Item 5 – Material developments". Our cash flow projections are based on our Brent scenario of 90 $/BBL flat in the next four years. We note that the Brent price in the period January 1 to March 28, 2013 was 112.60 $/BBL on average. We estimated that our cash flow from operations may improve by around euro 120 million for each dollar increase in Brent prices on a yearly basis.

For planning purposes, management assumed an average exchange rate of approximately 1.30 U.S. dollars per euro in the 2013-2016 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. See "Item 3 – Risk factors".

 

Dividend policy

Management plans to pay a dividend of euro 1.08 a share for fiscal year 2012 subject to approval from the General Shareholders’ Meeting scheduled for May 10, 2013. Of this, euro 0.54 per share was paid in September 2012 as an interim dividend with the balance of euro 0.54 per share expected to be paid in late May 2013. The dividend for fiscal year 2012 represents an increase of 4% compared to the 2011 dividend.

Given the Company’s changed business profile which entails both more growth options and more volatile results, as well as an improved balance sheet, management plans to distribute cash to shareholders by means of a revised dividend policy and share repurchases.

The new dividend policy contemplates a progressive, growing dividend at a rate which is expected to be determined year-to-year taking into account Eni’s underlying earnings and cash flow growth as well as capital expenditure requirements and the targeted financial structure. Management will also evaluate the achievement of the targeted production levels in the Exploration & Production segment, the status of renegotiations at gas long-term supply contracts in the Gas & Power segment and the delivery on efficiency gains in the downstream businesses. This dividend policy is based on management’s planning assumptions for oil prices at 90 $/BBL in the 2013-2016 period and a gradual European demand recovery.

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.

Management plans to commence a new buyback program, which has been authorized by the Shareholders Meeting for a total amount of euro 6 billion, at management’s sole discretion and when a number of conditions are met. These include, but are not limited to, a level of leverage which management assesses to be sound enough given market conditions and well within our target range limit of 0.3, and full funding of capital expenditure requirements and dividends throughout the plan period. In 2013, management would consider the activation of the buyback program, provided oil prices remain at current levels and Eni makes good progress on its business and cash flow targets.

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 34 of the Notes to the 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.

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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 34 - Guarantees, commitments and risks – of the Notes to the Consolidated Financial Statements".

 

Contractual obligations

Amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

	Maturity year

	Total		2013		2014		2015		2016		2017		2018 and thereafter

(euro million)

Total debt		25,429		5,703		2,222		4,030		2,182		2,967		8,325
Long-term finance debt		21,997		2,555		2,090		3,941		2,180		2,956		8,275
Short-term finance debt		2,223		2,223
Fair value of derivative instruments		1,209		925		132		89		2		11		50
Interest on finance debt		4,693		840		725		622		550		465		1,491
Guarantees to banks		212		212
Non-cancelable operating lease obligations (1)		2,571		722		515		323		250		201		560
Decommissioning liabilities (2)		15,048		174		198		85		259		555		13,777
Environmental liabilities (3)		1,777		362		375		260		160		69		551
Purchase obligations (4)		263,753		20,761		19,486		19,394		17,815		16,482		169,815
Natural gas to be purchased in connection with take-or-pay contracts (5)		247,324		18,463		17,763		17,840		16,377		15,094		161,787
Natural gas to be transported in connection with ship-or-pay contracts (5)		12,105		1,746		1,303		1,263		1,159		1,119		5,515
Other take-or-pay and ship-or-pay obligations		1,715		171		170		163		156		146		909
Other purchase obligations (6)		2,609		381		250		128		123		123		1,604
Other obligations (7)		139		4		3		3		3		3		123
of which:
- Memorandum of intent relating to Val d’Agri		139		4		3		3		3		3		123
Total		313,622		28,778		23,524		24,717		21,219		20,742		194,642

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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 dividends, 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 Italian 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 2,113 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 22 of the Notes to the Consolidated Financial Statements").

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The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment as of December 31, 2012. 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		2013		2014		2015		2016		2017 and thereafter

Committed on major projects		37,125		6,718		7,680		6,897		3,991		11,839
Other committed projects		21,902		6,940		3,782		1,584		1,100		8,496
Total		59,027		13,658		11,462		8,481		5,091		20,335

 

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 market place 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 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. For a description of how the Company manages the liquidity risk see "Item 18 – note 34 of the Notes to the Consolidated Financial Statements".

At December 31, 2012, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 12,173 million, of which euro 1,241 million were committed, and long-term committed unused borrowing facilities of euro 6,928 million. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial. Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 12.3 billion were drawn as of December 31, 2012.

 

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 amounts due.

For a description of how the Company manages the credit risk see "Item 18 – note 34 of the Notes to the Consolidated Financial Statements".

For information about credit losses in 2012 and the allowance for doubtful accounts see "Item 18 – note 9 of the Notes to the 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 34 of the Notes to the Consolidated Financial Statements".

 

Research and development

For a description of Eni’s research and development operations in 2012, 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 2013:

Name		Position		Year elected or appointed		Age
Giuseppe Recchi		Chairman		2011		49
Paolo Scaroni		CEO		2005		66
Mario Resca		Director		2002		67
Paolo Marchioni		Director		2008		43
Francesco Taranto		Director		2008		72
Carlo Cesare Gatto		Director		2011		71
Alessandro Lorenzi		Director		2011		64
Roberto Petri		Director		2011		63
Alessandro Profumo		Director		2011		56

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 5, 2011, 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, 2013.

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. One third of the Board is appointed from among the candidates of the non-controlling shareholders.

Giuseppe Recchi, Paolo Scaroni, Carlo Cesare Gatto, Paolo Marchioni, Roberto Petri and Mario Resca were candidates of the Ministry of the Economy and Finance. Alessandro Lorenzi, Alessandro Profumo and Francesco Taranto were candidates of institutional investors (non-controlling shareholders).

The Shareholders’ Meeting appointed Giuseppe Recchi as the Chairman of the Board of Directors and, on May 6, 2011, the Board appointed Paolo Scaroni as the Chief Executive Officer of the Company.

On the basis of Italian laws regulating the special powers of the State (see "Item 10 – Stock ownership limitation and voting rights restrictions"), the Minister of the Economy and Finance, in agreement with the Minister for Economic Development, may appoint another member of the Board of Directors, without voting rights, in addition to those appointed by the Shareholders’ Meeting. On the occasion of the last Board appointment, the Minister of the Economy and Finance opted not to exercise that power. Law Decree No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified Italian legislation governing the special powers of the State to comply with European rules. The previous provisions (Article 2 of Law Decree No. 332/1994 ratified by Law No. 474/1994 and its implementing decrees), as well as the provisions of the By-laws which are inconsistent with the new rules, will be repealed by the last of the implementing ministerial regulations in the areas of energy, transport and communications. At the date of the filing of the present Form, the ministerial regulations had not been issued. Among the provisions to be repealed, those governing enforcement of Law No. 474/1994 related to Eni have been expressly identified. Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.

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

Giuseppe Recchi was born in 1964 and has been Chairman of the Board of Eni since May 2011. He is also Vice Chairman of GE Capital Interbanca SpA; a member of the board of directors and of the audit committee of Exor SpA; a member of the European Advisory Board of Blackstone and a member of the Massachusetts Institute of Technology E.I. External Advisory Board. He is also a member of the Italian Corporate Governance Committee, of the executive committees of Confindustria (where he chairs the Foreign Investment Committee), Assonime (Association of Italian Joint Stock Companies), Aspen Institute Italia; a member of the board of directors of FEEM-Eni Enrico Mattei Foundation, of the Italian Institute of Technology and of the LUISS Business School Advisory Board. He is co-Chair of the B20 Task Force on Improving Transparency and Anti-Corruption and director of the World Economic Forum Partnering Against Corruption Initiative. He holds a degree in Engineering from the Polytechnic of Turin. In 1989 he started his career as entrepreneur at Recchi SpA, a general contractor active in 25 countries in the construction of

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high-tech public infrastructure. Since 1994 he has served as Executive Chairman of Recchi America Inc., the U.S. branch of Recchi Group. In 1999 he joined General Electric, where he held several management positions in Europe and in the United States. He served as Director of GE Capital Structure Finance Group; Managing Director for Industrial M&A and Business Development for GE EMEA; President & CEO of GE Italy. Until May 2011 he was President & CEO of GE South Europe. Mr. Recchi was a member of the Organizing Committee for the Rome Candidacy for the 2020 Olympic Games, a member of the board of Permasteelisa SpA a member of the Advisory Board of Invest Industrial (private equity) and visiting professor in Structured Finance at Turin University.

Paolo Scaroni has been Chief Executive Officer of Eni since June 2005. He is currently a Non-Executive Director of Assicurazioni Generali, Non-Executive Deputy Chairman of the London Stock Exchange Group and a Non-Executive Director of Veolia Environnement. He also sits on the Board of Overseers of Columbia Business School and of Fondazione Teatro alla Scala. After receiving a degree in economics and business from Luigi Bocconi University in Milan in 1969, he worked for three years at Chevron, before obtaining an MBA from Columbia University, New York, and continuing his career at McKinsey. In 1973 he joined Saint Gobain, where he held a series of management positions in Italy and abroad, until his appointment as head of the glass division in Paris in 1984. From 1985 to 1996 he was deputy chairman and CEO of Techint. In 1996 he moved to the UK and served as CEO of Pilkington until May 2002. From May 2002 to May 2005 he served as Chief Executive Officer and General Manager of Enel. From 2005 to July 2006 he was Chairman of Alliance Unichem. In May 2004 he was decorated as Cavaliere del Lavoro of the Italian Republic. In November 2007 he was decorated as an Officier of the French Légion d’Honneur.

Mario Resca was born in 1945 and has been a Director of Eni since May 2002. He graduated from the Università Luigi Bocconi of Milan with a degree in Economics and Business. He is also Chairman of Confimprese, Deputy Chairman of Sesto Immobiliare SpA and Director of Mondadori SpA. After graduating he joined Chase Manhattan Bank. In 1974 he was appointed manager of Saifi Finanziaria (Fiat Group) and from 1976 to 1991 he was a partner at Egon Zehnder. In this period he was appointed Director of Lancôme Italia and of companies belonging to the RCS Corriere della Sera Group and the Versace Group. From 1995 to 2007 he was Chairman and Chief Executive Officer of McDonald’s Italia. He was also Chairman of Sambonet SpA and Kenwood Italia SpA, a founding partner of Eric Salmon & Partners, Chairman of the American Chamber of Commerce, General Director of Italian Heritage and Antiquities in the Ministry of Cultural Heritage and Activities and Chairman of Convention Bureau Italia SpA. He was decorated as a Cavaliere del Lavoro in June 2002.

Paolo Marchioni was born in 1969 and has been a Director of Eni since June 2008. He is a lawyer specializing in criminal and administrative law, and has been admitted to argue before the Supreme Court and the higher Courts. He has been Chairman of the Board of Directors of Finpiemonte partecipazioni SpA since August 2010. He serves as a consultant to government agencies and business organizations on business, corporate, administrative and local government law. He was Mayor of Baveno (Verbania) from April 1995 to June 2004 and Chairman of the Assembly of Mayors of Con.Ser.Vco from September 1995 to June 1999. Until June 2004 he was a member of the Assembly of Mayors of the Asl 14 health authority, the steering committee of the Verbania health district, the Assembly of Mayors of the Valle Ossola waste water consortium, the Assembly of Mayors of the Verbania social services consortium. From April 2005 to January 2008 he was a member of the Stresa (VB) city council. From October 2001 to April 2004 he was a Director of CIM SpA of Novara (merchandise interport centre) and from December 2002 to December 2005 a Director and executive committee member of Finpiemonte SpA. From June 2005 to June 2008 he was a Director of Consip SpA. He was Vice President and Provincial Councillor in charge of the budget, financial reporting, property, legal affairs and productive activities of the Province of Verbano-Cusio-Ossola from June 2009 to October 2011. He was Director of the Provincial Board of the Province of Verbano-Cusio-Ossola from October 2011 to November 2012.

Francesco Taranto was born in 1940 and has been a Director of Eni since June 2008. He is currently Vice Chairman of Banca CR Firenze SpA (Cassa di Risparmio di Firenze SpA). He is also a Director and member of the Executive Committee of Rimorchiatori Riuniti SpA. He started working in 1959 in a stock brokerage in Milan. From 1965 to 1982, he worked at Banco di Napoli as deputy manager of the stock market and securities department. He held a series of management positions in the asset management field, notably as manager of securities funds at Eurogest from 1982 to 1984, and General Manager of Interbancaria Gestioni from 1984 to 1987. After moving to the Prime group (1987 to 2000), he was Chief Executive Officer of the parent company for an extended period of time. He was Director of ERSEL S.I.M., member of the steering council of Assogestioni and of the Committee for the Corporate Governance of listed companies formed by Borsa Italiana. He was a Director of Enel from October 2000 to June 2008.

Carlo Cesare Gatto was born in 1941 and has been a Director of Eni since May 2011. He graduated from the University of Turin with a degree in Economics and Business. He is a certified public auditor. He is currently Chairman of the Board of Statutory Auditors of RAI SpA, Natuzzi SpA, Difesa Servizi SpA, Rainet SpA and Director of Arcese Trasporti SpA. He has taught courses in Finance, Administration and Control at the Isvor Fiat SpA training institute. In 1968 he was hired by Impresit as Chief Accountant, where he managed the finance department of the local branch in Jordan. He joined the Fiat Group in 1969 where over the years he held a series positions of increasing responsibility in the area of finance, administration and control. From 1979 to 1990 he was in charge of Financial Reporting at the Fiat Group and was also responsible for controlling of the transport companies of the Fiat Group operating public transport concessions (Sapav, Sadem, Sita) and oversaw their subsequent sale. In 1990 he was appointed Joint Manager of Finance and Control of the Fiat Group, before becoming, in 1998, Chief Administration Officer (CAO). From 2000 to

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2004, he was Chief Executive Officer and Deputy Chairman of Business Solutions, a new sector created by Fiat to provide business services. In 1993 he was the Italian Representative to the European Commission for the fiscal harmonization of the Member States. In 1992 he was decorated as Cavaliere Ordine al Merito of the Italian Republic and, in 1995, an Ufficiale Ordine al Merito of the Italian Republic.

Alessandro Lorenzi was born in 1948 and has been a Director of Eni since May 2011. He is currently a founding partner of Tokos Srl, a securities investment consulting firm, and Chairman of Società Metropolitana Acque Torino SpA, and a Director of Ersel SIM SpA, Millbo SpA and Sicme Motori Srl. He began his career at SAIAG SpA, in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined 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, a position he held 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 the Coin Group. In 2006 he became Central Corporate Manager at Lavazza SpA, serving as a member of the Board of Directors from 2008 to June 2011.

Roberto Petri was born in 1949 and has been a Director of Eni since May 2011. He graduated with a degree in law from the Università degli Studi "Gabriele D’Annunzio" of Chieti and Pescara. He has been member of the Board of Directors of the Ravenna Festival since 2007 and he has been Chairman of Italimmobili Srl since 2011. In 1976 he was hired by Banca Nazionale del Lavoro (BNL) where he held a series of positions: head of the "Lending Advisory" of BNL in Busto Arsizio (1982), Deputy Manager for the industrial division at the BNL branch in Ravenna (1983-1987), Area Chief of BNL in Venice (1987-1989) and Joint Manager of the central office of BNL in Rome (1989-1990). In 1990 he was appointed commercial manager at Banca Popolare and in 1994 transferred, holding the same position, to Cassa di Risparmio di Ravenna Group (Carisp Ravenna and Banca di Imola). From 2001 to 2006 he was Chief Secretary to the Under-Secretary of Defence, where he was mainly involved in the Defence Ministry’s contacts with industry and international relations. From 2008 to 2011 he was Chief Secretary of the Minister of Defence. From 2003 to 2006 he was a Director of Fintecna SpA and from 2005 to 2008 a Director of Finmeccanica SpA.

Alessandro Profumo was born in 1957 and has been Director of Eni since May 2011. He received a degree in Business Administration from Università Luigi Bocconi of Milan. He is currently Chairman of Banca Monte dei Paschi di Siena, of Appeal Strategy & Finance Srl and member of the Supervisory Board of Sberbank. He is also member of the Board of Directors of the Bocconi University in Milan. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development projects at Bain, Cuneo e Associati firm (now Bain & Co). In 1991 he left the consulting field to join RAS, Riunione Adriatica di Sicurtà, where he was given responsibility, as General Manager, for the banking and parabanking sectors. He was also in charge of expanding the revenues of that group’s bank and of the other group companies operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager, with responsibility for Programming and Control, becoming General Manager in 1995. In 1997 he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On an international level he was Chairman of the European Banking Federation in Bruxelles and Chairman of the Internal Monetary Conference Washington. In May 2004 he was decorated as a Cavaliere del Lavoro.

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Senior Management

The table below sets forth the composition of Eni’s Senior Management as at December 31, 2012. It includes the CEO, as General Manager of Eni SpA, the Chief Operating Officers, the Chief Financial Officer, the Chief Corporate Operations Officer and the Executives who report directly to the CEO.

Name		Management position		Year first appointed to current position		Total number of years of service at Eni		Age

Paolo Scaroni		General Manager of Eni		2005		8		66
Claudio Descalzi		Exploration & Production Chief Operating Officer		2008		32		57
Angelo Fanelli		Refining & Marketing Chief Operating Officer		2010		32		60
Umberto Vergine (a)		Gas & Power Chief Operating Officer		2012		29		55
Alessandro Bernini (b)		Chief Financial Officer		2008		17		52
Massimo Mondazzi (c)		Chief Financial Officer		2012		21		49
Salvatore Sardo		Chief Corporate Operations Officer		2008		8		60
Stefano Lucchini		International Relations and Communication Senior Executive Vice President		2005		8		50
Massimo Mantovani		General Counsel Legal Affairs Senior Executive Vice President		2006		20		49
Roberto Ulissi		Company Secretary Corporate Affairs and Governance Senior Executive Vice President		2006		7		50
Marco Petracchini		Internal Audit Senior Executive Vice President		2011		14		48
Marco Alverà		Trading Senior Executive Vice President (*)		2012		8		37
Salvatore Meli		Research and Technological Innovation Executive Vice President		2011		31		59
Leonardo Bellodi (d)		Government Affairs Executive Vice President		2012		7		47
Stefano Leofreddi (e)		Integrated Risk Management Senior Vice President		2012		27		52
Raffaella Leone		Executive Assistant to the CEO		2005		8		50

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(a)		Since December 5, 2012, Paolo Scaroni has been Gas & Power Chief Operating Officer ad interim.
(b)		Until December 5, 2012.
(c)		As of December 5, 2012.
(d)		As of July 2, 2012.
(e)		As of April 10, 2012.
(*)		As of March 15, 2013, the Department has been renamed "Optimization & Trading".

The Chief Operating Officers, the Chief Financial Officer, the Chief Corporate Operations Officer and the Executive Assistant to the CEO, the Senior Executive Vice Presidents and the Government Affairs Executive Vice President and the Chief Executive Officer of Versalis SpA⁷ are permanent members of the Management Committee⁸, which advises and supports the CEO. The Chief Operating Officers, the Chief Financial Officer and the Senior Executive Vice President of the Internal Audit Department are appointed by the Board of Directors, acting upon a proposal of the CEO in agreement with the Chairman. Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause, except for the Senior Executive Vice President of the Internal Audit Department and the Company Secretary, who are appointed by the Board of Directors, the latter upon a proposal of the Chairman.

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Senior Managers

Claudio Descalzi was born in Milan in 1955. He received a degree in Physics in 1979 from the Politecnico University of Milan. He joined the Eni in 1981 as an Oil-Gas field petroleum engineering and project manager, following the development of the North Sea, Libya, Nigeria, and Congo. In 1990 he was appointed head of reservoir and operating activities for Italy. In 1994 he was named Managing Director of the Eni subsidiary in Congo and in 1998 became Vice Chairman and Managing Director of Naoc, Eni’s 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 while also covering the role of Chairman of the Board of several Eni subsidiaries in the area. In 2006 he was appointed Deputy Chief Operating Officer of the Eni Exploration & Production Division. In 2012 he was awarded the "Charles F. Rand Memorial Gold Medal 2012" award by the Society of Petroleum Engineers and the American Institute of Mining Engineers. Since 2006 he has been President of Assomineraria and Vice President of Confindustria Energy. Since July 30, 2008 he has been Chief Operating Officer of Eni Exploration & Production Division.

Angelo Fanelli was born in Rome in 1952. He has a degree in mechanical engineering from the University La Sapienza in Rome. After gaining experience at other companies, he joined the Eni Group in 1981, and in the first seven years held "field" positions in the Extra-network and Network markets as Technical Assistant, Lubricants and Sales Promoter on the Motorway Network. From 1988 to 1993 he was Head of the Bologna and Florence sales areas. From 1994 to 2004 he held a number of positions in the Network sector. He was appointed Head of Road Network Management, Head of the Ordinary Network and subsequently Head of Business Network Italy and Head of the Agip Road Transport Division, before becoming Head of Retail Business at the R&M Division. From 2003 to 2004 he was Chairman and Managing Director of AgipRete SpA. In 2004 he was appointed Commercial Director Italy, a job he held until 2005 when he took up the position of Head of Logistics at the Genoa headquarters. In 2006 he was appointed Commercial Director (Executive Vice President) of the Refining & Marketing Division. Since 2008 he has been a member of the board of Europia in Brussels. Since April 2010 he has been Chairman of Eni Trading & Shipping SpA. Since June 2012 he has been member of the steering council of AISCAT. On April 6, 2010 he was appointed Chief Operating Officer of Eni SpA - Refining & Marketing.

Umberto Vergine was born in Milan in 1957. He is a Chartered Civil Engineer from Politecnico University of Milan and joined Eni in 1984. Having started his career at Agip as a Petroleum Engineer, he worked between 1985 and 1991 in Norway on the Ekofisk field, in Angola in Cabinda and in Libya in Tripoli. He then took the position of Production Manager of the Crema District in the North of Italy. Between 1993 and 2001, he held various leading positions overseas, managing different Eni E&P companies: District Manager of Agip UK in Aberdeen, District General Manager of Nigerian Agip Oil Co (NAOC) in Port Harcourt and General Manager of Petrobel Co in Egypt. In 2001 he was Managing Director of Lasmo Venezuela in Caracas. At the end of 2002 he was appointed Managing Director of Ieoc in Cairo. Returning to Italy in 2004, he held the following positions in the Eni E&P Division: Regional Vice President West Africa and Egypt; Senior Vice President for North Sea, Americas, Russia, Far East and Pacific; Senior Vice President Technologies & Services and Executive Vice President for South Europe, Central Asia, Far East and Pacific. In 2010 he was appointed Eni SpA Senior Executive Vice President for Studies and Research. He has been member of the Board of Directors of Saipem SpA, of Eni Trading and Shipping, of Eni Foundation and Eni’s representative on the Board of the Fondazione Politecnico of Milan. From January 2012 until December 5, 2012 was been Chief Operating Officer of the Gas & Power Division⁹. On December 5, 2012 he was appointed Chief Executive Officer and non-independent executive Director of the Board of Directors of Saipem SpA.

Alessandro Bernini was born in 1960 in Borgonuovo Val Tidone, in the province of Piacenza, Italy. He started his career in 1979 at Neutra Revisioni Sas, based in Milan, first as Junior Accountant in the Auditing Activities Department then as Accountant in Charge. In 1981, he joined Ernst & Young thereafter becoming Senior, Supervisor and Manager. On January 1, 1995 he was appointed Partner of the Company and Chartered Accountant Manager for the Areas of Piacenza, Parma and Cremona and Technical Manager for the branch based in Brescia. In the same period he was also engaged as a Lecturer for post-graduate Master’s Degree courses at the Universities of Pavia and Parma. On September 1, 1996 he joined the Eni Group as Administration Department Manager for Saipem SpA. In 2006 he was appointed Group Chief Financial Officer for Saipem SpA. He has held executive management roles in many important companies of the Saipem Group. From August 1, 2008 until December 5, 2012 he was Chief Financial Officer of the Eni Group.

Massimo Mondazzi was born in Monza in 1963. He received a degree in Business Administration from the University L. Bocconi in Milan in 1987. Before joining Eni in 1992, his early career was spent gaining professional experience in industrial and consulting firms. He worked in the Administration and Control area of the Eni Exploration and 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 Central Asia, Far East and Pacific Region. In the last three years of his tenure as Executive Vice President for Central Asia, Far East and Pacific Region, he contributed to the consolidation of Eni’s activities in the Exploration and Production Division, to the launch of new development projects and to Eni’s entry into new countries.

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Since December 5, 2012 he has been Chief Financial Officer of the Eni Group and the officer responsible for preparing financial reporting documents pursuant to Article 154-bis of Italian Legislative Decree No. 58/1998.

Salvatore Sardo was born in Turin in 1952. He has been Chief Corporate Operations Officer of Eni SpA since November 2008, reporting directly to the Chief Executive Officer with responsibility for policies and control of procurement, the department of human resources and organization, the department of Information & Communication Technology, Health, Safety, Environment & Quality, Security, Compensation & Benefits and the subsidiary EniServizi. Since April 8, 2009, he has also been the Chairman of Eni Corporate University. From April 27, 2010 to October 15, 2012 he was also Chairman of Snam SpA¹⁰. He graduated with a degree in Economics from the University of Turin. He is also a Chartered Accountant and Auditor. From 1976 to 1981 he worked with Coopers & Lybrand as auditor, rising the position of supervisor. From 1981, he served at Stet as Head of Control for manufacturing. In 1991 he was appointed to the position of co-central director and, from 1992 to 1996, central director of Planning and Control. He was appointed in 1997 as deputy general manager of finance, administration and control at Telecom Italia. From 1998 to June 2001, he was Chairman of Seat Pagine Gialle SpA. From October 1999 he served as operational head of the Real Estate Department of Telecom Italia. He has been Chairman of EMSA, Chairman and CEO of EMSA Servizi and Chairman and CEO of IMMSI, a company listed on the Milan Stock Exchange, as well as operational Chairman of TELIMM, IMSER and Telemaco, companies operating in the same sector. From November 2000, he served as head of the Real Estate and Services business unit of Telecom Italia. From October 2001 he was head of the Real Estate and General Services operating unit, reporting to the Chief Executive Officer of Telecom Italia. From February 2003 he worked as group head of Procurement, Services and Security of Enel SpA, reporting directly to the Chief Executive Officer, with a volume of procurement of over euro 3 billion. In 2005, he was appointed Senior Executive Vice President Human Resources and Business Services of Eni SpA, reporting to the Chief Executive Officer, with responsibility for policies and control of the Information & Communication Technology department and the subsidiary EniServizi. In July 2011 he was decorated as Grande Ufficiale dell’Ordine al merito of the Italian Republic. On June 2008 he was decorated as Commendatore dell’Ordine al merito of the Italian Republic. From April 2008 to April 2011 he was a member of the Board of Directors and the Remuneration Committee of Saipem. He has also served as a standing statutory auditor of Italtel, Finsiel and Telecom Italia.

Stefano Lucchini was born in Rome in 1962. He is married with two children and has a degree in Economics from the LUISS University of Rome. His first job was in the research department at Montedison. After a period as assistant to the Chairman of the Energy and Commerce Committee of the U.S. Congress in Washington D.C., he served as director of communications at Montedison USA in New York. Returning to Italy in 1993, he was responsible for financial communications and investor relations for the Montedison Group. He joined Enel in 1997 as Head of corporate communications, and investor relations (where he oversaw the company’s IPO) and subsequently as the Group’s head of external relations. He has also been the head of external relations for Confindustria, the Italian employers’ federation. In June 2002 he was appointed head of external relations for the Banca Intesa Group. In July 2005 he was appointed as Eni’s Senior Executive Vice President of public affairs and corporate communication and, since July 2012, he has been Senior Executive Vice President of international relations and communication and chairman of Eni USA Inc. He teaches at the Advanced School of Journalism at the Catholic University of Milan, of which he is also a member of the evaluation committee. Since 2007 he has been a member of the Supervisory Board of Confindustria and of the executive board of UPA. He is also a member of the boards of Censis, Fondazione Eni Enrico Mattei (FEEM) and Eni Foundation. Since 2005 he has been a member of the Board of Directors of AGI. He is a Grand Officer of Order of Merit of the Italian Republic and was awarded the Silver Cross Medal by the Italian Red Cross. He is a Member of the Advisory Board LUISS MBA Program and member of the Board of Directors both of the American Chamber of Commerce in Italy and Unindustria and a director of the Energy Foundation. He is a visiting fellow at Oxford University.

Massimo Mantovani was born in Milan in 1963. He has a degree in Law from the Università Statale di Milano and a Master in Law (LLM) from the University of London. He is registered to practice law in Italy and in England as solicitor. For around 5 years he worked for a number of law firms in Milan and London before joining the legal department of Snam SpA in 1993. In October 2005 he was appointed as Legal Affairs Senior Executive Vice President of Eni SpA after a period in which he was legal director of the Gas & Power Division of Eni. Since 2005 he has been a member of the Board of Directors of Snam Rete Gas SpA¹¹ and is a member of the Watch Structure of Eni SpA.

Roberto Ulissi was born in Rome in 1962. He is qualified as a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance, head of the Banking and Financial System and Legal Affairs Department. He was a director of Telecom Italia, Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He was also a member of numerous Italian and European commissions representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law and, at the 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 a

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Grande Ufficiale of the Italian Republic. Since 2006 he has been Senior Executive Vice President Corporate Affairs and Governance and Company Secretary of Eni. He is also a director of Eni International BV.

Marco Petracchini was born in Rome in 1964. He graduated cum laude in economics from the University La Sapienza in Rome in 1989. After graduation, he was hired by Esso Italiana where he held a number of positions in the IT, Finance and Auditing sectors. He joined Eni in 1999, where he was rapidly promoted in the Internal Audit Department. He is currently Senior Executive Vice President of the Internal Auditing Department and supervisor of the Internal Control function. He is also a member of the Control Body and Secretary of the Internal Control Committee of Eni SpA. He holds international qualifications, including that of Certified Internal Auditor (CIA), awarded by the Institute of Internal Auditors with which he also gained an honorable mention, and Certified Fraud Examiner (CFE), awarded by the Association of Certified Fraud Examiners.

Marco Alverà graduated from the London School of Economics in 1997 with a degree in Philosophy and Economics. He is currently an Associate Fellow at the Oxford University Centre for Corporate Reputation, where he specializes in developing and teaching case studies on doing business in Africa. He started his career at Goldman Sachs in London in 1997 in M&A and Private Equity. In 2000 he co-founded Netesi, Italy’s first broadband ADSL company. From 2002 to 2005 he joined Enel as Head of Group Corporate Strategy before becoming in 2004 Chief Financial Officer of Wind Telecom, overseeing the sale of Wind to Orascom. He joined Eni in 2005 as Assistant to the CEO for special initiatives. In 2006 he was appointed Director of Supply & Portfolio Development at Eni Gas & Power Division and Chief Executive Officer of Bluestream and Promgas. In 2008 he moved to Eni Exploration & Production Division where he was appointed Executive Vice President for Russia, North Europe and Americas. 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. As of January 16, 2012 he is also Senior Executive Vice President of Eni Trading Business Unit¹². He has served on the Board of Gazprom Neft and is Chairman of the Board of Eni’s Russian subsidiaries.

Salvatore Meli was born in Torre del Greco in 1953. After earning his degree in Chemical Engineering, in 1980 he began his career as a researcher, gradually taking on positions of greater responsibility until 1992, when he became Head of Applied Research in Engineering at Eni Research. In 1998 he became Head of Research of Eni Technologies and took over responsibility for the entire Department of Engineering, Modeling and Pilot Systems, a position he retained until 2003. In January 2004 he was appointed Head of Planning Technology and Development at Eni Corporate, and then, in August 2006, he took the position of Director of Research and Technological Innovation of the E&P Division, with the aim of enhancing the role of technological innovation as a lever in strengthening the competitive position of the E&P business. On January 1, 2008 he was appointed Head of Technologies in Strategic Management and Research at Eni Corporate, with responsibility for monitoring the development of technologies of interest to Eni’s activities and for identifying development opportunities for new technologies and new energy sources. In this position, particular emphasis was placed on activities enhancing intellectual property through a significant increase in the number and quality of patents filed. On June 10, 2009, as part of Eni Corporate Management Studies and Research, he was appointed Executive Vice President of Research & Technological Innovation; since August 2, 2011 he has been reporting directly to the Chief Executive Officer under the aegis of the Research & Technological Innovation Department.

Leonardo Bellodi was born in Venice in 1965. After graduating with a degree in law, he worked at the United Nations and for international law firms. He is the author of numerous publications and has taught international and EU law. In 1998 he was hired as Head of the Eni Delegation to the European Union. Since his return from Brussels in 2006, he has held positions of increasing responsibility at Eni’s Department of Public Affairs and Communication, and in 2011 he was appointed as Public Affairs Executive Vice President. Since July 2012 he has been Executive Vice President of Government Affairs, reporting directly to the Chief Executive Officer of Eni SpA. Since 2009 he has also been Chairman of the Board of Directors of Syndial SpA.

Stefano Leofreddi was born in Rome in 1960. He graduated with a degree in economics and, after experience as a researcher at the International Trade Centre (UN/WTO) in Geneva, he joined Eni in 1986, working in planning and control at EniChem, where he remained until 1998, in positions of increasing responsibility. Then, at Eni Corporate, he was in charge of major innovation projects in the administration and control area until 2001, when he was appointed Head of Administration and Control at Stogit, where he contributed to the company’s start up. Returning to Eni Corporate in 2007, he coordinated the Eni gas infrastructure functional unbundling program (Snam¹³, Italgas, Stogit). In 2009 he was appointed Head of Risk Control and Financial Systems. He is currently Senior Vice President of Integrated Risk Management, reporting directly to the Chief Executive Officer.

Raffaella Leone with Eni since 2005, she is the Executive Assistant to the CEO of Eni. She is President of Servizi Aerei SpA, Vice President of Eni Foundation, member of the Board of Directors of the news agency AGI (Agenzia Giornalistica Italia) and of the Board of Directors of Fondazione Eni Enrico Mattei. Previously, she was the Executive Assistant to the CEOs of Enel (from May 2002 to 2005) and of Pilkington (from 1996 to May 2002).

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Compensation

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

Moreover, in accordance with the applicable legal and regulatory duties (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, the Board of Directors approves and submits to the annual Shareholders’ Meeting, the guidelines for the remuneration of Directors, Chief Operating Officers of Eni Division and other Managers with strategic responsibilities.

Main elements of the remuneration policy defined for 2013 and of the 2012 compensation of the Chairman, the CEO, other Board members and Eni’s three General Managers are described below.

 

CHAIRMAN OF THE BOARD OF DIRECTORS

Shareholder established remuneration
The Shareholders’ Meeting of May 5, 2011, set remuneration of the Chairman of the Board of Directors, envisaging a fixed gross annual compensation for the mandate equal to euro 265,000, unchanged with respect to the previous mandate. In addition, the Shareholders’ Meeting resolved as for the other Directors, an annual bonus connected to the Eni’s performance in terms of total return to shareholders, as benchmarked to that achieved by the other seven largest international oil companies in terms of market capitalization (Exxon, Shell, Chevron, British Petroleum, Total, Conoco, and Statoil). The incentive is paid in the amount of euro 80,000 or euro 40,000, unchanged with respect to the previous mandate, in case Eni ranks first or second, or third or fourth, respectively in a given year. In the absence of such results, the bonus is not paid. In 2012, the Company did not meet the performance conditions to award the bonus.

Remuneration for powers delegated
On June 1, 2011, the Board of Directors defined an additional remuneration for the powers delegated to the Chairman in conformity with the Company’s By-laws. To that end, a fixed annual emolument in the amount of euro 500,000 gross was established, unchanged from the previous mandate, as well as a variable annual component with a minimum, target and a maximum incentive level respectively set at 51%, 60% and 78% of the fixed emolument established for the delegated powers. The objectives for the incentives that will be paid in 2013 are focused on Eni’s economic/financial and operational/industrial performance results achieved by Eni during the year prior to that of the payment and on the implementation of the strategic and sustainability guidelines defined in the Strategic Plan. Studies are in progress regarding the introduction of specific objectives on the activities carried out by the Chairman to ensure the effective functioning of the Board of Directors, for the incentive that will be paid in 2014.

Treatments established in the event of termination of office or employment
No specific treatments are envisaged upon the termination of the office of the Chairman or agreements that envisage indemnities in the case of early termination of the mandate. In any case, the Committee is entitled to propose to the Board the possible payment of an indemnity, upon completion of the mandate, commensurate with the compensation received and with the achievement of performance of particular relevance to Eni.

Benefits
Insurance related benefit, including the case of risk of death and disability, are envisaged for the Chairman.

 

NON-EXECUTIVE DIRECTORS

Shareholder established remuneration
The Shareholders’ Meeting of May 5, 2011, set remuneration of the Directors for the 2011-2014 mandate, envisaging a fixed gross annual compensation for the mandate equal to euro 115,000, unchanged from the previous mandate. In addition, the Shareholders’ Meeting resolved an annual bonus connected to Eni’s performance in terms of total return to shareholders, as benchmarked to that achieved by the other seven largest international oil companies in terms of market capitalization (Exxon, Shell, Chevron, British Petroleum, Total, Conoco and Statoil). The incentive is paid in the amount of euro 20,000 or euro 10,000, unchanged with respect to the previous mandate, in case Eni ranks first or second, or third or fourth, respectively in a given year. Absent such results, the bonus is not paid. In 2012, the Company did not meet the performance conditions to award the bonus.

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Compensation for participation in Board committees For non-executive and/or independent Directors, it is confirmed the payment of additional annual compensation for participation in Board committees, as follows:

•		for the Control and Risk Committee, compensation equal to euro 45,000 for the Chairman and euro 35,000 for other members was envisaged, with regards to the more significant role played by the Committee in supervising company risk;
•		for the Compensation Committee and the Oil-Gas Energy Committee compensation, equal to euro 30,000 for the Chairman and euro 20,000 for other members, already envisaged in the previous mandate; and
•		for participation on the Nominating Committee, established in July 2011, no compensation is paid.

In the case of participation on more than one Committee (with the exception of the Nominating Committee), a 10% reduction will apply.

Treatments established in the event of termination of office or employment
No specific treatments are envisaged upon the termination of office of the non-executive Directors or agreements that envisage indemnities in the case of early termination of the mandate.

 

CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER
The remuneration structure for the Chief Executive Officer and General Manager for the current mandate was approved by the Board of Directors on June 1, 2011, in relation to the powers delegated to him and incorporates both the compensation determined by the Shareholders’ Meeting on May 5, 2011 for Directors, as well as compensation that would possibly be due for positions held at the Board of Directors of subsidiaries or associated companies.

Fixed remuneration
Fixed remuneration is set at an annual gross amount of euro 1,430,000, of which euro 430,000 for the role of Chief Executive Officer, and euro 1,000,000 for the role of General Manager. These amounts are unchanged with respect to the previous mandate, in consideration of the continuity of the powers delegated to him.

In addition, in his role as Eni Executive, the General Manager is also entitled to receive the indemnities due for travel, both in Italy and abroad. This is in line with applicable provisions in the relevant national collective labor agreement for managers and in the complementary company level agreements.

Annual variable incentives
The annual variable incentive plan envisages compensation determined with reference to a minimum (performance = 85), a target (performance = 100) and a maximum incentive level (performance = 130), set at 87.5%, 110% and 155% of the total fixed remuneration, respectively, based on the results achieved by Eni in the previous year, as measured according to a performance scale 70÷130, in relation to the weight assigned to each (below 70 points the performance of each objective is considered zero and the minimum overall performance is set at 85 points).

The objectives set for the incentives which will be paid in 2013, are focused on: (i) the implementation of strategic, financial and sustainability policies (30%) in terms of reserve allocation, increase in exploration resources, optimization of business activities, financial leverage, maintenance of Eni's presence in the "Ftse4good" index and the "Dow Jones Sustainability Index"; (ii) the operating performance of the Divisions (30%); (iii) adjusted EBIT (30%); and (iv) the efficiency program (weight 10%).

The Company’s Compensation Committee is entitled to propose to the Board of Directors extra compensation to the Chief Executive Officer and General Manager in the case of achievement of strategic transactions or arrangements that strengthen the Company’s competitive position over the medium-long term.

Long-term variable incentives The long-term variable component consists of two distinct plans:

•

Deferred Monetary Incentive Plan (DMI), also envisaged for managers of the Company, with three annual assignments, starting in 2012 based on Company performance measured in terms of EBITDA (Earnings before interest, tax, depreciation and amortization). This parameter is generally used in the oil&gas sector as an indicator of performance and is in line with Eni's growth and consolidation strategy for the Company's current placement in business areas. The assignment and payment of the incentive after a three-year vesting period, are subject to the following conditions: (i) the incentive to be assigned each year is determined in relation to the EBITDA results carried out by the Company during the previous year, measured on a performance scale 70÷130, with a minimum, target and maximum value of 38.5%, 55% and 71.5%, respectively of total fixed remuneration. Where results are below the minimum performance level, no assignment is made; and (ii) the incentive to be paid at the end of the three-year vesting period is determined on the basis of the average annual EBITDA results achieved during the vesting period, as a percentage between zero and 170% of the assigned value. The annual performance is evaluated on a scale between 70% and 170% (below the minimum threshold of 70%, performance is assumed to be zero). Should the

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		current office not be renewed, the payment of each incentive assigned will occur at the natural expiry of the relative vesting period, in accordance with the performance conditions defined in the Plan.
•		Long-Term Monetary Incentive Plan (LTMI) linked to the results of profitability achieved by the Company in connection with its main international competitors, and extended to all critical managerial resources to the business. This Plan, adopted in the previous mandate in place of the Stock Option Plan which has not been operational since 2009, was confirmed by the Board of Directors on June 1, 2011, at the last renewal of the company's bodies. For the Chief Executive Officer and General Manager three annual assignments are envisaged, as of 2011, subject to the following conditions: (i) the target incentive to be assigned each year is determined on the basis of a valorization process of the previous Stock Option Plan, performed by specialized external companies on the basis of procedures and criteria established by the Board, taking into account the value of Eni share; and (ii) the incentive to be paid at the end of the three-year vesting period is determined in relation to the results achieved in terms of variation of the Adjusted Net Profit + Depletion Depreciation & Amortization (DD&A) parameter recorded in the three-year period, in relative terms, with respect to other major international companies, based on capitalization (Exxon, Shell, Chevron, British Petroleum, Total, Conoco). This incentive is defined as a percentage of the amount assigned according to the average annual placements achieved in the vesting period of 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%. Should the current office not be renewed, the payment of each incentive assigned will occur at the natural expiry of the relative vesting period, in accordance with the performance conditions defined in the Plan.

Treatments established in the event of termination of office or employment The following is envisaged for the Chief Executive Officer and General Manager, in accordance with the practices of the reference market and unchanged from the previous mandate, also considering the entitlements already accrued within the employment relationship, established before March 31, 2010, and due to which, in accordance with the Corporate Governance Code, the recommendations pursuant to criteria 6.C.1, letter f) of the same Code results not applicable:

•		upon termination of the employment relationship, in connection with the expiry or early termination of the current mandate, an indemnity is envisaged, in addition to the severance pay due upon termination of employment and in lieu of any obligations regarding prior notice, defined as a fixed component of euro 3,200,000 and a variable component based on the value of the annual variable incentive calculated with respect to the average of Eni performance in the three-year period 2011-2013; the indemnity is undue should the termination of the employment relationship meets the requirements of due cause, in case of death and of resignation from office for reasons other than an essential reduction of the powers currently attributed;
•		at the end of the mandate, it is recognized a treatment which, in relation to fixed remuneration and to the 50% of the maximum variable remuneration earned for the administrative role alone, guarantees a social security contribution and severance pay equal to that paid by Eni for the management employment relationship; and
•		in relation to the obligation assumed by the Chief Executive Officer and General Manager to not carry out any type of activities that could be in competition with that performed by Eni for a period of one year after termination of the employment relationship, in all of Italy, Europe, and North America, the payment of a fee equal to euro 2,219,000 is envisaged.

In any case, the Committee is entitled to propose to the Board, upon the conclusion of the mandate, a possible increase to the amounts due upon termination of office, in the case that, over the course of the three-year period, notable results were obtained.

Benefits
For the Chief Executive Officer and General Manager, unchanged from the previous mandate and the policy enacted in 2012, insurance related benefits, also in the case of risk of death or disability, are envisaged, and, in respect of the provisions of the relevant national collective labor agreement and the complementary Company level agreement for Eni senior managers ("Dirigenti"), enrolment in the supplementary pension plan (FOPDIRE) as well as in the supplementary health plan (FISDE) is envisaged, together with the use of a company car.

 

CHIEF OPERATING OFFICERS OF DIVISIONS
AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES

Fixed remuneration
Fixed remuneration is determined on the basis of the role and the responsibilities assigned, considering the average compensation levels seen in the market of large national and international companies for roles of a similar level of responsibility and complexity and that may be updated periodically, in the context of the annual salary review process that involves all managerial staff. The Guidelines for 2013, in consideration of the reference context and current market trends, envisage selective criteria, while in any case maintaining appropriate levels for competitiveness and motivation. In particular, the actions proposed regard: (i) interventions to update the fixed amount aimed at holders of roles that increased their area of responsibility or with positioning below the average of the reference market; and (ii) one-time extraordinary interventions connected to achieving results or projects or particular importance during the year.

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In addition, like all other senior managers, the Chief Operating Officers of Divisions and other Managers with strategic responsibilities are also entitled to receive the indemnities due for travel, both in Italy and abroad, in line with the applicable provisions in the relevant national collective labor contract for senior managers and in the complementary company level agreements.

Annual variable incentives
The annual variable incentive plan envisages compensation determined with reference to the Eni, business area, and individual performance results for 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) is differentiated based on the role held, up to a maximum equal to 60% of the fixed remuneration.

With regards to the Chief Operating Officers and other Managers with strategic responsibilities, the objectives are determined on the basis of those assigned to the Chief Executive Officer and General Managers, and are focused, for each business area, on economic/financial, operational and industrial performance, on internal efficiency, and issues of sustainability (in terms of health and safety, environmental protection, relations with stakeholders) as well as on individual objectives assigned in relation to the area of responsibility for the role held, in accordance with the Company’s Strategic Plan.

Long-term variable incentives Chief Operating Officers and other Managers with strategic responsibilities, in line with that envisaged for the Chief Executive Officer and General Manager, participate in the Long-Term Incentive Plans approved by the Board of Directors on March 15, 2012, with the following characteristics:

•		Deferred Monetary Incentive Plan (DMI), designed for the managerial resources who have delivered performance results envisaged within the annual variable incentive plan. The 2012-2014 Plan envisages three annual assignments, as of 2012 with the same performance conditions and characteristics as described above for the Plan of the Chief Executive Officer and General Manager. For Chief Operating Managers and other Managers with strategic responsibilities, the incentive to be assigned each year is determined in relation to the EBITDA results achieved by the Company in the previous year, measured on a performance scale of 70-130. The target incentive level is differentiated based on the role 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 EBITDA results achieved during the three-year period as a percentage between zero and 170% of the assigned value; and
•		Long-Term Monetary Incentive Plan (LTMI), designed for critical managerial resources. The 2012-2014 envisages three annual assignments, as of 2012, with the same performance conditions and characteristics as envisaged in the Plan of the Chief Executive Officer and General Manager. For Chief Operating Officers and other Managers with strategic responsibilities, the incentive to be assigned at target level is differentiated by role, up to a maximum of 50% of the fixed remuneration. The incentive to be paid at the end of the three-year period in question is determined as a percentage of the amount assigned on the basis of the average annual placement in the three-year period with respect to other companies of the peer group, between zero and 130% of the assigned value.

Both Plans provide for clauses aimed at promoting retention of employees, envisaging, in the case of consensual contract resolution, or transfer 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 conserves the right to the incentive in the measure decreased by the period between the award of the base incentive and the occurrence of said events, or no payment in the case of unilateral termination.

Treatments established in the event of termination of office or employment
For Chief Operating Officers and other Managers with strategic responsibilities, the employment termination treatments established in the relevant national collective labor contract are provided, together with any other additional severance indemnity agreed on an individual basis upon termination, according to the criteria established by Eni for cases of early resolutions and/or retirement; these criteria take into account the retirement age and actual age of the manager at the time of termination of employment and the remuneration received annually. Specific compensation for cases in which it is necessary to stipulate non-competition agreements may also be envisaged.

Benefits
For the Chief Operating Officers of Eni Divisions and other Managers with strategic responsibilities, unchanged from the policy enacted in 2012, and in respect of the provisions of the relevant national collective labor agreement and the complementary company level agreements for Eni senior managers, insurance related benefits, also in case of death and disability, and the enrolment in the supplementary pension plan (FOPDIRE) as well as in the supplementary health plan (FISDE) are envisaged, together with the use of a company car.

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MARKET REFERENCES AND PAY MIX

The remuneration benchmarks used for the various types of roles, are indicated as follows: (i) for the Chairman and non-executive Directors, references relative to similar roles in the largest national listed companies by capitalization; (ii) for the Chief Executive Officer and General Manager, benchmarks relative to similar roles in national and European largest listed companies by capitalization and in the main international companies in the Oil sector; and (iii) for Chief Operating Officers of Divisions and Managers with strategic responsibilities, benchmarks relative to roles with the same level of responsibility and managerial complexity in large national and international industrial companies.

The 2013 remuneration policy guidelines lead to a remuneration mix in line with the management positions held, with greater weight given to the variable component, in particular over the long term, for those position having a greater impact on Company results.

With the exception of the CEO as described above, none of the Directors of Eni has service contracts with the Company or any of its subsidiaries providing for benefits upon termination of employment.

Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the table below reports individual remuneration earned in 2012 by each Member of the Board of Directors, Statutory Auditors, and Chief Operating Officers. The overall amount earned by other Managers with strategic responsibilities is reported too.

Following the mentioned amendment, the table reports the total amount of emoluments paid during the year 2012.

(euro thousand)

Variable non-equity remuneration

Name

Notes

Office

Term of office

Office expiry (*)

Fixed remuneration

Committee membership remuneration

Bonuses and other incentives

Profit sharing

Non-monetary benefits

Other remuneration

Total 2012

Fair value of equity remuneration

Severance indemnity for end of office or termination of employment

Giuseppe Recchi	(1)		Chairman		01.01-12.31		04.2014		765	(a)					245	(b)				4					1,014
Paolo Scaroni	(2)		CEO and General Manager		01.01-12.31		04.2014		1,430	(a)					4,952	(b)				15					6,397
Carlo Cesare Gatto	(3)		Director		01.01-12.31		04.2014		115	(a)		50	(b)												165
Alessandro Lorenzi	(4)		Director		01.01-12.31		04.2014		115	(a)		59	(b)												174
Paolo Marchioni	(5)		Director		01.01-12.31		04.2014		115	(a)		50	(b)												165
Roberto Petri	(6)		Director		01.01-12.31		04.2014		115	(a)		36	(b)												151
Alessandro Profumo	(7)		Director		01.01-12.31		04.2014		115	(a)		45	(b)												160
Mario Resca	(8)		Director		01.01-12.31		04.2014		115	(a)		45	(b)												160
Francesco Taranto	(9)		Director		01.01-12.31		04.2014		115	(a)		50	(b)												165

Board of Statutory Auditors

Ugo Marinelli	(10)		Chairman		01.01-12.31		04.2014		115	(a)															115
Roberto Ferranti	(11)		Auditor		01.01-12.31		04.2014		80	(a)															80
Paolo Fumagalli	(12)		Auditor		01.01-12.31		04.2014		80	(a)															80
Renato Righetti	(13)		Auditor		01.01-12.31		04.2014		80	(a)															80
Giorgio Silva	(14)		Auditor		01.01-12.31		04.2014		80	(a)															80

Chief Operating Officers

Claudio Descalzi

(15)

E&P Division

01.01-12.31

Remuneration in the company preparing the financial statements		773	(a)					1,171	(b)				13					1,957
Remuneration from subsidiaries and associates															599	(c)		599

							Total		773						1,171					13		599			2,556
Umberto Vergine	(16)		G&P Division		01.01-12.04				372	(a)					335	(b)				10					717
Angelo Fanelli	(17)		R&M Division		01.01-12.31				559	(a)					533	(b)				14					1,106

Other Managers with strategic responsibilities (**)	(18)		Remuneration in the company preparing the financial statements		4,613						6,189					124		120			11,046				2,917
			Remuneration from subsidiaries and associates		819						408					9		25			1,261
			Total		5,432	(a)					6,597	(b)				133		145	(c)		12,307				2,917	(d)

10,571

335

13,833

189

744

25,672

2,917

Notes

(*)		The term of office expires with the Shareholders' Meeting approving the financial statements for the year ending December 31, 2013.
(**)		Managers who, during the course of the year and with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, were permanent members of the Company Management Committee and the ones who report directly to the Chief Executive Officer (thirteen managers).
(1)		Giuseppe Recchi - Chairman of the Board of Directors
		(a) The amount includes the fixed remuneration of euro 265 thousand established by the Shareholders' Meeting of May 5, 2011 and the fixed remuneration of euro 500 thousand for the powers granted by the Board of Directors on June 1, 2011.
		(b) The amount refers to the annual variable incentive paid pro-rata from May 6, 2011.
(2)		Paolo Scaroni - CEO and General Manager
		(a) The amount includes the fixed remuneration of euro 430 thousand for the role of Chief Executive Officer (which incorporates the remuneration established by the Shareholders' Meeting of May 5, 2011 as Director) and the fixed remuneration of euro 1 million as General Manager; indemnities owed for travel, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for senior managers and of the other Company's agreements are added to this amount for a total of euro 139 thousand.

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		(b) The amount includes variable annual incentive of euro 2,110 thousand, deferred monetary incentive of euro 1,022 thousand assigned in 2009 and paid in 2012, and long-term monetary incentive of euro 1,820 thousand assigned in 2009 and paid in 2012.
(3)		Carlo Cesare Gatto - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 31.5 thousand for participation in the Control and Risk Committee, and euro 18 thousand for the Compensation Committee.
(4)		Alessandro Lorenzi - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 40.5 thousand for participation in the Control and Risk Committee, and euro 18 thousand for the Oil-Gas Energy Committee.
(5)		Paolo Marchioni - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 31.5 thousand for participation in the Control and Risk Committee, and euro 18 thousand for the Oil-Gas Energy Committee.
(6)		Roberto Petri - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 18 thousand for participation in the Compensation Committee, and euro 18 thousand for the Oil-Gas Energy Committee.
(7)		Alessandro Profumo - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 18 thousand for participation in the Compensation Committee, and euro 27 thousand for the Oil-Gas Energy Committee.
(8)		Mario Resca - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 27 thousand for participation in the Compensation Committee, and euro 18 thousand for the Oil-Gas Energy Committee.
(9)		Francesco Taranto - Director
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
		(b) The amount includes euro 31.5 thousand for participation in the Control and Risk Committee, and euro 18 thousand for the Oil-Gas Energy Committee.
(10)		Ugo Marinelli - Chairman of the Board of Statutory Auditors
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
(11)		Roberto Ferranti - Auditor
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011, entirely paid to the Ministry for Economy and Finance.
(12)		Paolo Fumagalli - Auditor
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
(13)		Renato Righetti - Auditor
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
(14)		Giorgio Silva - Auditor
		(a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011.
(15)		Claudio Descalzi - Chief Operating Officer E&P Division
		(a) To the amount of euro 773 thousand as Gross Annual Salary 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 153 thousand.
		(b) The amount includes the payment of euro 442 thousand relating the deferred monetary incentive assigned in 2009.
		(c) Amount relative to remuneration for the position as Chairman of Eni UK.
(16)		Umberto Vergine - Chief Operating Officer G&P Division
		(a) To the amount of euro 372 thousand as Gross Annual Salary up to December 4, 2012, 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 9,000.
		(b) The amount includes the payment of euro 144 thousand relating the deferred monetary incentive granted in 2009.
(17)		Angelo Fanelli - Chief Operating Officer R&M Division
		(a) To the amount of euro 559 thousand as Gross Annual Salary 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 3.000.
		(b) The amount includes the payment of euro 164 thousand relating the deferred monetary incentive assigned in 2009.
(18)		Other Managers with strategic responsibilities
		(a) To the amount of euro 5,432 thousand as Gross Annual Salary, as 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 as well as other indemnities related to the employment contract, for a total amount of euro 622 thousand.
		(b) The amount includes euro 2,866 thousand relating to deferred monetary incentive assigned in 2009 as well as the pro-rata amounts of the Long Term Incentive Plans (DMI and LTMI) paid upon termination of the employment relationship, in relation to the vesting period expired as defined in the respective Plan Regulations.
		(c) Amounts related to the roles held by Managers with strategic responsibilities in the Watch Structure established pursuant to the Company's Model 231, to the role of Manager responsible for the preparation of the company's financial statements and to the compensation received for positions held in subsidiaries or associated companies of Eni.
		(d) The amount includes severance amounts and early resolution indemnities paid in relation to the termination of the employment relationship.

In particular:

•		the column "Fixed remuneration" reports, following the criteria of competence, fixed remuneration and fixed salary from employment due for the year, gross of social security and tax expenses to be paid by the employee; it excludes attendance fees, as they are not envisaged. Details on compensation are provided in the notes, as well as separate indication of any indemnities or payments referred to the employment relationship;
•		the column "Committee membership remuneration" reports, following the criteria of competence, 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 - Bonuses and other incentives" reports the incentives paid during the year due to rights vested following the assessment and approval of the relative performance results by the relevant company bodies, in accordance with that specified, in greater detail, in the Table of page 151 on monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities;
•		the column "Profit sharing", does not include any figures, as no form of profit-sharing is envisaged;
•		the column "Non-monetary benefits" reports, in accordance with competence and taxability criteria, the value of fringe benefits awarded;
•		the column "Other remuneration" reports, in accordance with the criteria of competence, any other remuneration deriving from other services provided;
•		the column "Total" reports the sum of the amounts of all the previous items;
•		the column "Fair value of equity remuneration" reports the fair value of competence of the year related to the existing stock option plans, estimated in accordance with international accounting standards which assign the relevant cost in the vesting period; and
•		the column "Severance indemnities for end of office or termination of employment" reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of financial year considered or in relation to the end of the office and/or employment.

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2012 performance variable incentives of the CEO and other top managers

Annual variable incentives
The incentive for the 2012 annual plan was paid, with regards to the top management positions, in the face of evaluation of the Company performance in relation to verification of results regarding the objectives defined for 2011 in accordance with the Strategic Plan and the annual budget, in terms of: (i) implementation of strategic and financial guidelines, taking into account the evaluation expressed by the Compensation Committee; (ii) operational performance of Eni Divisions; (iii) EBIT adjusted; and (iv) reduction of costs. Eni results in 2011, evaluated using a constant scenario approved by the Board at the meeting of March 15, 2012 and following a proposal by the Compensation Committee, led to a performance score of 125 points in the measurement scale used which envisaged a target and maximum performance level of 100 and 130 points, respectively. With regards to the Chief Operating Officers of the Divisions, the incentive was paid on the basis of the economic and operational performance obtained in their respective business sectors, including evaluation of the achievement of specific sustainability objectives (in terms of health and safety, environmental protection and relation with stakeholders). With regards to other Managers with strategic responsibilities, the variable incentive paid in 2012 was connected to Company results and a series of individual objectives assigned in relation to the area of responsibility for the role held, in line with that envisaged in the Eni 2011 performance Plan.

For the purposes of the variable remuneration to be paid in 2012, the performance score determined:

•		for the Chairman, the payment of a bonus equal to 75% of the fixed remuneration, taking into account the target (60%) and maximum (78%) incentive levels assigned (bonus paid pro-rata with respect to the period for which the office was held in 2011);
•		for the Chief Executive Officer, the payment of a bonus equal to 147.5% of the fixed remuneration taking into account the target (110%) and maximum (155%) incentive levels assigned; and
•		for the Chief Operating Officers of Divisions and Managers with strategic responsibilities, the payment of bonuses determined in relation to the specific performance achieved, in accordance with incentive levels differentiated on the basis of the role held.

Deferred Monetary Incentive Plan
At its meeting of March 15, 2012, the Board of Directors, following the review and proposal of the Compensation Committee, determined achievement of a 2011 EBITDA result (evaluated using a constant scenario) at the target level.

Therefore, for the Chief Executive Officer and Chief Operating Officer General Manager, the Board determined the assignment of the 2012 base incentive in the amount of euro 786,500 (55% of the fixed remuneration). For Chief Operating Officers of Eni Divisions and other Managers with strategic responsibilities, the incentive amounts defined as "target" were assigned, differentiated by the level of the role up to a maximum equal to 40% of the fixed remuneration.

In addition, in 2012 the deferred monetary incentive assigned in 2009 to the Chief Executive Officer and Chief Operating Officer, to the Chief Operating Officers of the Divisions, and to other Managers with strategic responsibilities reached maturity. At its meeting of March 15, 2012, the Board of Directors, on the basis of Eni’s EBITDA results during the 2009-2011 period, approved, based on a proposal from the Compensation Committee, the multiplier to be applied to the base incentive assigned for the purposes of calculating the amount to be paid, in the amount of 130%.

Specifically, an incentive equal to euro 1,022,450 was paid to the Chief Executive Officer (equal to 130% of the base incentive of euro 786,500 assigned in 2009).

Long-Term Monetary Incentive Plan
At its meeting of September 20, 2012, for the Chief Executive Officer and General Manager, the Board of Directors, in accordance with the verification and proposal of the Compensation Committee, approved the assignment of the 2012 base incentive from the Long-Term Monetary Incentive Plan envisaged in the Board resolution of June 1, 2011, replacing the previous stock option plan, which was not implemented after 2009. The incentive assigned was defined at euro 2,363,013 in accordance with the criteria and the methods of valorization approved by the Board itself and with the assistance of specialized external providers.

For Chief Operating Officers of Eni Divisions and other Managers with strategic responsibilities, the amounts were determined in accordance with the target incentive level, differentiated by the level of the role, up to a maximum equal to 50% of the fixed remuneration.

In addition, in 2012 the long-term monetary incentive assigned in 2009 to the Chief Executive Officer and the General Manager reached maturity. At its meeting on March 15, 2012, the Board of Directors, on the basis of Eni’s results relating to the variation of the Adjusted Net Profit + DD&A recorded in the period 2009-2011 and the corresponding annual placement with the reference peer group, approved, based on a proposal by the Compensation Committee, the multiplier to be applied to the amount awarded for the purposes of calculating the amount to be paid, in the amount of 67%. As a result, an incentive of euro 1,819,982 was paid to the Chief Executive Officer (equal to 67% of the base incentive of euro 2,716,319 awarded in 2009).

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The table below indicates, by name, the variable monetary incentives, both short and long term, envisaged for the Directors, the Chief Operating Officers of the Divisions and, at an aggregate level, for other Managers with strategic responsibilities (including all those individuals who, during the course of the period, filled said roles, even if for only a fraction of the year).

Monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities

(euro thousand)						Bonuses of the year		Bonuses of previous years

Name

Office

Plan

payable/paid

deferred

deferral period

no longer payable

payable/paid (1)

still deferred

Other bonuses

Giuseppe Recchi		Chairman		Annual Monetary Incentive Plan 2012 BoD March 15, 2012		245
Total						245
Paolo Scaroni		CEO and General Manager		Annual Monetary Incentive Plan 2012 BoD March 15, 2012		2,110
				Deferred Monetary Incentive Plan 2012 BoD March 15, 2012				787		three-year
				Long-Term Monetary Incentive Plan 2012 BoD September 20, 2012				2,363		three-year
				Deferred Monetary Incentive Plan 2011 BoD March 10, 2011												787
				Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011												2,447
				Deferred Monetary Incentive Plan 2010 BoD July 28, 2010												787
				Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010												2,501
				Deferred Monetary Incentive Plan 2009 Award: BoD July 30, 2009 Payment: BoD March 15, 2012										1,022
				Long-Term Monetary Incentive Plan 2009 Award: BoD November 18, 2009 Payment: BoD March 15, 2012								896		1,820
Total						2,110		3,150				896		2,842		6,522
Claudio Descalzi		Chief Operating Officer E&P Division		Annual Monetary Incentive Plan 2012		579
				Deferred Monetary Incentive Plan 2012 BoD March 15, 2012				387		three-year
				Long-Term Monetary Incentive Plan 2012 BoD September 20, 2012				356		three-year
				Deferred Monetary Incentive Plan 2011 BoD March 10, 2011												309
				Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011												363
				Deferred Monetary Incentive Plan 2010 BoD July 28, 2010												275
				Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010												347
				Deferred Monetary Incentive Plan 2009 Award: BoD July 30, 2009 Payment: BoD March 15, 2012										442
Total						579		743						442		1,294		150
Umberto Vergine		Chief Operating Officer G&P Division (2)		Annual Monetary Incentive Plan 2012		191
				Deferred Monetary Incentive Plan 2012 BoD March 15, 2012				180		three-year
				Long-Term Monetary Incentive Plan 2012 BoD September 20, 2012				207		three-year
				Deferred Monetary Incentive Plan 2011 BoD March 10, 2011												100
				Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011												124
				Deferred Monetary Incentive Plan 2010 BoD July 28, 2010												95
				Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010												128
				Deferred Monetary Incentive Plan 2009 Award: BoD July 30, 2009 Payment: BoD March 15, 2012										144
Total						191		387						144		447

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(1)		Payment relative to deferred monetary incentive assigned in 2009.
(2)		Chief Operating Officer G&P Division until December 4, 2012.

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Monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities continued

(euro thousand)						Bonuses of the year		Bonuses of previous years

Name

Office

Plan

payable/paid

deferred

deferral period

no longer payable

payable/paid (1)

still deferred

Other bonuses

Angelo Fanelli		Chief Operating Officer R&M Division		Annual Monetary Incentive Plan 2012		369
				Deferred Monetary Incentive Plan 2012 BoD March 15, 2012				224		three-year
				Long-Term Monetary Incentive Plan 2012 BoD September 20, 2012				257		three-year
				Deferred Monetary Incentive Plan 2011 BoD March 10, 2011														224
				Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011														263
				Deferred Monetary Incentive Plan 2010 BoD July 28, 2010														194
				Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010														244
				Deferred Monetary Incentive Plan 2009 Award: BoD July 30, 2009 Payment: BoD March 15, 2012											164

Total

369

481

164

925

Other Managers with strategic responsibilities (2)

Annual Monetary Incentive Plan 2012

3,281

				Deferred Monetary Incentive Plan 2012 BoD March 15, 2012				1,326		three-year		210	(3)		90	(4)
				Long-Term Monetary Incentive Plan 2012 BoD September 20, 2012				1,590		three-year		242	(3)		104	(4)
				Deferred Monetary Incentive Plan 2011 BoD March 10, 2011								150	(3)		150	(4)		1,291
				Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011								229	(3)		123	(4)		1,567
				Deferred Monetary Incentive Plan 2010 BoD July 28, 2010								80	(3)		187	(4)		1,018
				Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010								203	(3)		135	(4)		1,340
				Deferred Monetary Incentive Plan 2009 Award: BoD July 30, 2009 Payment: BoD March 15, 2012											2,077

Total

3,281

2,916

1,114

2,866

5,216

450

6,775

7,677

2,010

6,458

14,404

600

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(1)		Payment relative to deferred monetary incentive assigned in 2009.
(2)		Managers who, during the course of the year and with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, were permanent members of the Company Management Committee and the ones who report directly to the Chief Executive Officer (thirteen managers).
(3)		Pro-rata amount no longer payable, following the termination of the employment relationship, in relation to the vesting period expired, as foreseen in the Plan Regulations.
(4)		Pro-rata amount paid, following the termination of the employment relationship, in relation to the vesting period expired, as foreseen in the Plan Regulations.

In particular:

•		the column "Bonuses of the year - payable/paid" reports the short-term variable incentive paid during the year on the basis of the verification of the performance carried out by the relevant company bodies relative to the objectives defined for the previous year;
•		the column "Bonuses of the year - deferred" reports the amount of the base incentive assigned during the year in implementation of the long-term monetary incentive plans;
•		the column "Bonuses of the year - Deferral period" reports the duration of the period of the vesting for the long-term incentives assigned during the year;
•		the column "Bonuses of previous years - no longer payable" indicates the long-term incentives no longer payable in relation to the verified performance conditions for the vesting period, or the incentives that expired due to events pertaining to the employment relationships as foreseen by the Regulations of the Plans;
•		the column "Bonuses of previous years - payable/paid" indicates the long-term incentives paid during the year, matured on the basis of verification of the performance conditions for the vesting period, or the incentive options disbursed due to events pertaining to the employment relationships as foreseen by the Regulations of the Plans;
•		the column "Bonuses of previous years - still deferred" reports incentives assigned in previous years, in implementation of long-term Plans, which have not yet vested; and
•		the column "Other bonuses" includes incentives paid on a one-time extraordinary basis, connected to the achievement of particularly important results of projects during the year.

The Total of the columns "Bonuses of the year - payable/paid", "Bonuses of previous years - payable/paid" and "Other bonuses" is the same as that indicated in the column "Bonuses and other incentives" in the Compensation table.

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Severance indemnity for end of office or termination of employment
In the course of 2012, severance indemnity for the end of office were not approved and/or paid in favor of the Directors and/or Chief Operating Officers of Eni's Divisions. With regards to other Managers with strategic responsibilities, amounts were paid as defined in accordance with Company policy for early resolutions in addition to contractual and legal obligations.

Accrued compensation
Total compensation accrued in the year 2012 pertaining to all the Board members amounted to euro 13.2 million; it amounted to euro 467,000 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, 2012, 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 amounted to euro 33 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2012. The break-down is as follow:

	2012
	(euro million)

Fees and salaries		21
Post employment benefits		1
Other long-term benefits		11
Indemnity upon termination of the office
		33

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, 2012, the total amount accrued to the reserve for employee termination indemnities with respect to members of the Board of Directors who were also employees of Eni, the three Divisional Chief Operating Officers and Eni’s senior managers was euro 1,536 thousand.

Name	(euro thousand)

Paolo Scaroni		CEO and General Manager of Eni		182
Claudio Descalzi		Chief Operating Officer of the E&P Division		333
Angelo Fanelli		Chief Operating Officer of the R&M Division		240
Senior managers (a)				781
				1,536

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(a)

No. 12 managers.

 

Stock options

At December 31, 2012, a total of 8,259,520 options were outstanding for the purchase of an equal amount of Eni ordinary shares without nominal value. 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.

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The following table shows the evolution of stock option activity in 2011 and 2012.

	2011		2012

	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		15,737,120			23.005		16.398		11,873,205			23.101		15.941
Options exercised in the period		(208,900	)		14.333		16.623		(93,000	)		16.576		16.873
Options cancelled in the period		(3,655,015	)		23.187		17.474		(3,520,685	)		22.233		16.637
Options outstanding as of December 31		11,873,205			23.101		15.941		8,259,520			23.545		18.457
of which exercisable as of December 31		11,863,335			23.101		15.941		8,243,205			23.544		18.457

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 2012 period, filled said roles, even if for only 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 these are incentive plans which are now only residual.

Stock options granted to Directors, Chief Operating Officers, and other Managers with strategic responsibilities

Name			Paolo Scaroni		Claudio Descalzi		Umberto Vergine		Angelo Fanelli		Other Managers with strategic responsibilities (2)
Office			CEO and General Manager		Chief Operating Officer of E&P Division		Chief Operating Officer of G&P Division (1)		Chief Operating Officer of R&M Division
Plan			Eni Stock Option Plans		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			1,608,705		144,355		53,290		71,595		858,335
Average exercise price	(euro)		23.373		23.679		23.741		23.688		23.595
Average maturity	(months)		19		20		22		21		21
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			320,070		35,720		9,870		16,685		200,850
Options held at the end of the year
Number of options			1,288,635		108,635		43,420		54,910		657,485
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 control functions are allocated to the Board of Statutory Auditors. The Company's accounts are also independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. On April 26, 2012,

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Eni completed the adoption of the recommendations of the new Corporate Governance Code for listed companies (on the Italian Stock Exchange) of December 2011 (hereinafter "Corporate Governance Code"), which replaced the previous 2006 edition of the Corporate Governance Code.

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

Board of Directors’ duties and responsibilities
The Board of Directors has the widest powers for the ordinary and extraordinary administration of the Company in relation to its purpose. In a resolution dated May 6, 2011, 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 Paolo Scaroni as CEO and General Manager, entrusting him with the widest powers for the ordinary and extraordinary administration of the Company. In the same resolution, the Board delegated to the Chairman, Giuseppe Recchi, powers to identify and promote integrated projects and international agreements of strategic importance, in accordance with Article 24 of the By-laws.

In particular, exercising the powers as set out in the Corporate Governance Code – and in consultation with the relevant committees, the CEO, and/or the Chairman where applicable – the Board, among other tasks: defines the system of corporate governance of the Company and the Group; establishes the internal committees of the Board; assigns and revokes powers granted to the CEO and to the Chairman and defines the limits and procedures for exercising such powers; establishes the fundamental guidelines for the organizational, administrative and accounting structure of the Company and the internal control system and risk management; examines and approves the Company and Group’s strategic, industrial and financial plans and agreements, annual budgets and the semi-annual financial report and the interim reports, as well as the Sustainability Report; receives information from Directors with proxies relative to activities implemented during the exercising of their powers and receives periodic half-year information from the internal committees of the Board; assesses the general management trends of the Company and of the Group paying particular attention to conflicts of interest; examines and approves the operations of the Company and its subsidiaries which are significant from a strategic, economic and financial perspective, particularly with regards to situations in which one or more Directors retain personal or third party interests as well as related parties transactions¹⁴; appoints and dismisses the Chief Operating Officers, the Officer in charge of preparing financial reports and a Senior Executive Vice President of Internal Audit; defines a remuneration plan for top management of the Company and the Group; resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the primary subsidiaries; formulates the proposals to present to the Shareholders’ Meeting; and examines and decides on other issues which Directors with delegated powers believe it is appropriate to present to the Board due to their particular relevance or sensitivity. In accordance with Article 23.2 of the By-laws, the Board also decides on: mergers and proportional demergers of companies in which Eni holds an equity interest of more than 90%; on the establishment and closing of branches; and on 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
During its meeting of May 6, 2011 and, after an investigation by the Nomination Committee, at its meeting of February 14, 2012, the Board of Directors determined that the non-executive Directors Gatto, Lorenzi, Marchioni, Petri, Profumo, Resca and Taranto were independent.

These determinations were made by the Board on the basis of statements made by the Directors and other information available to the Company, and taking into account the criteria of independence established in Italian regulations and the Corporate Governance Code in force at that time. Director Resca was confirmed as being independent under the terms of the Corporate Governance Code in force at that time as well, even though he has held the position for over nine years in the last twelve years¹⁵, because of his recognized independence of judgment. With reference to the marital relationship of the Director Profumo with an employee of the Company, the Board believes that this relationship does not compromise the independence requirements requested by Corporate Governance Code in force at that time, in view of his ethical and professional integrity of this Director and his international reputation. Director Gatto was confirmed as being independent even though he was appointed Chairman of the Board of the Statutory Auditors of RAI SpA, company under common control with Eni by the Ministry of the Economy and Finance, because of the independence required to the Board of Statutory Auditors and also for the particular discipline applicable to RAI which limits the power of control of the Ministry of the Economy and Finance.

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After the evaluation of the Board at the meeting of February 14, 2012, in compliance with the independence requirements contained in the Corporate Governance Code (Article 3C4) which establishes that the Board of Directors shall assess the independence of a Director every time a material circumstance occurs, the Nomination Committee investigated, in its meetings of September 20, 2012 and October 18, 2012, the independence of Director Profumo, who was appointed Chairman of the Board of Directors of Monte dei Paschi di Siena on April 27, 2012, taking into account the business relations between Eni and that Bank. The Nomination Committee acquired documentation concerning the financial relationships between Eni and Monte dei Paschi di Siena and the other information available to the Company, and confirmed¹⁶ the independence of Director Profumo, determining that these business relations were not sufficient to undermine the independence requirements set out in the Corporate Governance Code. The Board of Directors, on the basis of the investigation of the Nomination Committee, confirmed, on October 29, 2012, that Director Profumo was independent.

The Board of Statutory Auditors has always monitored the correct application of the criteria and procedures adopted by the Board for assessing the independence of its members. Those independence criteria may not be equivalent to the independence criteria set forth by 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 Committee¹⁷; (b) the Compensation Committee; (c) the Nomination Committee; and (d) the Oil-Gas Energy Committee. The Control and Risk Committee, the Compensation Committee and the Nomination Committee are recommended by the Corporate Governance Code. The composition, duties and operational procedures of these committees are governed by their rules, which are approved by the Board, in compliance with the criteria outlined in the Corporate Governance Code.

The committees provided for by the Corporate Governance Code (Control and Risk Committee, Nomination Committee and Compensation Committee) are composed of no fewer than three members and, in any case, less than a majority of members of the Board. The Control and Risk Committee, the Compensation Committee and the Oil-Gas Energy Committee are made up of non-executive, independent Directors. The Nomination Committee is made up of non-executive Directors, a majority of whom are independent in compliance with the Corporate Governance Code. 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, may participate in Control and Risk Committee meetings. The Chairman of the Board, the CEO, the other standing Statutory Auditors and the Magistrate of the Italian Court of Auditors may also attend the Control and Risk Committee meetings. Furthermore, the Committee may, through its Chairman, invite other persons, including other member of the Board of Directors or the Company structure, to attend the meetings in relation to individual items on the agenda.

The Chairman of the Board of Statutory Auditors, or a standing Statutory Auditor designated by him, are invited to participate in Compensation Committee meetings. Other Statutory Auditors may also attend meetings in which the Committee is addressing issues about which the Board of Directors is required to obtain an opinion from the Board of Statutory Auditors. Company managers or other persons who, at the invitation of the Chairman of the Committee, are called to provide information and or opinions based on their expertise on specific items on the agenda may also attend the meetings. No Director may take part in meetings of the Committee during which Board proposals regarding his compensation are being discussed.

The Chairman of the Board of Directors and the CEO are invited to attend Oil-Gas Energy Committee meetings and other Directors may also participate. The Chairman of the Board of Statutory Auditors – or another standing Statutory Auditor designated by the former – may also participate as well as other individuals, who need not be affiliated with Eni, at the invitation of the Committee with regard to the specific items in the agenda.

The CEO attends the Nomination Committee meetings. The Chairman of the Board of Statutory Auditors, or a Statutory Auditor designated by him, may participate in Committee meetings for matters within the competence of the Board of Statutory Auditors as well as other persons who, at the invitation of the Committee itself, are called to provide information and or opinions based on their expertise on specific items in the agenda.

Minutes of all committee meetings are drafted by the respective secretaries. The current members of the Control and Risk Committee, Compensation Committee, Oil-Gas Energy Committee were appointed by the Board of Directors on May 6, 2011. The current members of the Nomination Committee were appointed by the Board of Directors on July 28, 2011.

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Compensation Committee
Members: Mario Resca (Chairman), Carlo Cesare Gatto, Roberto Petri and Alessandro Profumo.

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 compensation of the managers with strategic responsibilities; (ii) annual and long-term incentive plans, including equity-based plans; (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 2012, the Compensation Committee met four times, with an attendance rate of 100% of its members and the main topics discussed in the first part of the year were: (i) periodical evaluation of the remuneration policy carried out in 2011, even for the definition of the proposal guidelines of remuneration policy 2012; (ii) evaluation of the attainment of Eni’s 2011 management objectives and definition of 2012 performance objectives for the purposes of variable Incentive Plans; (iii) establishment of the proposal regarding the 2012 Deferred Monetary Incentive Plan for the CEO and General Manager and for other executives; and (iv) examination of the remuneration report 2012. During the second part of the year, the Committee examined the results of the vote of the Shareholder’s Meeting on the remuneration policy for 2012 and the planned guidelines for the preparation of the 2013 Remuneration Report. The Committee also formulated the proposal concerning the fulfillment of the Long-Term Monetary Incentive Plan for the CEO and General Manager and for critical management personnel.

The composition and appointment, as well as duties and operational rules, of the Committee are governed by rules approved by the Board of Directors on June 1, 2011, and amended on December 15, 2011 and on October 29, 2012.

Control and Risk Committee¹⁸
Members: Alessandro Lorenzi (Chairman), Carlo Cesare Gatto, Paolo Marchioni and Francesco Taranto.

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 periodic financial reports. It is entirely made up of non-executive and independent Directors¹⁹ who possess the necessary expertise consistent with the duties they are required to perform²⁰.

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 determines 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 once a year, 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

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the system itself; e) on the evaluation of the findings reported by the Audit Firm in the recommendations letter it may issue and in the latter’s report on the main issues arising during the audit; g) 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 h) 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 the 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: (i) 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; (ii) examines and evaluates the appropriateness of the powers and resources assigned to the officer in charge of preparing financial reports and, also 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 (iii) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and oversees its activities with respect to the Board of Directors’ duties in this area, 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. Among its other duties, the Committee examines: a) the periodic report prepared by the Senior Executive Vice President of the Internal Audit Department containing 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 the assessment of the appropriateness of the internal control and risk management system; b) the reports prepared promptly by the Senior Executive Vice President of the Internal Audit Department on events of particular importance; and c) 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 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.

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: (i) 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; (ii) periodic reports issued by Eni’s Watch Structure, including in its capacity as Guarantor of the Code of Ethics; (iii) information on the internal control and risk management system, including that provided in the course of periodic meetings with the competent Company structures; and (iv) enquiries and reviews concerning the internal control and risk management system carried out by third parties.

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 June 1, 2011 and amended on July 31, 2012.

 

Nomination Committee
Members: Giuseppe Recchi (Chairman), Alessandro Lorenzi, Alessandro Profumo and Mario Resca.

On July 28, 2011, the Board of Directors of Eni established the Nomination Committee, chaired by the Chairman of the Board of Directors. The Committee is made up of three to four 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 the criteria for the appointment of persons indicated in following letter b) 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 with the shareholders’ structure, the Committee proposes to the Board of Directors the succession plan concerning 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

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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 not later than the deadline for the approval of the Annual Financial Statements and of the semi-annual Financial Report, on the activity carried out, as well as on the adequacy of the appointment system, at the Board meeting indicated by the Chairman of the Board of Directors.

The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors on September 29, 2011 and amended on October 29, 2012.

 

Board of Statutory Auditors
The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of May 5, 2011 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, 2013.

Name		Position		Year first appointed to Board of Statutory Auditors
Ugo Marinelli		Chairman		2008
Roberto Ferranti		Auditor		2008
Paolo Fumagalli		Auditor		2011
Renato Righetti		Auditor		2011
Giorgio Silva		Auditor		2005
Francesco Bilotti		Alternate Auditor		2005
Maurizio Lauri		Alternate Auditor		2011

Roberto Ferranti, Paolo Fumagalli, Renato Righetti and Francesco Bilotti were candidates in the list presented by the Ministry of the Economy and Finance; Ugo Marinelli, Giorgio Silva and Maurizio Lauri were candidates in the list 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 elected by the non-controlling shareholders.

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 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 shall 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, preparation and auditing of financial statements and internal control processes.

Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters within the scope of the Board’s authority, the adequacy of the internal control system and the administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the corporate governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.

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In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, in its role as the "internal control and financial auditing committee" the Board of Statutory Auditors oversees the following: a) the financial reporting process; b) the efficacy of internal control, internal audit (where applicable) and risk management systems; c) the auditing of the annual financial statements and consolidated financial statements; and d) the independence of the external auditor or the Audit Firm, in particular with regard to the provision of non-audit services to the entity subject to financial auditing.

The responsibilities assigned under the Decree 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.

Furthermore, 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 Article 153 of the Consolidated Law on Finance, the Board of Statutory Auditors presents the results of its supervisory activity in a report. 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 (SEC) applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as from June 1, 2005, performs, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and 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 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 account 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 execution of its functions, is supported by Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department.

 

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

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January 28, 2004 – approved an organizational, managerial and control model pursuant to Legislative Decree No. 231 of 2001 ("Model 231") and created the associated Watch Structure. Moreover, as a result of changes in the Italian legislation governing the matter and of the Company organizational structures, on March 14, 2008, the Board of Director 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: shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. 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 established by Model 231 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 from among academics, professionals of proven authority and expertise in economic and business management issues. The internal members are the Senior Executive Vice President Legal Affairs, Executive Vice President Human Resources and Organization and Senior Executive Vice President Internal Audit of the Company. On May 19, 2011, 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 ("Corte dei conti") in order to preserve the integrity of the public finances. This work is performed by the magistrate of the Court of Auditors, Raffaele Squitieri (whose alternate is Amedeo Federici), on the basis of the resolution approved on October 28, 2009 by the Presidential Council of the Court of Auditors. 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.

 

Employees

As of December 31, 2012, Eni had a total of 77,838 employees, an increase of 5,264 employees, or up 7.3% from December 31, 2011, which reflects an increase of 5,518 employees working outside Italy and a decrease of 254 employees hired in Italy.

During the year, 1,599 persons left their job at Eni in Italy (2.1% of all Group employees), of these 937 had an open-end contract and 662 a fixed-term contract. Declines were registered in all business Divisions due to efficiency actions.

The process of improvement in the quality mix of employees continued in 2012 with the hiring of 1,601 persons, of which 605 had fixed-term contracts. A total of 996 persons were hired with open-ended and apprenticeship contracts, most of them with university qualifications (697 persons).

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Employees hired and working outside Italy were 51,034 (65.6% of all Group employees), an increase of 5,518 persons, mainly in the Engineering & Construction segment due to new contracts, in Exploration & Production segment due to the expansion of some operating units and in sourcing of contract people, and in Belgium in the Gas & Power segment (Nuon Belgium).

		2010		2011		2012

(units)

Exploration & Production		10,276		10,425		11,304
Gas & Power (1)		5,072		4,795		4,752
Refining & Marketing		8,022		7,591		7,125
Chemicals		5,972		5,804		5,668
Engineering & Construction		38,826		38,561		43,387
Other activities		939		880		871
Corporate and financial companies		4,661		4,518		4,731
		73,768		72,574		77,838

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The table below sets forth Eni’s employees as of December 31, 2010, 2011 and 2012 in Italy and outside Italy:

		2010		2011		2012

(units)

Exploration & Production	Italy		3,906		3,797		3,933
	Outside Italy		6,370		6,628		7,371
			10,276		10,425		11,304
Gas & Power (1)	Italy		2,479		2,310		2,126
	Outside Italy		2,593		2,485		2,626
			5,072		4,795		4,752
Refining & Marketing	Italy		6,162		5,790		5,505
	Outside Italy		1,860		1,801		1,620
			8,022		7,591		7,125
Chemicals	Italy		4,903		4,750		4,606
	Outside Italy		1,069		1,054		1,062
			5,972		5,804		5,668
Engineering & Construction	Italy		4,915		5,197		5,186
	Outside Italy		33,911		33,364		38,201
			38,826		38,561		43,387
Other activities	Italy		939		880		871
	Outside Italy		-		-		-
			939		880		871
Corporate and financial companies	Italy		4,497		4,334		4,577
	Outside Italy		164		184		154
			4,661		4,518		4,731
Total	Italy		27,801		27,058		26,804
	Outside Italy		45,967		45,516		51,034
			73,768		72,574		77,838
of which senior managers			1,454		1,468		1,474

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Share ownership

As of February 28, 2013, the cumulative number of shares owned by Eni’s directors, statutory auditors and senior managers, including the three Chief Operating Officers, was 305,696 less than 0.1% of Eni’s share capital outstanding as of the same data. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The break-down of share ownership for each of those persons is provided below.

Name	Position	Number of shares owned		Options granted

Board of Directors
Giuseppe Recchi		Chairman		42,000
Paolo Scaroni		CEO and COO of Eni		91,250		1,288,635
Carlo Cesare Gatto		Director		6,800
Paolo Marchioni		Director		1,500
Alessandro Profumo		Director				7,195
Mario Resca		Director		3,900
Francesco Taranto		Director		500
Chief Executive Officers
Claudio Descalzi		Chief Operating Officer of the E&P Division		39,455		108,635
Angelo Fanelli		Chief Operating Officer of the R&M Division		30,800		4,910
Umberto Vergine (*)		Chief Operating Officer of the G&P Division		13,764		43,420
Board of Statutory Auditors				7,454
Senior managers				68,273		657,485

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Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

The Ministry of Economy and Finance controls Eni as a result of shares held directly and indirectly through Cassa Depositi e Prestiti SpA ("CDP"), in which the Ministry of Economy and Finance holds a 70% stake. As of March 18, 2013, the total amount of Eni SpA’s voting securities owned by these shareholders was:

Title of class		Number of shares owned		Percent of class

Ministry of Economy and Finance		157,552,137		4.34
Cassa Depositi e Prestiti SpA		936,179,478		25.76

The following table shows the percentage of Eni’s share capital owned directly or indirectly by subjects that as of March 18, 2013 have notified that their holding exceeds the threshold of 2% pursuant to Article 120 of Italian Consolidated Law on Financial Intermediation and to Consob Resolution No. 11971/99 (Consob Regulations on Issuers). Holdings notified before July 16, 2012 have been recalculated (see figures in italics) based on No. 3,634,185,330 shares representing Eni’s current share capital following the cancellation of treasury shares approved by the Eni Shareholders’ Meeting of July 16, 2012.

Title of class		Number of shares owned		Percent of class

BNP Paribas Group

91,529,423

2.52

(a)

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The Ministry of Economy and Finance, in agreement with the Ministry of Economic Development, pursuant to Article 6.2 of the By-laws and to the special rules set out in Law No. 474/1994, retains certain special powers over Eni. See "Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)". As of March 18, 2013 there were 35,890,018 ADRs, each representing two Eni ordinary shares outstanding corresponding to approximately 2.0% of Eni’s share capital. See "Item 9 – The offer and the listing".

 

Related party transactions

In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with non-consolidated subsidiaries and affiliates as well as other companies owned or controlled by the Italian Government. All such transactions are conducted on an arm’s length basis and in the interest of Eni companies.

Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in "Item 18 – note 42 of the Notes to the Consolidated Financial Statements".

On October 15, 2012, Eni divested a stake of 30% less one share of the voting capital in its Snam subsidiary to Cassa Depositi e Prestiti SpA (CDP), an entity controlled by the Italian Ministry of Economy and Finance. At the date of the transaction, the counterparty CDP held a stake in Eni that gave CDP a significant influence over the Company and was under common control of the Italian Ministry for Economy and Finance’s. Consequently, the transaction qualified as material transaction with a related party. Furthermore, because the value of the transaction was above certain established thresholds applicable to transactions with related parties pursuant to Italian listing standards provided by the Consob Regulation (No. 17221 of March 12, 2010 as updated by Regulation No. 17389 of June 23, 2012), the transaction was reviewed in accordance to the internal procedures that the Company has adopted to ensure fairness, transparency and correctness for similar transactions in line with Consob guidelines. That procedure is retrievable at the Company website eni.com in the section "Corporate Governance". For a full description of the transaction with CDP see "Item 4 – Significant transactions".

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Item 8. FINANCIAL INFORMATION

Consolidated Statements and other financial information

See "Item 18 – Financial Statements".

 

Legal proceedings

Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will not have an adverse effect on Eni’s Consolidated Financial Statements.

For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see "Item 18 – note 34 of the Notes to the Consolidated Financial Statements".

 

Dividends

Eni’s dividend policy in future periods, and the sustainability of the current amount of dividends over the next four-year period, will depend upon a number of factors including future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the "Risk factors" set out in Item 3. The parent company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. However, given the Company’s changed business profile which entails both more growth options and more volatile results, as well as and improved balance sheet, management plans to implement a new dividend police. The new dividend policy contemplates a progressive, growing dividend at a rate which is expected to be set taking into account Eni’s underlying earnings and cash flow growth as well as capital expenditure requirements and the targeted financial structure. Management will also evaluate the achievement of the targeted production levels in the Exploration & Production segment, the status of renegotiations at gas long-term supply contracts in the Gas & Power segment and the delivery on efficiency gains in the downstream businesses. This dividend policy is based on management’s planning assumptions for oil prices at 90 $/BBL in the 2013-2016 period and a gradual European demand recovery.

Management intends to propose to the Annual Shareholders’ Meeting scheduled on May 10, 2013, the distribution of a dividend of euro 1.08 per share for fiscal year 2012, of which euro 0.54 was already paid as interim dividend in September 2012. Total cash outlay for the 2012 dividend is expected at approximately euro 3.9 billion (including euro 1.96 billion already paid in September 2012) in case the Annual Shareholders’ Meeting approves the annual dividend. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance to the full-year dividend to be paid in each following year. For further information about the Company’s dividend policy see "Item 5 – Management’s expectations of operations".

 

Significant changes

See "Item 5 – Recent developments" for a discussion of significant events occurred after 2012 year end up to the latest practicable date.

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Item 9. THE OFFER AND THE LISTING

Offer and listing details

The principal trading market for the ordinary shares of Eni SpA ("Eni"), without indication of par value (the "Shares"), is the Mercato Telematico Azionario (Electronic Share Market or "MTA"). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA ("Borsa Italiana"). Eni’s American Depositary Receipts ("ADRs"), each representing two Shares, are listed on the New York Stock Exchange. The ratio has changed from one ADR per five Shares to one ADR per two Shares, effective January 10, 2006.

The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. See "Item 3 – Key information - Exchange rates" regarding applicable exchange rates during the periods indicated below.

	MTA		New York Stock Exchange

	High		Low		High		Low

(euro per share)

($ per ADR)

2008		26.930		13.798		84.140		37.220
2009		18.350		12.300		54.450		31.070
2010		18.560		14.610		53.890		35.370
2011		18.420		12.170		53.740		32.980
2012		18.700		15.250		49.440		36.850
2011
First quarter		18.420		16.420		50.300		43.990
Second quarter		18.050		15.580		53.740		44.040
Third quarter		16.550		12.170		48.120		32.980
Fourth quarter		16.670		12.950		47.420		33.790
2012
First quarter		18.670		16.200		49.440		41.420
Second quarter		17.570		15.340		46.960		37.920
Third quarter		18.700		15.250		48.970		36.850
Fourth quarter		18.540		17.020		49.220		43.890
2013
First quarter
January 2013		19.480		18.400		52.120		49.270
February 2013		18.490		17.010		50.660		44.360
March 2013 (through March 18, 2013)		18.490		17.230		47.930		45.060

Until January 17, 2012, JPMorgan Chase Bank NA has functioned as depositary banking issuing ADRs pursuant to a deposit agreement among Eni, the depositary bank and the beneficial owners and registered holders from time of ADRs issued hereunder.

Effective January 18, 2012, The Bank of New York Mellon (the "Depositary") functions as depositary bank issuing ADRs pursuant to a deposit agreement (the "Deposit Agreement") among Eni, the Depositary and the beneficial owners ("Beneficial Owners") and registered holders from time to time of ADRs issued hereunder.

As of March 18, 2013 there were 35,890,018 ADRs outstanding, representing 71,780,036 ordinary shares or approximately 2% of all Eni’s shares outstanding, held by 112 holders of record (including the Depository Trust Company) in the United States, 109 of which are U.S. residents. Since certain of such ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere.

The Shares are included in the FTSE MIB Index (the "FTSE MIB"), the primary benchmark index for the Italian stock market. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on MTA and the Investment Vehicles Market ("MIV") and seeks to replicate the broad sector weights of the Italian stock market. The constituents of the FTSE MIB are selected according to the following criteria: market capitalization of free-float Shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for float. Since June 1, 2009 the FTSE MIB (previously S&P/MIB Index) is the principal indicator used to track the performance of the Italian stock market and is

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the basis for future and option contracts traded in the Italian Derivatives Market ("IDEM") managed by Borsa Italiana. The Shares are the first largest component of the FTSE MIB, with a weighting of approximately 15%, as established by FTSE after the quarterly rebalancing for FTSE MIB effective March 18, 2013.

Trading in the MTA is allowed in any quantity of the Shares as well as other financial instruments. Where necessary, Borsa Italiana may specify a minimum lot for each financial instrument. Since March 28, 2000, a three-day rolling cash settlement has been applied to all trades of equity securities in Italy, instead of the previous five-day settlement. In addition, future and option contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Market ("SeDeX"). IDEM facilitates the trading of future and option contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated market where it is possible to trade securitized derivatives (covered warrants and certificates).

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an "official price", calculated as the weighted average price of the total volume of each security traded in the market during the session, and a "reference price", calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective March 18, 2013: (i) ± 5.0% (or such other amount established by Borsa Italiana in the "Guide to the Parameters" for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall be the previous day’s reference price, in the opening auction, or the auction price, in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the "Guide to the Parameters") with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.

 

Markets

The Commissione Nazionale per le Società e la Borsa (the National Commission for Companies and the Stock Exchange or "Consob"), is the public authority responsible for regulating and supervising the Italian securities markets to ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, is a joint stock company authorized by Consob to operate regulated markets in Italy; it is responsible for the organization and management of the Italian stock exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading and the surveillance of the markets.

According to Consob Regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which are MTA (shares, convertible bonds, pre-emptive rights, warrants and Funds), ETFplus (Exchange Traded Funds and Exchange Traded Commodities market), IDEM (index and stock derivatives market), SeDeX (covered warrants and certificates), MOT (bond market) and MIV, as well as the admission to listing on and trading on these markets.

According to EU Markets in Financial Instruments Directive (No. 2004/39/EC) ("MiFID") and Consob Regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities ("MTF"s) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm or a bank which deals on own account by executing client orders outside a Regulated Market or a MTF. Outside Regulated Markets, block trading is also permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana.

According to Legislative Decree No. 58 of February 24, 1998 ("Decree No. 58"), the Consolidated Law on Financial Intermediation, the provision of investment services and activities to the public on a professional basis is reserved to banks and investment firms ("authorized persons"). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct.

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The Bank of Italy, in agreement with Consob, also regulates the operation of the clearing and settlement service for transactions involving financial instruments. The regulations and measures of general application adopted by Consob and the Bank of Italy are available on the website of Consob (www.consob.it) or Bank of Italy (www.bancaditalia.it).

The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it).

 

 

 

 

 

 

 

 

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Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

Register office

"Eni SpA" results from the privatization of Ente Nazionale Idrocarburi, a public agency, established by Law No. 136 of February 10, 1953 and it is registered in the Rome Companies Register, with identification number (and tax number) 00484960588, and VAT number 0090581106. The Company’s registered office is located in Rome, Italy, and the Company has two branch offices in San Donato Milanese (Milan).

The full text of Eni’s By-laws is attached as an exhibit to this annual report (last amended on February 14, 2013). See "Exhibit 1".

 

Company objects and purpose
In accordance with Article 4 of Eni’s By-laws, the Company purpose includes the direct and/or indirect exercise, through equity holdings in companies or other entities of: activities in the field of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law; activities in the field of chemicals, nuclear fuels, geothermal energy, renewable energy sources and energy in general, in the design and construction of industrial plants in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and in the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the afore mentioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

 

Directors’ issues

The Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting.

If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members.

The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions.

According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance.

The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time.

The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors.

In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors with voting rights must be present. Resolutions shall be approved by a majority of the votes of the Directors with voting rights present; in the event of a tie, the person who chairs the meeting shall have a casting vote.

 

Interests in Company’s transactions
As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob Regulation on transactions with related parties, the Board of Directors – on November 18, 2010 – unanimously

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approved the Management System Guidelines (MSG) "Transactions involving interests of directors and statutory auditors and transactions with related parties"²¹, which has been in effect from January 1, 2011²² to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. This MSG and the subsequent amendments received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The MSG sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and must leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required.

Moreover, to ensure compliance with the investigation and resolution procedures envisaged by the above mentioned MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in which they explain their potential interests related to Eni and its subsidiaries, and in any case they inform the CEO (or the Chairman, in the case the CEO holds an interest) about individual transactions that Eni intends to carry out in which they have an interest; the CEO (or Chairman) will then inform the other Directors and the Board of Statutory Auditors.

 

Compensation
Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors assigned particular duties in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the Compensation Committee, after consultation with the Board of Statutory Auditors (for more details about the compensation policy in 2012, see "Item 6 – Compensation").

 

Borrowing powers
The Company purpose includes the power to borrow. Moreover, in accordance with Article 11 of the By-laws, the Company may issue bonds, including convertibles bonds and warrants, in compliance with the law.

 

Retirement and shareholdings
There are no provisions in the By-laws relating to either retirement based on age-limit requirements and the number of shares required for a Director to qualify.

 

Company’s shares

In accordance with Article 5 of the By-laws, the Company’s share capital amounts to euro 4,005,358,876.00, fully-paid, and is represented by 3,634,185,330 ordinary registered shares without indication of par value. As required by the Italian law on the dematerialization of financial instruments, Eni’s shares must be held with "Monte Titoli SpA" (the Italian Central Depository for financial instruments) and their beneficial owners may exercise their rights through special deposit accounts opened with authorized intermediaries, such as banks, brokers and securities dealers.

Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the meeting, by electronic means.

Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.

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In 1995, Eni established a sponsored ADR (American Depositary Receipts) program directed at U.S. investors.

Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the New York Stock Exchange.

 

Dividend rights
Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations: specifically, the ordinary Shareholders’ Meeting called to approve the annual financial statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.

 

Voting rights
The general provisions on share "voting rights" are described at the paragraph "Shareholders’ Meeting" below. In relation to the appointment of the Board of Directors (Eni’s Board is not a "staggered board") and the Board of Statutory Auditors (see Item 6), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob (the public authority responsible for regulating the Italian securities market) in its regulation, or by the Board of Directors. Each shareholder may, severally or jointly, submit and vote on a single slate only.

There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.

 

Liquidation rights
In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors.

 

Change in shareholders’ rights

A shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision-making quorum established by law for extraordinary meetings.

 

Shareholders’ Meeting

The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in "ordinary" or "extraordinary" form. Resolutions of ordinary and extraordinary Shareholders’ Meetings in first, second or third call must be passed with the majorities required by law in each case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meeting be held after a single call. In the case of a single call, the majorities required by law in this case shall apply.

Shareholders’ Meetings shall normally be held at the Company’s registered office, unless otherwise decided by the Board of Directors, provided however they are held in Italy.

The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, which content is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by correspondence (the information is also available on the Company’s website) and, if envisaged, it may include instructions for participating in the Shareholders’ Meeting by means of telecommunication systems and exercise the right to vote by electronic means. By the same date of the publication of the notice calling the meeting, the Board of Directors shall make a report on each of the items on the agenda available to the public at the Company's registered

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office, on the Company website and by other means envisaged by Consob regulation. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up consolidated financial statements.

Entitlement to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit and debit records entered on the accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement issued by the authorized intermediary must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the meeting; otherwise, the date of each call is deemed the reference date.

Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collecting proxies shall be made available to said associations in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.

The right to vote may also be exercised by correspondence in accordance with the applicable provisions of laws and regulations. If envisaged in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules.

The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by law and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.

The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.

The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his/her opinion on the items on the agenda.

During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information.

 

Stock ownership limitation and voting rights restrictions

There are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign people to hold shares or vote other than the limitations described below (which are equally applicable to residents and non-residents in Italy).

In accordance with Article 6 of the By-laws, and applying the special rules pursuant to Article 3²³ of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.

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Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organization controlled by them are exempt from this ban.

Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.

 

Limitation on changes in control of the Company (Special Powers of the Italian State)

Pursuant to Article 6.2 of the By-laws and to the special rules set out in Law No. 474/1994, the Minister of the Economy and Finance, in agreement with the Minister of Economic Development, retains special powers that can be exercised in accordance with the criteria set out in the Decree issued by the President of the Council of Ministers on June 10, 2004.

These special powers are briefly the following:

(a)		power of opposition to the acquisition of material shareholdings (i.e. shareholdings that represent, directly and indirectly, at least 3% of the share capital and consist of shares with the right to vote in ordinary Shareholders’ Meetings). The opposition, duly justified, must be expressed if the transaction is deemed to be prejudicial to the vital interests of the State, within ten days of the date of the notice to be filed by the Directors at the time request is made for registration in the shareholders’ register. Pending expiry of the ten-day term, the voting rights and other rights, except for the right to participate in profits, attached to the shares that represent the material shareholding may not be exercised. In the event the right of opposition is exercised, by means of a duly justified decision based on the actual prejudicial effect caused by the transaction to the vital interests of the State, the transferee may not exercise the voting rights or any other non-financial rights attached to the shares representing the material shareholding, and must dispose of said shares within one year. In the event of a failure to comply, the Court, upon appeal of the Minister of the Economy and Finance, shall order the disposal of the shares representing the material shareholding in accordance with the procedures set out in Article 2359-ter of the Italian Civil Code;
(b)		power of opposition to the conclusion of shareholders’ agreements, as referred to in Article 122 of the Consolidated Law on Finance, involving at least 3% of the share capital with voting rights at the ordinary Shareholders’ Meetings. For the purpose of exercising said power of opposition, Consob shall notify the Minister of the Economy and Finance of any such agreements notified to it pursuant to Article 122 of the Consolidated Law on Finance. The power of opposition shall be exercised within ten days of the date of the notice from Consob. Pending expiry of the ten-day term, the voting rights and other non-financial rights attached to the shares held by the shareholders who have entered into such shareholders’ agreements may not be exercised. If the power of opposition is exercised, with a measure duly explicating the prejudice that the aforesaid agreements may cause to the vital interests of the Italian State, the shareholders’ agreement shall be null and void. If the conduct during the Shareholders’ Meeting of the shareholders bound by the agreement reveals that the undertakings given under an agreement pursuant to the aforesaid Article 122 of the Consolidated Law on Finance have been maintained, any resolutions passed with the casting vote of these same shareholders may be challenged;
(c)		power of veto, duly justified by the effective prejudice to the vital interests of the Italian State, with respect to resolutions to wind up the Company, to transfer the business, to merge, to demerge, to transfer the Company’s registered office abroad, to change the Company purpose or to amend the By-laws so as to eliminate or modify the powers set out in letters (a), (b), (c) and in the subsequent letter (d); and
(d)		power of appointment of one non-voting Director.

The decisions for exercising the powers detailed in letters (a), (b) and (c) may be challenged, within sixty days, by the parties entitled to do so, before the Regional Administrative Court of Lazio.

The special powers shall be exercisable with regard to significant and binding cases of general interest (public order, public security, public health and defense) in an appropriate way and measure and proportionally to the safeguarding of these interests, even by means of necessary time limits, without prejudice to compliance with national and European principles and, in particular, with the non-discrimination principle.

The Decree of the Italian Prime Minister of May 20, 2010, following on certain decisions of the European Court of Justice, repealed Article 1, paragraph 2 of the Decree issued by the Italian Prime Minister on June 10, 2004, related to the specific circumstances in which the special powers may be exercised.

The Law Decree No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified Italian legislation governing the special powers of the State to comply with European rules. The previous provisions (Article 2 of Law Decree No. 332/1994 ratified by Law No. 474/1994 and its implementing decrees), as well as the provisions of the By-laws which are inconsistent with the new rules, will be repealed by the last of the implementing

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ministerial regulations in the areas of energy, transport and communications. At the date of the filing of the present Form, the ministerial regulations had not been issued. Among the provisions to be repealed, those governing enforcement of Law No. 474/1994 related to Eni have been expressly identified. Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.

In order to "promote privatization and the spread of investment in shares" of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain such any provision.

 

Shareholder ownership thresholds

There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Finance²⁴ and Consob Regulation²⁵, any direct or indirect holding in the voting shares of an Italian listed company in excess of 2%²⁶, 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6%, 90% and 95% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds. Due declarations shall be made within five trading days of the date of the transaction triggering the obligation to notify, regardless of the date on which it is carried out, using the forms established in Annex 4A to the above mentioned Regulation.

The relevant thresholds noted above shall be calculated including: (i) shares owned by the reporting person, even if the voting rights belong or are assigned to third parties, or are suspended, as well as shares in which the voting rights belong or are assigned to him; and (ii) shares held through third parties (and shares whose voting rights are assigned to such third parties) such as nominees, trustees or subsidiary companies. The obligation to notify also applies to any direct or indirect holding owned through ADRs. Specific disclosure requirements (with partially different thresholds) are connected to so-called "potential holdings" (such as holdings of derivatives or other equity-linked securities).

Voting rights attached to listed shares which have not been notified pursuant to the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in Court, under the Italian Civil Code.

The Consolidated Law on Finance regulates cross-ownership matters as follows.

Cross-ownership between listed companies may not exceed 2% of the shares. The company that last exceeds the limit of 2% may not exercise the voting rights attached to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding, and any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code. If a person holds an interest exceeding 2% of the share capital of a listed company, such listed company or any entity controlling such listed company may not acquire an interest exceeding 2% of the share capital of a listed company controlled by the former. If the foregoing limit is exceeded, the person who last exceeded the foregoing limit (or both holders, if it is not possible to ascertain which of the two persons was the last to exceed the limit) may not exercise the voting rights attached to the shares exceeding the foregoing limit. In the event of non-compliance, the voting rights attached to the shares held in excess of the limit specified shall be suspended and any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code. The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company.

Under the Consolidated Law on Finance, any agreement, in whatever form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed in the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights attached to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares may be challenged under the Italian Civil Code.

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The same provisions also apply to agreements, in whatever form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe them; (c) provide for the purchase of the shares or of above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis) which aim to encourage or frustrate a takeover bid or an exchange tender offer, including commitments relating to non-participation in a takeover bid.

Moreover, under the Italian Civil Code (Article 2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed one-fifth of the capital of the parent company – if the latter is a listed company – taking into account for this purpose the shares held by the same parent company or its subsidiaries.

Finally, in accordance with Law No. 287 of October 10, 1990, any merger or acquisition of sole or joint control over a company that would create or strengthen a dominant position in the domestic market in a manner that eliminates or significantly reduces competition is prohibited and mergers and acquisition of specified dimension must be subject to the prior authorization of the Italian Antitrust Authority²⁷. However, if the acquiring party and the company to be acquired operate in more than one EU Member State and together exceed certain revenue thresholds, the antitrust approval for the acquisition falls under the exclusive jurisdiction of the European Commission.

 

Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than are required by law.

Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe new issues of shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.

 

Material contracts

None.

 

Exchange controls

There are no exchange controls in Italy. Residents and non-residents in Italy may effect any investments, divestments and other transactions that entail a transfer of assets to or from Italy, subject only to the reporting, record-keeping and disclosure requirements described below. In particular, residents of Italy may hold foreign currency and foreign securities of any kind, within and outside Italy, while non-residents may invest in Italian securities without restriction and may export from Italy cash, instruments of credit or payment and securities, whether in foreign currency or euro, representing interest, dividends, other asset distributions and the proceeds of dispositions.

Updated reporting and record-keeping requirements are contained in the Italian legislation which implements an EU directive regarding the free movement of capital. Such legislation requires that transfers into or out of Italy of cash or securities in excess of euro 12.5 thousand be reported in writing to the Relevant Authority (Ministry for Economy and Finance) by residents or non-residents that effect such transfers directly, or by banks, securities dealers or Poste Italiane SpA (Italian Mail) that effect such transactions on their behalf. In addition, banks, securities dealers or Poste Italiane SpA effecting such transactions on behalf of residents or non-residents of Italy are required to maintain records of such transactions for five years, which records may be inspected at any time by Italian tax and judicial authorities.

Non-compliance with these reporting and record-keeping requirements may result in administrative fines or, in the case of false reporting and in certain cases of incomplete reporting, criminal penalties.

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Taxation

The information set forth below is a summary only, and Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.

 

Italian taxation

The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.

 

Income tax
Dividends received by Italian resident individuals in relation to interest exceeding 2% of the voting rights or 5% of the share capital ("substantial interest") are included in the taxable income subject to personal income tax to the extent of 49.72% of their amount. Personal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends received by Italian resident individuals in relation to non-substantial interest not related to the conduct of a business are subject to a substitute tax of 20% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return. If the non-substantial interest is related to the conduct of a business, dividends received in respect of 2011 profits are included in the taxable business income to the extent of 49.72% of their amount.

Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to un-distributed profit of 2007 and previous years.

Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, and società di investimento a capitale variabile ("SICAV") are not subject to substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 20% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares.

Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund.

The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units.

Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to an 11% substitute tax.

Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 20%, provided that the interest is not connected to an Italian permanent establishment. Up to one fourth of the substitute tax withheld might be recovered by the non-resident shareholder from the Italian Tax Authorities upon provision of evidence of full payment of income tax on such dividend in his/her country of residence in an amount at least equal to the total refund claimed.

Dividends are subject to the 1.375% substitute tax introduced by Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to companies and entities subject to a corporate income tax in a European Union member state or in Norway.

The substitute tax may also be reduced under the tax treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income tax treaties with approximately 70 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that tax treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.

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In order to obtain the treaty benefit (reduced substitute tax rate) at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the treaty benefit, together with a certification issued by the foreign Tax Authorities stating that the shareholder is a resident of that country for treaty purposes.

Under the tax treaty between the United States and Italy, dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy-U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 20%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the "IRS") with respect to each dividend payment. The request for that certificate must include a statement, signed under penalties for perjury, to the effect that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.

Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 20%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference ("treaty refund") between the domestic rate and the treaty one by filing specific forms (certificate) with the Italian Tax Authorities.

As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the ADSs, such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or tax treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith.

 

Capital gains tax
This paragraph applies with respect to capital gains out of the scope of a business activity carried out in Italy.

Gains realized by Italian resident individuals upon the sale of substantial interest is included in the taxable base subject to personal income tax to the extent of 49.72% of their amount, while gains realized upon the sale of non-substantial interest is subject to a substitute tax at a 20% rate.

For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return:

•

the so-called "administered savings" tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (20%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and

•

the so-called "portfolio management" tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 20% substitute tax to be applied by the portfolio.

Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.

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On the contrary, gains realized by non-residents from substantial interest even in listed companies are deemed to be realized in Italy and consequently they are subject to the capital gains tax.

However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non-taxability pursuant to the convention have been satisfied.

 

Financial Transactions Tax
Italian Law No. 228 of December 24, 2012, has introduced a Tax on Financial Transactions which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable for financial year 2013 is 0.12% for ADR negotiated in regulated markets (like NYSE). For further years tax rate will be reduced to 0.10%. Tax applies to transactions realized from March 1, 2013.

Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Tax on Financial Transactions. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law.

 

Inheritance and gift tax Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006 effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:

(a)		4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding euro 1,000,000 (per beneficiary);
(b)		6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding euro 100,000 (per beneficiary);
(c)		6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity as well as to persons related by collateral affinity up to the third degree; and
(d)		8 per cent: in all other cases.

If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding euro 1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.

 

United States taxation

The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not purport to address all material tax consequences of the ownership of Shares or ADSs. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of Eni SpA’s Shares, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose "functional currency" is not the U.S. dollar.

This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, (the "Code"), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.

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If a partnership holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs.

As used in this section, the term "U.S. Holder" means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.

The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the income tax convention between the United States and Italy with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits.

In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax.

 

Dividends
Subject to the passive foreign investment company, or PFIC, rules discussed below, distributions paid on the shares generally will be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends-received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian tax Authorities. If you are a non-corporate U.S. Holder, dividends paid to you that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains provided that you hold the Shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends we pay with respect to the Shares or ADSs generally will be qualified dividend income. The amount of the dividend distribution that you must include in your income as a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot euro/$ rate on the date the dividend distribution is includible in your income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date you include the dividend payment in income to the date you convert the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a refund of the tax withheld is available to a U.S. Holder under Italian law or under the income tax convention between the United States and Italy, the amount of tax withheld that is refundable will not be eligible for credit against your U.S. federal income tax liability. See "Italian taxation – Income tax" above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the shares will be income from sources outside the United States and will, depending on your circumstances, be either "passive" or "general" income for purposes of computing the foreign tax credit allowable to you.

Sale or exchange of shares
Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent, determined at the spot rate on the date of disposition). Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non-corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.

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PFIC rules
Eni SpA believes that Shares and ADSs should not be treated as stock of a PFIC for U.S. federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, if you are a U.S. Holder, you would be treated as if you had realized such gain and certain "excess distributions" ratably over your holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, your Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during your holding period in your Shares or ADSs. Dividends that you receive from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to you either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.

 

Documents on display

Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at:

http://www.eni.com/en_IT/documentation/documentation.page?type=bilrap&header=documentazione&doc_from=hpeni_header.

The Company is subject to the information requirements of the U.S. Security Exchange Act of 1934 applicable to foreign private issuers.

In accordance with these requirements, Eni files its annual report on Form 20-F and other related documents with the SEC. It’s possible to read and copy documents that have been filed with the SEC at the SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, USA.

You may also call the SEC at +1 800-SEC-0330 or log on to www.sec.gov.

It is also possible to read and copy documents referred to in this annual report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17^th floor, New York, USA.

 

 

 

 

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Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the euro/$ exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil and gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.

The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and petrochemical operations depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the euro/$ exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products as in the case of gas prices. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.

As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, trading activities and risk management and optimization activities as well as, from time to time, to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil and gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives.

Due to a changed competitive environment in the European gas market and also considering the development of highly liquid spot markets for gas and volatile gas margins, management has implemented through 2011 new risk management policies and instruments to safeguard the value of the Company’s assets in the gas value chain and to seek to profit from market and trading opportunities. As part of its risk management strategy, the Company actively manages exposure to the commodity risk by entering into commodity derivatives transactions on both financial and physical trading venues targeting different objectives.

(i)		On one hand, management enters commodity derivative transactions to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. Management has been implementing tight correlation between such commodity derivatives transactions and underlying physical contracts in order to account for those derivatives in accordance with hedging accounting in compliance with IAS 39, where possible; and
(ii)		on the other hand, management enters purchase/sale commodity contracts for speculative purposes in order to alter the risk profile associated with a portfolio of assets (purchase contracts, transport entitlements, storage capacity) or leverage any price differences in the marketplace, seeking to increase margins on existing assets in case of favorable trends in the commodity pricing environment or seeking a potential profit based on expectations of future trends in prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. Those derivatives will be accounted through profit and loss, resulting in higher volatility in the gas business’ operating profit. These trading activities are executed within limits set by internal policies and guidelines that define the maximum tolerable level of market risk. Furthermore the Company intends to optimize the value of its assets (gas supply contracts, storage sites, transportation rights, customer base, and market position) by effectively managing the flexibilities associated with them. This can be achieved through strategies of asset-backed trading where the underlying items are represented by the Company’s assets. We believe that the risk associated with asset backed trading activities is mitigated by the natural hedge granted by the assets’ availability. In 2012, Eni’s risk management activities helped reduce the Group exposure to the commodity risk: Furthermore trading activities including asset-backed activities reported positive contribution to the Group results of operations. We are planning to expand those trading activities both in the Gas & Power and the Refining & Marketing businesses. In fact, in 2012 the Company started a reorganization to integrate the supply activities of the Gas & Power and Refining & Marketing segments together with our trading, risk management and the wholesale activities of gas and LNG. This integration will allow us to capture opportunities from market trends and synergies in commodity risk management.

Please refer to "Item 18 – note 34 of the Notes to the Consolidated Financial Statements" for a qualitative and quantitative discussion of the Company’s exposure to market risks. Please also refer to "Item 18 – notes 13, 20, 25 and 30 of the Notes to the Consolidated Financial Statements" for details of the different derivatives owned by the Company in these markets.

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Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Item 12A. Debt securities

Not applicable.

 

Item 12B. Warrants and rights

Not applicable.

 

Item 12C. Other securities

Not applicable.

 

Item 12D. American Depositary Shares

In the United States, Eni’s securities are traded in the form of ADSs (American Depositary Shares) which are listed on the New York Stock Exchange. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. Since January 18, 2012, Eni’s ADRs are issued, cancelled and exchanged at the office of Bank of New York Mellon, PO Box 358516 Pittsburgh, PA 15252-8516, as depositary (the "Depositary") under the Deposit Agreement between Eni, the Depositary and the holders of ADRs.

Bank of New York Mellon is also the transfer agent for Eni’s ADRs.

Société Générale Securities Services SpA and UniCredit SpA are the custodians (the "Custodian") on behalf of the holders of Eni’s ADRs, and their principal offices are located in Milan, Italy.

 

Fees and charges paid by ADR holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees.

 

 

 

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The table below sets forth all fees and charges that a holder of Eni’s ADRs may have to pay, either directly or indirectly, to Bank of New York Mellon, as Depositary.

Type of service		Amount of fees or charges (1)		Depositary Actions
(a) Depositing or substituting the underlying shares		$5.00 (or less) for each 100 ADSs (or portion of 100 ADSs)		Each person to whom ADRs are issued against deposits of shares, including deposits and issuances in respect of: • Share distributions, stock split, rights, merger. • Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities.
(b) Selling or exercising rights		$5.00 (or less) for each 100 ADSs (or portion of 100 ADSs)		Distribution or sale of securities, the fee being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities.
(c) Withdrawing an underlying security		$5.00 (or less) for each 100 ADSs (or portion of 100 ADSs)		Acceptance of ADRs surrendered for withdrawal of deposited securities.
(d) Transferring, splitting or grouping receipts		Registration or transfer fees		Transfers, combining or grouping of depositary receipts.
(e) Expenses of the depositary		Varied charges		Expenses incurred on behalf of holders in connection with: • The depositary’s or its custodian’s compliance with applicable law, rule or regulation. • Stock transfer or other taxes and other governmental charges. • Cable, telex, facsimile transmission/delivery. • Expenses of the depositary in connection with the conversion of foreign currency into U.S. dollars (which are paid out of such foreign currency). • Any other charge payable by Depositary or its agents.
(f) Distribution of cash		$0.02 (or less) per ADS		Any cash distribution to ADS registered holders.
(g) Depositary services		$0.02 (or less) per ADS per calendar year		Depositary services.

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(1)

All fees and charges are paid by ADR holders to Bank of New York Mellon as Depositary and Transfer agent.

 

Fees and payments made by the Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the New York Stock Exchange. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.

For the year 2012, as agreed in the Deposit Agreement with the previous depositary bank, JPMorgan Chase Bank of New York, and subsequent amendments, the Depositary will reimburse to Eni up to $1,500,000 in connection with above mentioned expenditures.

 

Expenses waived or paid directly to third parties by the Depositary
For the year 2012, the depositary has agreed to waive fees for standard costs associated with the administration of the ads program and has paid certain expenses directly to third parties on behalf of Eni SpA. These waived fees amounted to $117,487.39.

		2012
		($)

Fees paid to third parties		7,487.39
BNYMellon Products and Services		110,000.00
Total		117,487.39

 

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PART II

Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

 

 

Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

 

 

Item 15. CONTROLS AND PROCEDURES

Disclosure controls and procedures
In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act"), the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries.

The Company’s management, with the participation of the principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Rule 13a-14(c) under the Exchange Act as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the principal executive officer and principal financial officer have concluded that these disclosure controls and procedures are effective.

 

Management’s Annual Report on Internal Control over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.

The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system.

The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012, has been audited by Reconta Ernst & Young SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F.

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Changes in Internal Control over Financial Reporting
There have not been changes in the Company’s internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Item 16A. Board of Statutory Auditors financial expert

Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are "audit committee financial expert". These five members are: Ugo Marinelli, who is the Chairman of the Board, Roberto Ferranti, Paolo Fumagalli, Renato Righetti and Giorgio Silva. All members are independent.

 

Item 16B. Code of Ethics

Eni adopted a Code of Ethics that applies to all Eni’s employees including Eni’s principal executive officer, principal financial officer and principal accounting officer. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Corporate Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F.

Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model.

 

Item 16C. Principal accountant fees and services

Reconta Ernst & Young SpA has served as Eni’s principal independent public auditor for fiscal years 2012 and 2011 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.

The following table shows total fees paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures for services provided by Eni to its public auditors Reconta Ernst & Young SpA and its respective member firms, for the years ended December 31, 2012 and 2011, respectively:

	Year ended December 31,

		2011		2012

(euro thousand)

Audit fees		22,031		23,042
Audit-related fees		1,113		1,351
Tax fees		323		25
All other fees		-		3
Total		23,467		24,421

Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting.

Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due

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diligence, audit and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards.

Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities.

All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.

 

Pre-approval policies and procedures of the Internal Control Committee
The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities within the Eni Group which are either controlled or jointly-controlled (directly or indirectly) by Eni SpA. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s internal audit department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The internal audit department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors.

During 2012, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (c) of Rule 2-01 of Regulation S-X.

 

Item 16D. Exemptions from the Listing Standards for Audit Committees

Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, is performing the functions required by the SEC rules and the Sarbanes-Oxley Act to be performed by the audit committees of non-U.S. companies listed on the NYSE (see "Item 6 – Board of Statutory Auditors" above).

 

Item 16E. Purchases of equity securities by the issuer and affiliated purchasers

The issuer and its affiliated purchasers have not executed any purchase of equity securities of the issuer since the beginning of 2009 up as of the date of the 20-F filing for the year ended December 31, 2012.

On July 16, 2012, the Extraordinary and Ordinary Shareholders’ meeting resolved to authorize the Board of Directors to purchase – in one or more transactions and in any case within 18 months from the date of the resolution – up to a maximum number of 363,000,000 ordinary Eni shares on the Mercato Telematico Azionario and up to a total amount of euro 6,000 million. The Board of Directors resolved to propose to the annual Shareholders’ Meeting scheduled on May 10, 2013 to grant a proxy to the Board of Directors to continue the purchase program of treasury shares for a period of 18 months beginning from the date of the grant.

As of December 31, 2012, Eni’s treasury shares in portfolio amounted to No. 11,388,287 corresponding to 0.31% of share capital of Eni, for a total book value of euro 201 million. The decrease of No. 371,266,546 shares held in treasury from December 31, 2011 (No. 382,654,833 shares) related to the cancellation of No. 371,173,546 shares, as resolved by the Extraordinary and Ordinary Shareholders’ meeting held on July 16, 2012 and to the sale of No. 93,000 shares following 2004 stock option plan.

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Item 16F. Change in Registrant’s Certifying Accountant

Not applicable.

 

Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual

Corporate governance. Eni’s governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted.

This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities.

The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, also with reference to Corporate Governance Code for listed companies, which Eni has adopted (hereinafter the Corporate Governance Code).

 

Independent Directors

NYSE standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he/she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he/she is an employee of the issuer or a partner of the auditor).

In addition, a Director cannot be considered independent in the three-year "cooling-off" period following the termination of any relationship that compromised a Director’s independence.

Eni standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies.

In particular, a Director may not be deemed independent if he/she or an immediate family member has relationships with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of their judgment.

Eni’s By-laws require that at least one Director – if the Board has no more than five members – or at least three Directors – if the Board is composed of more than five members – must satisfy the independence requirements.

Corporate Governance Code provides for additional independence requirements, recommending that the Board of Directors includes an adequate number of independent non-executive Directors. In particular, for issuers belonging to FTSE-Mib index of the Italian Stock Market, like Eni, the Corporate Governance Code recommends that at least one third of the members of the Board of Directors shall be independent Directors. In any event, independent Directors shall not be fewer than two. Independence is defined as not being currently or recently involved in any direct or indirect relationship with the issuer or other parties associated with the issuer and which may influence his/her independent judgment.

After the appointment of a Director who qualifies himself/herself as independent and subsequently, upon the occurrence of circumstances affecting the independence requirements and in any case at least once a year, the Board of Directors assesses the independence of the Director. The Board of Statutory Auditors verifies the correct application of the criteria and procedures adopted by the Board of Directors to evaluate the independence of its members.

The Board of Directors shall disclose the result of its evaluations, after the appointment, through a press release to the market and, subsequently, in the Annual Corporate Governance Report.

In accordance with Eni’s By-laws, if a Director does not or no longer satisfies the independence requirements or the minimum number of independent Directors fall below the threshold set by Eni’s By-laws, the Board declares the

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Director disqualified and provides for his/her substitution. Directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise.

 

Meetings of non-executive Directors

NYSE standards. Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors.

In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year.

Eni standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year without the other Directors. During 2012, Eni’s independent Directors had numerous opportunities to meet, formally and informally, to hold discussions and exchange opinions.

 

Audit Committee

NYSE standards. Listed U.S. companies must have an audit committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

Eni standards. At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on regulated U.S. markets, assigned the Board of Statutory Auditors, effective from June 1, 2005 and within the limits set by Italian law, the functions specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the SEC rules (see "Item 6 – Board of Statutory Auditors" earlier).

Under Section 303A.07 of the NYSE Listed Company Manual, audit committees of U.S. companies have additional functions and duties which are not mandatory for non-U.S. private issuers and which are therefore not included in the list of functions reported in "Item 6 – Board of Statutory Auditors".

 

Nominating/Corporate Governance Committee

NYSE standards. U.S. listed companies must have a nominating/corporate governance committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers.

Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a nomination committee the majority of whose member shall be independent Directors.

On July 28, 2011, the Board of Directors of Eni established the Nomination Committee, chaired by the Chairman of the Board of Directors, Giuseppe Recchi, and composed of the Chairmen of the other Board Committees: Alessandro Lorenzi (Chairman of the Control and Risk Committee), Alessandro Profumo (Chairman of the Oil-Gas Energy Committee) and Mario Resca (Chairman of the Compensation Committee). The Nomination Committee is made up of three to four Directors, a majority of whom are independent in accordance with the recommendations of the Corporate Governance Code²⁸. Further details on this Committee are reported in the Item 6.

 

Code of Business Conduct and Ethics

NYSE standards. The NYSE listing standards require each U.S. listed company to adopt a code of business conduct and ethics for its Directors, officers and employees, and to promptly disclose any waivers of the code for Directors or executive officers.

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Eni standards. At its meetings of December 15, 2003, and January 28, 2004, the Board of Directors of Eni approved an organizational, management and control model pursuant to Italian Legislative Decree No. 231 of 2001 (hereinafter "Model 231") and established the associated Eni Watch Structure. Moreover, after subsequent approvals of the updates to Model 231 in response to changes in the Italian legislation governing the matter and in the Company organizational structures, on March 14, 2008, the Board of Directors approved the overall revision of Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of Eni’s Code of Conduct of 1998. Eni’s Code of Ethics, which is an integral part of Model 231, sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on ongoing basis: shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All the people working for Eni, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties. The synergies between the Code of Ethics and Model 231 are underscored by the designation of the Eni Watch Structure, established under Model 231, as the Guarantor of the Code of Ethics. The Guarantor of the Code of Ethics acts to ensure the protection and promotion of the above principles. Every six months, it presents a report on the implementation of the Code to the Control and Risk Committee, to the Board of Statutory Auditors and to the Chairman and the CEO, who in turn reports on this to the Board of Directors. The composition of the Model 231 Watch Structure – initially formed of only three members – was modified in 2007 with the inclusion of two external members, one of whom was appointed the Chairman of the Watch Structure itself, selected from among academics and professionals with proven experience in economic and business management matters. The internal members are the Senior Executive Vice President Legal Affairs, Executive Vice President Human Resources and Organization and Senior Executive Vice President Internal Audit of the Company. On May 19, 2011, the Board of Directors, with the favorable opinion of the Board of Statutory Auditors, appointed the current members of the Watch Structure.

 

Item 16H. Mine safety disclosure

Not applicable since Eni does not engage in mining operations.

 

 

 

 

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PART III

Item 17. FINANCIAL STATEMENTS

Not applicable.

 

 

Item 18. FINANCIAL STATEMENTS

Index to Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheet as of December 31, 2012 and 2011	F-3
Consolidated profit and loss account for the years ended December 31, 2012, 2011 and 2010	F-4
Consolidated Statements of comprehensive income for the years ended December 31, 2012, 2011 and 2010	F-5
Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2012, 2011 and 2010	F-6
Consolidated Statement of cash flows for the years ended December 31, 2012, 2011 and 2010	F-9
Notes to the Consolidated Financial Statements	F-11

 

 

Item 19. EXHIBITS

1. By-laws of Eni SpA

8. List of subsidiaries

11. Code of Ethics

Certifications:

12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act

13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)

15.a(i) Report of DeGolyer and MacNaughton
15.a(ii) Report of Ryder Scott Co

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Shareholders of Eni S.p.A.

We have audited the accompanying consolidated balance sheets of Eni S.p.A. as of December 31, 2012 and 2011, and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eni S.p.A. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni S.p.A.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 9, 2013 expressed an unqualified opinion thereon.

/s/ Reconta Ernst & Young S.p.A.

Rome, Italy

April 9, 2013

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Table of Contents

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Shareholders of Eni S.p.A.

We have audited Eni S.p.A.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Eni S.p.A. management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting on page 185. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Eni S.p.A. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Eni S.p.A. as of December 31, 2012 and 2011, and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 and our report dated April 9, 2013 expressed an unqualified opinion thereon.

/s/ Reconta Ernst & Young S.p.A.

Rome, Italy

April 9, 2013

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CONSOLIDATED BALANCE SHEET
(euro million)

		Dec. 31, 2011		Dec. 31, 2012

		Note		Total amount		of which with related parties		Total amount		of which with related parties

ASSETS
Current assets
Cash and cash equivalents		(7)		1,500					7,765
Other financial assets available for sale		(8)		262					235
Trade and other receivables		(9)		24,595			1,496		28,621			2,714
Inventories		(10)		7,575					8,496
Current tax assets		(11)		549					771
Other current tax assets		(12)		1,388					1,230
Other current assets		(13)		2,326			2		1,624			8
				38,195					48,742
Non-current assets
Property, plant and equipment		(14)		73,578					63,466
Inventory - compulsory stock		(15)		2,433					2,538
Intangible assets		(16)		10,950					4,487
Equity-accounted investments		(17)		5,843					4,265
Other investments		(17)		399					5,085
Other financial assets		(18)		1,578			704		1,229			642
Deferred tax assets		(19)		5,514					4,913
Other non-current receivables		(20)		4,225			3		4,400			43
				104,520					90,383
Assets held for sale		(31)		230					516
TOTAL ASSETS				142,945					139,641
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		(21)		4,459			503		2,223			403
Current portion of long-term debt		(26)		2,036					2,961
Trade and other payables		(22)		22,912			1,446		23,581			1,616
Income taxes payable		(23)		2,092					1,622
Other taxes payable		(24)		1,896					2,162
Other current liabilities		(25)		2,237					1,437			6
				35,632					33,986
Non-current liabilities
Long-term debt		(26)		23,102					19,279
Provisions for contingencies		(27)		12,735					13,603
Provisions for employee benefits		(28)		1,039					982
Deferred tax liabilities		(29)		7,120					6,740
Other non-current liabilities		(30)		2,900					1,977			16
				46,896					42,581
Liabilities directly associated with assets held for sale		(31)		24					361
TOTAL LIABILITIES				82,552					76,928
SHAREHOLDERS’ EQUITY		(32)
Non-controlling interest				4,921					3,514
Eni shareholders’ equity
Share capital				4,005					4,005
Reserve related to cash flow hedging derivatives net of tax effect				49					(16	)
Other reserves				53,195					49,579
Treasury shares				(6,753	)				(201	)
Interim dividend				(1,884	)				(1,956	)
Net profit				6,860					7,788
Total Eni shareholders’ equity				55,472					59,199
TOTAL SHAREHOLDERS’ EQUITY				60,393					62,713
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY				142,945					139,641

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)

		2010		2011		2012

Note

Total amount

of which with related parties

Total amount

of which with related parties

Total amount

of which with related parties

REVENUES		(35)
Net sales from operations				96,617			2,905			107,690			3,477			127,220			3,783
Other income and revenues				967			57			926			41			1,546			56
				97,584						108,616						128,766
OPERATING EXPENSES		(36)
Purchases, services and other				68,774			5,820			78,795			5,880			95,363			6,604
- of which non-recurring charge (income)		(43)		(246	)					69
Payroll and related costs				4,428			28			4,404			33			4,658			21
OTHER OPERATING (EXPENSE) INCOME		(36)		131			41			171			32			(158	)		10
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS		(36)		9,031						8,785						13,561
OPERATING PROFIT				15,482						16,803						15,026
FINANCE INCOME (EXPENSE)		(37)
Finance income				6,109			41			6,376			49			7,218			53
Finance expense				(6,727	)					(7,410	)		(1	)		(8,274	)		(4	)
Derivative financial instruments				(131	)					(112	)					(251	)
				(749	)					(1,146	)					(1,307	)
INCOME (EXPENSE) FROM INVESTMENTS		(38)
Share of profit (loss) of equity-accounted investments				493						500						278
Other gain (loss) from investments				619						1,623			338			2,603
				1,112						2,123						2,881
PROFIT BEFORE INCOME TAXES				15,845						17,780						16,600
Income taxes		(39)		(8,581	)					(9,903	)					(11,659	)
Net profit for the year - Continuing operations				7,264						7,877						4,941
Net profit (loss) for the year - Discontinued operations		(31)		119			365			(74	)		400			3,732			2,234
Net profit for the year				7,383						7,803						8,673
Attributable to Eni
Continuing operations				6,252						6,902						4,198
Discontinued operations		(31)		66						(42	)					3,590
				6,318						6,860						7,788
Attributable to non-controlling interest		(32)
Continuing operations				1,012						975						743
Discontinued operations		(31)		53						(32	)					142
				1,065						943						885
Earnings per share attributable to Eni (euro per share)		(40)
Basic				1.74						1.89						2.15
Diluted				1.74						1.89						2.15
Earnings per share attributable to Eni
- Continuing operations (euro per share)		(40)
Basic				1.72						1.90						1.16
Diluted				1.72						1.90						1.16

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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(euro million)

		Note		2010		2011		2012

Net profit				7,383			7,803			8,673
Other items of comprehensive income
Foreign currency translation differences		(32)		2,169			1,031			(717	)
Change in the fair value of investments		(32)								141
Change in the fair value of other available-for-sale financial instruments		(32)		(9	)		(6	)		16
Change in the fair value of cash flow hedging derivatives		(32)		443			352			(102	)
Share of "Other comprehensive income" on equity-accounted entities		(32)		(10	)		(13	)		7
Taxation		(32)		(175	)		(128	)		32
Total other items of comprehensive income				2,418			1,236			(623	)
Total comprehensive income				9,801			9,039			8,050
Attributable to:
Eni				8,699			8,097			7,183
Non-controlling interest				1,102			942			867
				9,801			9,039			8,050

 

 

 

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(euro million)

	Eni shareholders’ equity

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of tax effect

Reserve related to the fair value of available-for-sale financial instruments net of tax effect

Other reserves

Cumulative currency translation differences

Treasury shares

Retained earnings

Interim dividend

Net profit for the year

Total

Non- controlling interest

Total shareholders’ equity

Balance at December 31, 2009		4,005			959			6,757			(439	)		5			1,492			(1,665	)		(6,757	)		39,160			(1,811	)		4,367			46,073			3,978			50,051
Net profit of the year																																6,318			6,318			1,065			7,383
Other items of comprehensive income
Foreign currency translation differences											(2	)								2,204						(75	)								2,127			42			2,169
Change in the fair value of cash flow hedging derivatives net of tax effect											267																								267						267
Change in the fair value of other available-for-sale financial instruments net of tax effect														(8	)																				(8	)					(8	)
Share of "Other comprehensive income" on equity-accounted entities																	(5	)																	(5	)		(5	)		(10	)
											265			(8	)		(5	)		2,204						(75	)								2,381			37			2,418
Total comprehensive income of the year											265			(8	)		(5	)		2,204						(75	)					6,318			8,699			1,102			9,801
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.50 per share in settlement of 2009 interim dividend of euro 0.50 per share)																													1,811			(3,622	)		(1,811	)					(1,811	)
Interim dividend distribution of Eni SpA (euro 0.50 per share)																													(1,811	)					(1,811	)					(1,811	)
Dividend distribution of other companies																																						(514	)		(514	)
Allocation of 2009 net profit																										745						(745	)
Effect related to the purchase of Italgas SpA and Stogit SpA by Snam SpA																	56																		56			(56	)
Treasury shares sold following the exercise of stock options by Eni managers								(1	)														1			1									1						1
Treasury shares sold following the exercise of stock options by Saipem and Snam managers																										10									10			27			37
Non-controlling interest recognized following the acquisition of the control stake in the share capital of Altergaz SA																																						7			7
Non-controlling interest excluded following the divestment of the control stake in the share capital of GreenStream BV																																						(37	)		(37	)
								(1	)								56						1			756						(4,367	)		(3,555	)		(573	)		(4,128	)
Other changes in shareholders’ equity
Cost related to stock options																										7									7						7
Stock options expired																										(6	)								(6	)					(6	)
Stock warrants on Altergaz SA																	(25	)																	(25	)					(25	)
Other changes																										13									13			15			28
																	(25	)								14									(11	)		15			4
Balance at December 31, 2010		4,005			959			6,756			(174	)		(3	)		1,518			539			(6,756	)		39,855			(1,811	)		6,318			51,206			4,522			55,728

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued
(euro million)

	Eni shareholders’ equity

Note

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of tax effect

Reserve related to the fair value of available-for-sale financial instruments net of tax effect

Other reserves

Cumulative currency translation differences

Treasury shares

Retained earnings

Interim dividend

Net profit for the year

Total

Non-controlling interest

Total shareholders’ equity

Balance at December 31, 2010			4,005			959			6,756			(174	)		(3	)		1,518			539			(6,756	)		39,855			(1,811	)		6,318			51,206			4,522			55,728
Net profit of the year																																	6,860			6,860			943			7,803
Other items of comprehensive income
Foreign currency translation differences	(32)																				1,000						31									1,031						1,031
Change in the fair value of cash flow hedging derivatives net of tax effect	(32)											223																								223						223
Change in the fair value of other available-for-sale financial instruments net of tax effect	(32)														(5	)																				(5	)					(5	)
Share of "Other comprehensive income" on equity-accounted entities	(32)																	(12	)																	(12	)		(1	)		(13	)
												223			(5	)		(12	)		1,000						31									1,237			(1	)		1,236
Total comprehensive income of the year												223			(5	)		(12	)		1,000						31						6,860			8,097			942			9,039
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.50 per share in settlement of 2010 interim dividend of euro 0.50 per share)																														1,811			(3,622	)		(1,811	)					(1,811	)
Interim dividend distribution of Eni SpA (euro 0.52 per share)	(32)																													(1,884	)					(1,884	)					(1,884	)
Dividend distribution of other companies																																							(571	)		(571	)
Allocation of 2010 net profit																											2,696						(2,696	)
Payments by minority shareholders																																							26			26
Acquisition of non-controlling interest relating to Altergaz SA and Tigáz Zrt	(32)																	(94	)								(25	)								(119	)		(7	)		(126	)
Effect related to the purchase of Italgas SpA by Snam SpA	(32)																	(5	)																	(5	)		5
Treasury shares sold following the exercise of stock options exercised by Eni managers	(32)								(3	)														3			3									3						3
Treasury shares sold following the exercise of stock options by Saipem and Snam managers	(32)																	14									(10	)								4			13			17
Non-controlling interest excluded following the sale of Acqua Campania SpA and the divestment of the control stake in the share capital of Petromar Lda																																							(10	)		(10	)
									(3	)								(85	)					3			2,664			(73	)		(6,318	)		(3,812	)		(544	)		(4,356	)
Other changes in shareholders’ equity
Cost related to stock options																											2									2						2
Stock options expired																											(7	)								(7	)					(7	)
Other changes																											(14	)								(14	)		1			(13	)
																											(19	)								(19	)		1			(18	)
Balance at December 31, 2011	(32)		4,005			959			6,753			49			(8	)		1,421			1,539			(6,753	)		42,531			(1,884	)		6,860			55,472			4,921			60,393

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued
(euro million)

	Eni shareholders’ equity

Note

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of tax effect

Reserve related to the fair value of available-for-sale financial instruments net of tax effect

Other reserves

Cumulative currency translation differences

Treasury shares

Retained earnings

Interim dividend

Net profit for the year

Total

Non-controlling interest

Total shareholders’ equity

Balance at December 31, 2011	(32)		4,005			959			6,753			49			(8	)		1,421			1,539			(6,753	)		42,531			(1,884	)		6,860			55,472			4,921			60,393
Net profit of the year																																	7,788			7,788			885			8,673
Other items of comprehensive income
Foreign currency translation differences	(32)																				(596	)					(104	)								(700	)		(17	)		(717	)
Change in the fair value of investments	(32)														138																					138						138
Change in the fair value of other available-for-sale financial instruments net of tax effect	(32)														14																					14						14
Change in the fair value of cash flow hedging derivatives net of tax effect	(32)											(65	)																							(65	)					(65	)
Share of "Other comprehensive income" on equity-accounted entities	(32)																	8																		8			(1	)		7
												(65	)		152			8			(596	)					(104	)								(605	)		(18	)		(623	)
Total comprehensive income of the year												(65	)		152			8			(596	)					(104	)					7,788			7,183			867			8,050
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.52 per share in settlement of 2011 interim dividend of euro 0.52 per share)	(32)																													1,884			(3,768	)		(1,884	)					(1,884	)
Interim dividend distribution of Eni SpA (euro 0.54 per share)	(32)																													(1,956	)					(1,956	)					(1,956	)
Dividend distribution of other companies																																							(686	)		(686	)
Allocation of 2011 net profit																											3,092						(3,092	)
Effect related to the sale of Snam SpA																											371									371			(1,602	)		(1,231	)
Acquisition of non-controlling interest relating to Altergaz SA and Tigáz Zrt	(32)																	(4	)																	(4	)		(3	)		(7	)
Treasury shares sold following the exercise of stock options exercised by Eni managers	(32)								(1	)														1			1									1						1
Treasury shares sold following the exercise of stock options by Saipem managers	(32)																	7																		7			22			29
									(1	)								3						1			3,464			(72	)		(6,860	)		(3,465	)		(2,269	)		(5,734	)
Other changes in shareholders’ equity
Elimination of treasury shares									(6,551	)														6,551
Reconstitution of the reserve for treasury share									6,000																		(6,000	)
Stock options expired																											(7	)								(7	)					(7	)
Other changes																		(1,140	)								1,156									16			(5	)		11
									(551	)								(1,140	)					6,551			(4,851	)								9			(5	)		4
Balance at December 31, 2012	(32)		4,005			959			6,201			(16	)		144			292			943			(201	)		41,040			(1,956	)		7,788			59,199			3,514			62,713

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)

		Note		2010		2011		2012

Net profit of the year - Continuing operations				7,264			7,877			4,941
Adjustments to reconcile net profit to net cash provided by operating activities
Depreciation and amortization		(36)		8,343			7,755			9,538
Impairments of tangible and intangible assets, net		(36)		688			1,030			4,023
Share of (profit) loss of equity-accounted investments		(38)		(493	)		(500	)		(278	)
Gain on disposal of assets, net				(558	)		(1,176	)		(875	)
Dividend income		(38)		(264	)		(659	)		(431	)
Interest income				(95	)		(99	)		(108	)
Interest expense				607			773			803
Income taxes		(39)		8,581			9,903			11,659
Other changes				(39	)		331			(1,945	)
Changes in working capital:

- inventories				(1,141	)		(1,400	)		(1,395	)
- trade receivables				(1,923	)		218			(3,184	)
- trade payables				2,811			34			2,029
- provisions for contingencies				575			109			338
- other assets and liabilities				(1,480	)		(657	)		(1,161	)

Cash flow from changes in working capital				(1,158	)		(1,696	)		(3,373	)
Net change in the provisions for employee benefits				22			(10	)		16
Dividends received				766			955			988
Interest received				124			99			91
Interest paid				(630	)		(927	)		(825	)
Income taxes paid, net of tax receivables received				(9,018	)		(9,893	)		(11,868	)
Net cash provided by operating activities - Continuing operations				14,140			13,763			12,356
Net cash provided by operating activities - Discontinued operations		(31)		554			619			15
Net cash provided by operating activities				14,694			14,382			12,371
- of which with related parties		(42)		(2,229	)		(639	)		(1,542	)
Investing activities:
- tangible assets		(14)		(12,308	)		(11,658	)		(11,222	)
- intangible assets		(16)		(1,562	)		(1,780	)		(2,295	)
- consolidated subsidiaries and businesses		(33)		(143	)		(115	)		(178	)
- investments		(17)		(267	)		(245	)		(391	)
- securities				(50	)		(62	)		(17	)
- financing receivables				(866	)		(715	)		(1,634	)
- change in payables and receivables in relation to investing activities and capitalized depreciation				261			379			54
Cash flow from investing activities				(14,935	)		(14,196	)		(15,683	)
Disposals:
- tangible assets				272			154			1,229
- intangible assets				57			41			61
- consolidated subsidiaries and businesses		(33)		215			1,006			3,521
- investments				569			711			1,203
- securities				14			128			52
- financing receivables				841			695			1,578
- change in payables and receivables in relation to disposals				2			243			(252	)
Cash flow from disposals				1,970			2,978			7,392
Net cash used in investing activities				(12,965	)		(11,218	)		(8,291	)
- of which with related parties		(42)		(1,626	)		(800	)		1,535

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CONSOLIDATED STATEMENT OF CASH FLOWS continued
(euro million)

		Note		2010		2011		2012

Proceeds from long-term debt		(26)		2,953			4,474			10,484
Repayments of long-term debt		(26)		(3,327	)		(889	)		(3,784	)
Increase (decrease) in short-term debt		(21)		2,646			(2,481	)		(753	)
				2,272			1,104			5,947
Net capital contributions by non-controlling interest							26
Sale of treasury shares							3
Net acquisition of treasury shares different from Eni SpA				37			17			29
Acquisition of additional interests in consolidated subsidiaries							(126	)		604
Dividends paid to Eni’s shareholders				(3,622	)		(3,695	)		(3,840	)
Dividends paid to non-controlling interest				(514	)		(552	)		(539	)
Net cash used in financing activities				(1,827	)		(3,223	)		2,201
- of which with related parties		(42)		(23	)		348			(94	)
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)							(7	)		(4	)
Effect of exchange rate changes on cash and cash equivalents and other changes				39			17			(12	)
Net cash flow of the year				(59	)		(49	)		6,265
Cash and cash equivalents - beginning of the year		(7)		1,608			1,549			1,500
Cash and cash equivalents - end of the year		(7)		1,549			1,500			7,765

 

 

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Notes to the Consolidated Financial Statements

1 Basis of presentation

The Consolidated Financial Statements of Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IAS B). Oil and natural gas exploration and production activity is accounted for in conformity with internationally accepted accounting principles. Specifically, this concerns the determination of the amortization expenses using the unit-of-production method and the recognition of the production-sharing agreement and buy-back contracts. The Consolidated Financial Statements have been prepared on a historical cost basis, taking into account where appropriate of any value adjustments, except for certain items that under IFRS must be recognized at fair value as described in the summary of significant accounting policies paragraph.

The Consolidated Financial Statements include the statutory accounts of Eni SpA and the accounts of subsidiaries where the Company holds the right to directly or indirectly exercise control, determine financial and operating policies and obtain economic benefits from their activities. For entities acting as sole-operator in the management of oil and gas contracts on behalf of companies participating in a joint venture, the activities are financed proportionately based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized proportionally directly in the financial statements of the companies involved. The exclusion from consolidation of some subsidiaries, which are not material either individually or overall, has not produced significant¹ economic and financial effects on the Consolidated Financial Statements. These interests are accounted for as described below under the item "Financial fixed assets".

Subsidiaries’ financial statements are audited by the independent auditors who examine and certify also the information required for the preparation of the Consolidated Financial Statements. The 2012 Consolidated Financial Statements approved by Eni’s Board of Directors on March 14, 2013, were audited by the independent auditor Reconta Ernst & Young SpA. The independent auditor of Eni SpA, as the main auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other independent auditors, it takes the responsibility of their work. Amounts in the financial statements and in the notes are expressed in millions of euros (euro million).

 

2 Principles of consolidation

Interests in consolidated companies
Assets and liabilities, revenues and expenses related to fully consolidated subsidiaries are wholly incorporated in the Consolidated Financial Statements; the book value of these subsidiaries is eliminated against the corresponding share of the shareholders’ equity by attributing to each of the balance sheet items its fair value.

Business combination transactions are recognized by applying the acquisition method. The consideration transferred in a business combination is measured at the acquisition date and is the sum of the fair value of the assets transferred, the liabilities assumed or incurred, as well as any equity instruments issued by the acquirer. Acquisition-related costs are recognized in profit and loss account when they are incurred.

When acquired, the equity of subsidiaries is initially recognized at fair value. The excess of the purchase price of an acquired entity over the total fair value assigned to assets acquired and liabilities assumed is recognized as goodwill; negative goodwill is recognized in the profit and loss account.

Equity and net profit of non-controlling interests are included in specific lines of equity and profit and loss account. If the partial control is acquired, this share of equity is determined using the proportionate share of the fair value of assets and liabilities, excluding any related goodwill, at the time when control is acquired (partial goodwill method); as an alternative, it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, taking into account therefore also the portion attributable to the non-controlling interests (full goodwill method); in the latter case, the non-controlling interests are measured at their total fair value which therefore

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includes the goodwill attributable to them². The method of measuring goodwill (partial goodwill method or full goodwill method) is selective for each business combination.

In a business combination achieved in stages, the purchase price is determined by summing the fair value of previously held equity interest in the acquiree and the consideration transferred for the acquisition of control; the previously held equity interest is remeasured at its acquisition date fair value and the resulting gain or loss is recognized in profit and loss account; furthermore, on acquisition of control, any component of the acquiree previously recognized in other comprehensive income is charged to the profit and loss account.

The purchase of additional equity interests in subsidiaries from non-controlling interests is recognized in the Group shareholders’ equity and represents the excess of the amount paid over the carrying value of the non-controlling interests acquired; similarly, the effects of the sale of non-controlling interests in subsidiaries without loss of control are recognized in equity. Conversely, the sale of equity interests with loss of control determines the recognition in the profit and loss account: (i) of any gain/loss calculated as the difference between the consideration received and the corresponding transferred share of equity; (ii) of the amount of any gain or loss recognized as a result of remeasuring to fair value any investment retained in the former subsidiary; and (iii) of any component related to the former subsidiary previously recognized in other comprehensive income. The retained investment is remeasured to its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria³.

Intercompany transactions
Intercompany transactions and balances, including unrealized profits arising from intragroup transactions have been eliminated. Unrealized profits with companies accounted for using the equity method are eliminated for the share of the Group shareholders’ equity. In both cases, unrealized losses are not eliminated as evidence of an impairment of the asset transferred.

Foreign currency translation
Financial statements of foreign companies having a functional currency other than the euro, that represents the Group’s functional currency, are translated into euro using the rates of exchange ruling at the balance sheet date for assets and liabilities, historical exchange rates for equity accounts and average rates for the profit and loss account (source: Bank of Italy). Cumulative exchange rate differences resulting from this translation are recognized in shareholders’ equity under "Other reserves" in proportion to the Group’s interest and under "Non-controlling interest" for the portion related to non-controlling interests. Cumulative exchange rate differences are charged to the profit and loss account when the entity disposes the entire interest in a foreign operation or at the loss of control of a foreign subsidiary. On the partial disposal, without losing control, the proportionate share of cumulative amount of exchange differences related to the disposed interest is recognized in equity to non-controlling interests. Financial statements of foreign subsidiaries which are translated into euro are denominated in the functional currencies of the Countries where the entities operate. The U.S. dollar is the prevalent functional currency for the entities that do not use the euro.

The main foreign exchange rates used to translate the financial statements adopting a different functional currency are indicated below:

(currency amount for euro 1)	Annual average exchange rate 2010		Exchange rate at Dec. 31, 2010		Annual average exchange rate 2011		Exchange rate at Dec. 31, 2011		Annual average exchange rate 2012		Exchange rate at Dec. 31, 2012

U.S. dollar		1.33		1.34		1.39		1.29		1.28		1.32
Pound sterling		0.86		0.86		0.87		0.84		0.81		0.82
Norwegian Krone		8.00		7.80		7.79		7.75		7.48		7.35
Australian dollar		1.44		1.31		1.35		1.27		1.24		1.27
Hungarian forint		275.48		277.95		279.37		314.58		289.25		292.30

 

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3 Summary of significant accounting policies

The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Current assets
Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due within 90 days, readily convertible to known amount of cash and subject to an insignificant risk of changes in value.

Held for trading financial assets and available-for-sale financial assets are measured at fair value with gains or losses recognized in the profit and loss account under "Financial income (expense)" and to the equity reserve related to other comprehensive income, respectively. Changes in fair value of available-for-sale financial assets recognized in equity are charged to the profit and loss account when the assets are derecognized or impaired. The objective evidence that an impairment loss has occurred is verified considering, interalia, significant breaches of contracts, serious financial difficulties or the risk of insolvency of the counterparty; asset write downs are included in the carrying amount. Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets and held-to-maturity financial assets. The fair value of financial instruments is determined by market quotations or, where there is no active market, it is estimated adopting suitable financial valuation models which take into account all the factors adopted by market operators and prices obtained in similar recent transactions in the market.

Interests and dividends on available-for-sale financial assets are accounted for on an accrual basis in "Financial income (expense)" and "Other gain (loss) from investments", respectively. When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame generally established by regulation or convention in the market place concerned, the transaction is accounted for on the settlement date. Receivables are measured at amortized cost (see item "Financial fixed assets" below). Transferred financial assets are derecognized when the contractual rights to receive the cash flows of the financial assets are transferred together with the risks and rewards of the ownership. Inventories, including compulsory stocks and excluding construction contracts, are stated at the lower of purchase or production cost and net realizable value. Net realizable value is the net amount expected to be realized from the sale of inventories in the normal course of business, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual sale price. Inventories of natural gas which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell.

The cost for inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted-average cost method on a three-month basis, or monthly, when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost for inventories of the Chemical segment is determined by applying the weighted-average cost on an annual basis.

Construction contracts are measured using the cost-to-cost method, whereby contract revenue is recognized by reference to the stage of completion of the contract matching it with the contract costs incurred in reaching that stage of completion. Advances are deducted from inventories within the limits of accrued contractual considerations; any excess of such advances over the value of the inventories is recorded as a liability. Losses related to construction contracts are recognized immediately as an expense when it is probable that total contract costs will exceed total contract revenues. Construction contract not yet invoiced, whose payment will be made in a foreign currency, is translated into euro using the rates of exchange ruling at the balance sheet date and the effect of rate changes is reflected in the profit and loss account. When take-or-pay clauses are included in long-term natural gas purchase contracts, uncollected gas volumes which imply the "pay" clause, measured using the price formulas contractually defined, are recognized under "Other assets" as "Deferred costs" as an offset to "Other payables" or, after the settlement, to "Cash and cash equivalents". The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually delivered – the related cost is included in the determination of the weighted-average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to collect gas that was previously uncollected within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, determined adopting the same criteria described for inventories. Hedging instruments are described in the section "Derivative instruments".

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Non-current assets

Property, plant and equipment⁴
Tangible assets, including investment properties, are recognized using the cost model and stated at their purchase or self-construction cost including any costs directly attributable to bringing the asset into operation. In addition, when a substantial period of time is required to make the asset ready for use, the purchase price or self-construction cost includes the borrowing costs incurred that could have otherwise been saved had the investment not been made.

In the case of a present obligation for the dismantling and removal of assets and the restoration of sites, the carrying value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be incurred at the moment the asset is retired.

Changes in estimate of the carrying amounts of provisions due to the passage of time and changes in discount rates are recognized under "Provisions for contingencies"⁵. Property, plant and equipment are not revalued for financial reporting purposes.

Assets carried under financial leasing or concerning arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset are recognized at fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt payable to the lessor is recognized as a financial liability. These assets are depreciated using the criteria described below. When the renewal is not reasonably certain, leased assets are depreciated over the shorter of the lease term or the estimated useful life of the asset.

Expenditures on renewals, improvements and transformations which provide additional economic benefits are recognized as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Tangible assets, from the moment they begin or should begin to be used, are depreciated systematically using a straight-line method over their useful life which is an estimate of the period over which the assets will be used by the Company. When tangible assets are composed of more than one significant element with different useful lives, each component is depreciated separately. The amount to be depreciated is the book value less the estimated net realizable value at the end of the useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see item "Assets held for sale and discontinued operations" below). Any change to the depreciation plan, deriving from changes in the asset’s useful life, in its residual value or in the pattern of consumption of the economic benefits embodied in the asset, shall be recognized prospectively.

Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession or the asset’s useful life. Replacement costs of identifiable components in complex assets are capitalized and depreciated over their useful life; the residual book value of the component that has been substituted is charged to the profit and loss account. Expenditures for ordinary maintenance and repairs are expensed as incurred. The carrying value of property, plant and equipment is reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying value with the recoverable amount, which is the higher of fair value less costs to sell or its value in use. If there is no binding sales agreement, fair value is estimated on the basis of market values, recent transactions, or the best available information that shows the proceeds that the Company could reasonably expect to collect from the disposal of the asset. Value in use is the present value of the future cash flows expected to be derived from the use of the asset and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life, net of disposal costs. Expected cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving more importance to independent assumptions. Oil, natural gas and petroleum products prices (and to prices for products which derive there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. Discounting is carried out at a rate that reflects a current market valuation of the time value of money and of those specific risks of the asset that are not reflected in the estimate of the future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific Country risk of the activity. The evaluation of the specific Country risk to be included in the discount rate is provided by external parties. The WACC differs considering the risk associated with

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individual operating segments; in particular for the assets belonging to the Gas & Power and Engineering & Construction segments, taking into account their different risk compared with Eni, specific WACC rates have been defined (for Gas & Power segment on the basis of a sample of companies operating in the same segment; for Engineering & Construction segment on the basis of the market quotation); WACC used for impairments in the Gas & Power segment is adjusted to take into consideration the risk premium of the specific Country of the activity while WACC used for impairments in the Engineering & Construction segment is not adjusted for Country risk as most of the assets are not located in a specific Country. For the other segments, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called "cash generating unit". When the reasons for their impairment cease to exist, Eni makes a reversal that is recognized in the profit or loss account as income from asset revaluation. This reversed amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

Intangible assets
Intangible assets are identifiable assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill acquired in business combinations. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or as an integral part of other assets. An entity controls an asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits. Intangible assets are initially stated at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes. Intangible assets with a definite useful life are amortized systematically over their useful life estimated as the period over which the assets will be used by the Company; the amount to be amortized and the recoverability of the carrying amount are determined in accordance with the criteria described in the section "Property, plant and equipment".

Goodwill and other intangible assets with an indefinite useful life are not amortized. The recoverability of their carrying value is reviewed at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management purposes. When the carrying amount of the cash generating unit, including goodwill allocated thereto, calculated considering any impairment loss of the non-current assets belonging to the cash generating unit, exceeds its recoverable amount⁶, the excess is recognized as an impairment loss. The impairment loss is first allocated to reduce the carrying amount of goodwill; any remaining excess to be allocated to the assets of the unit is applied pro-rata on the basis of the carrying amount of each asset in the unit. Impairment charges against goodwill are not reversed⁷. Costs of technological development activities are capitalized when: (i) the cost attributable to the development activity can be reliably determined; (ii) there is the intention, availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate future economic benefits.

Intangible assets also include public to private service concession arrangements concerning the development, financing, operation and maintenance of infrastructures under concession, in which the grantor: (i) controls or regulates what services the operator must provide with the infrastructure, and at what price; and (ii) controls – by the ownership, beneficial entitlement or otherwise – any significant residual interest in the infrastructure at the end of the concession arrangement. According to the agreements, the operator has the right to operate the infrastructure, controlled by the grantor, in order to provide the public service⁸.

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Exploration and production activities^{9 10}

Acquisition of mineral rights
Costs associated with the acquisition of mineral rights are capitalized in connection with the assets acquired (such as exploratory potential, probable and possible reserves and proved reserves). When the acquisition is related to a set of exploratory potential and reserves, the cost is allocated to the different assets acquired on the basis of the value of the relevant discounted cash flows. Expenditure for the exploratory potential, represented by the costs for the acquisition of the exploration permits and for the extension of existing permits, is recognized under "Intangible assets" and is amortized on a straight-line basis over the period of the exploration as contractually established. If the exploration is abandoned, the residual expenditure is charged to the profit and loss account. Acquisition costs for proved reserves and for possible and probable reserves are recognized in the balance sheet as assets. Costs associated with proved reserves are amortized on a UOP basis, as detailed in the section "Development", considering both developed and undeveloped reserves. Expenditures associated with possible and probable reserves are not amortized until classified as proved reserves; in case of a negative result, the costs are charged to the profit and loss account.

Exploration
Costs associated with exploratory activities for oil and gas producing properties incurred both before and after the acquisition of mineral rights (such as acquisition of seismic data from third parties, test wells and geophysical surveys) are initially capitalized in order to reflect their nature as an investment and subsequently amortized in full when incurred.

Development
Development expenditures are those costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas. They are then capitalized within property, plant and equipment and amortized generally on a UOP basis, as their useful life is closely related to the availability of feasible reserves. This method provides for residual costs at the end of each quarter to be amortized at a rate representing the ratio between the volumes extracted during the quarter and the proved developed reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between development expenditures and proved developed reserves. Costs related to unsuccessful development wells or damaged wells are expensed immediately as losses on disposal. Impairments and reversal of impairments of development costs are made on the same basis as those for tangible assets.

Production
Production costs are those costs incurred to operate and maintain wells and field equipment and are expensed as incurred.

Production-sharing agreements and buy-back contracts
Oil and gas reserves related to production-sharing agreements and buy-back contracts are determined on the basis of contractual clauses related to the repayment of costs incurred for the exploration, development and production activities executed through the use of Company’s technologies and financing (Cost Oil) and the Company’s share of production volumes not destined to cost recovery (Profit Oil). Revenues from the sale of the production entitlements against both Cost Oil and Profit Oil are accounted for on an accrual basis whilst exploration, development and production costs are accounted for according to the policies mentioned above. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on the behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense.

Retirement
Costs expected to be incurred with respect to the retirement of a well, including costs associated with removal of production facilities, dismantlement and site restoration, are capitalized, consistently with the policy described under "Property, plant and equipment", and then amortized on a UOP basis.

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Grants
Grants related to assets are recognized as a reduction of purchase price or production cost of the related assets when there is reasonable assurance that all the required conditions attached to them, agreed upon with government entities, have been met. Grants not related to capital expenditure are recognized in the profit and loss account on an accrual basis matching the related costs when incurred.

Financial fixed assets

Investments
Investments in subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for using the equity method¹¹. Under the equity method, investments are initially recognized at cost and subsequently adjusted to reflect: (i) the investor’s share of the post-acquisition profit or loss of the investee; and (ii) the investor’s share of the investee’s other comprehensive income. The changes in the equity of investees accounted for using the equity method, not arising from the profit or loss or from the other comprehensive income, are recognized in the investor’s profit and loss account, as they represent, basically, a gain or loss from a disposal of an interest of the investee’s equity. Distributions received from an investee are recorded as a reduction of the carrying amount of the investment. In applying the equity method, consolidations adjustments are considered (see also "Principles of consolidation" paragraph). When there is objective evidence of impairment (see also section "Current assets"), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the section "Property, plant and equipment". Subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for at cost, adjusted for impairment losses if this does not result in a misrepresentation of the Company’s financial condition. When the reasons for their impairment cease to exist, investments are revalued within the limit of the impairment made and their effects are included in "Other gain (loss) from investments". Other investments, included in non-current assets, are recognized at their fair value and their effects are included in the equity reserve related to other comprehensive income; the changes in fair value recognized in equity are charged to the profit and loss account when it is impaired or realized. Galp and Snam shares related to convertible bonds are measured at fair value through profit and loss account, under the fair value option, in order to significantly reduce the accounting mismatch with the recognition of the option embedded in the convertible bond, measured at fair value through profit and loss account.

When investments are not traded in a public market and their fair value cannot be reasonably determined, they are accounted for at cost, adjusted for impairment losses; impairment losses shall not be reversed¹².

The investor’s share of losses of an investee, that exceeds its interest in the investee, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to cover its losses.

Receivables and financial assets to be held to maturity
Receivables and financial assets to be held to maturity are stated at cost represented by the fair value of the initial exchanged amount adjusted to take into account direct external costs related to the transaction (e.g. fees of agents or consultants, etc.).

The initial carrying value is then adjusted to take into account principal repayments, reductions for impairment or uncollectibility and amortization of any difference between the maturity amount and the initial amount. Amortization is carried out on the basis of the effective interest rate of return represented by the rate that equalizes, at the moment of the initial recognition, the present value of expected cash flows to the initial carrying amount (so called "amortized cost method"). Receivables for finance leases are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease. If there is objective evidence that an impairment loss has been incurred (see also point "Current assets"), the impairment loss is measured by comparing the carrying value with the present value of the expected cash flows discounted at the effective interest rate as defined at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and financial assets to be held to maturity are recognized net of the allowance for impairment losses; when the impairment loss is definite the allowance for impairment losses is reversed for charges, otherwise for excess. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as "Financial income (expense)".

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Assets held for sale and discontinued operations
Non-current assets and current and non-current assets included within disposal groups, are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through their continuing use. For this to be the case, the sale must be highly probable and the asset or the disposal group must be available for immediate sale in its present condition.

Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized in the balance sheet separately from the entity’s other assets and liabilities. Non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell and their carrying amount. The classification as held for sale of equity-accounted investments determines the interruption of equity method accounting; therefore, in this case, the book value of the investment in accordance with the equity method represents the carrying amount for the measurement as non-current assets held-for sale.

Any difference between the carrying amount and the fair value less costs to sell is taken to the profit or loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale.

Non-current assets and current and non-current assets included within disposal groups, classified as held for sale, are considered a discontinued operation if, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognized on the disposal, are indicated in a separate profit and loss account item, net of the related tax effects.

When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retain after the sale.

Financial liabilities
Debt is measured at amortized cost (see item "Financial fixed assets" above). Financial liabilities are derecognized when they are extinguished, or when the obligation specified in the contract is discharged or cancelled or expires.

Provisions for contingencies
Provisions for contingencies are liabilities for expenses and charges of a definite nature and whose existence is certain or probable but for which at year end the timing or amount of future expenditure is uncertain. Provisions are recognized when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that the settlement of that obligation will result in an outflow of resources embodying economic benefits; and (iii) the amount of the obligation can be reliably estimated. The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation at the balance sheet date or to transfer it to third parties at that time. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any indemnity or penalty arising from failure to fulfill these obligations. If the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognized as "Financial income (expense)". When the liability regards a tangible asset (e.g. site dismantling and restoration), the provision is stated with a corresponding entry to the asset to which it refers. Charges to the profit and loss account are made with the amortization process. Costs that the Company expects to bear in order to carry out restructuring plans are recognized when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring. Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognized in the same profit and loss account item that had previously held the provision, or, when the liability regards tangible assets (i.e. site dismantling and restoration), changes in the provision are recognized with a corresponding entry to the assets to which they refer, to the extent of the assets’ carrying amounts; any excess amount is recognized to the profit and loss account.

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In note 27, the following contingent liabilities are described: (i) possible, but not probable obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the Company’s control; and (ii) present obligations arising from past events whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits.

Provisions for employee benefits
Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. In the first case, the Company’s obligation, which consists of making payments to the State or a trust or a fund, is determined on the basis of contributions due. The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. The actuarial gains and losses of defined benefit plans are recognized pro-rata on service, in the profit and loss account using the corridor method, if and to the extent that net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period exceed the greater of 10% of the present value of the defined benefit obligation or 10% of the fair value of the plan assets, over the expected average remaining working lives of the employees participating in the plan. Such actuarial gains and losses derive from changes in the actuarial assumptions used or from a change in the conditions of the plan. Obligations for long-term benefits are determined by adopting actuarial assumptions. The effect of changes in actuarial assumptions or a change in the characteristics of the benefit is taken to the profit or loss in its entirety.

Treasury shares
Treasury shares are recognized as deductions from equity at cost. Gains or losses resulting from subsequent sales are recognized in equity.

Revenues and costs

Revenues associated with sales of products and services are recognized when significant risks and rewards of ownership have passed to the customer or when the transaction can be considered settled and the associated revenue can be reliably measured. In particular, revenues are recognized for the sale of:

•		crude oil, generally upon shipment;
•		natural gas, upon delivery to the customer;
•		petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales of petroleum products are generally recognized upon shipment; and
•		chemical products and other products, generally upon shipment.

Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer. Revenues from crude oil and natural gas production from properties in which Eni has an interest together with other producers are recognized on the basis of Eni’s net working interest in those properties (entitlement method). Differences between Eni’s net working interest volume and actual production volumes are recognized at current prices at year end. Income related to partially rendered services is recognized in the measurement of accrued income if the stage of completion can be reliably determined and there is no significant uncertainty as to the collectability of the amount and the related costs. When the outcome of the transaction cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable. Revenues accrued during the year related to construction contracts are recognized on the basis of contractual revenues with reference to the stage of completion of a contract measured on the cost-to-cost basis. For service concession arrangements (see item "Intangible assets" above) in which customers fees do not provide a reliable distinction between the compensation for construction/update of the infrastructure and the compensation for operating it and in the absence of external benchmarks, revenues recognized during the construction/update phase are limited to the amount of the costs incurred. Additional revenues, derived from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them. Tangible assets, different from an infrastructure used in service concession arrangements, transferred from customers (or constructed using cash transferred from customers) and used to connect them to a network to supply goods and services, are recognized at their fair value as an offset to revenues. When more than one separately identifiable service is provided (for example, connection to a network and supply of goods) the entity shall assess for which one service it receives the transferred asset from the customer and it shall consistently recognize a revenue when the connection is delivered or over the lesser period between the

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length of the supply and the useful life of the transferred asset. Revenues are measured at the fair value of the consideration received or receivable net of returns, discounts, rebates, bonuses and direct taxation. Award credits, related to customer loyalty programs, are recognized as a separate component of the sales transaction which grant the right to customers. Therefore, the portion of revenues related to the fair value of award credits granted is recognized as an offset to the item "Other liabilities". The liability is charged to the profit and loss account in the period in which the award credits are redeemed by customers or the related right is lost. The exchange of goods and services of a similar nature and value do not give rise to revenues and costs as they do not represent sale transactions. Costs are recorded when the related goods and services are sold or consumed during the year or systematically allocated or when their future economic benefits cannot be identified. Costs associated with emission quotas, determined on the basis of the market prices, are recognized in relation to the amount of the carbon dioxide emissions that exceed the amount assigned. Costs related to the purchase of the emission rights are recorded as intangible assets net of any negative difference between the amount of emissions and the quotas assigned. Revenues related to emission quotas are recognized when they are realized through a sale transaction. In case of sale, if applicable, the acquired emission rights are considered as the first to be sold. Monetary receivables granted as a substitution of emission rights awarded free of charge are recognized as an offset to item "Other income" of the profit and loss account. Operating lease payments are recognized in the profit and loss account over the length of the contract. Labor costs include stock options granted to managers, consistent with their actual remunerative nature. The instruments granted are recorded at fair value on the vesting date and are not subject to subsequent adjustments; the current portion is calculated pro-rata over the vesting period¹³. The fair value of stock options is determined using valuation techniques which consider conditions related to the exercise of options, current share prices, expected volatility and the risk-free interest rate. The fair value of stock options is recorded as a charge to "Other reserves". The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized (see item "Intangible assets" above), are included in the profit and loss account.

Exchange rate differences
Revenues and costs associated with transactions in currencies other than the functional currency are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in currencies other than functional currency are converted by applying the year end exchange rate and the effect is stated in the profit and loss account. Non-monetary assets and liabilities denominated in currencies other than the functional currency valued at cost are translated at the initial exchange rate. Non-monetary items that are measured at fair value, recoverable amount or net realizable value are translated using the exchange rate at the date when the value is determined.

Dividends
Dividends are recognized at the date of the general shareholders’ meeting in which they were declared, except when the sale of shares before the ex-dividend date is certain.

Income taxes
Current income taxes are determined on the basis of estimated taxable income. The estimated liability is included in "Income taxes payable". Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the tax authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets or liabilities are recognized for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that have been enacted or substantively enacted for future years. Deferred tax assets are recognized when their recoverability is considered probable; in particular, deferred tax assets are recoverable when it is probable that taxable income will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carryforward of unused tax credits and unused tax losses are recognized to the extent that the recoverability is probable. Relating to the temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, the related deferred tax liabilities are not recognized if the investor is able to control the timing of reversal of the temporary differences and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to offsettable taxes. The balance of the offset, if positive, is recognized in the item "Deferred tax assets"; if negative, in the item "Deferred tax

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liabilities". When the results of transactions are recognized directly in shareholders’ equity, the related current and deferred taxes are also charged to the shareholders’ equity.

Derivatives
Derivatives, including embedded derivatives which are separated from the host contract, are assets and liabilities measured at their fair value which is estimated by using the criteria described in the item "Current assets". When there is objective evidence that an impairment loss has occurred for reasons different from fair value decreases (see item "Current assets"), derivative are recognized net of the allowance for impairment losses.

Derivatives are designated as hedging instruments when the relationship between the derivative and the hedged item is formally documented and the hedge is highly effective and regularly reviewed. When hedging instruments hedge the risk of changes of the fair value of the hedged item (fair value hedge, e.g. hedging of the variability on the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Hedged items are consistently adjusted to reflect, in the profit and loss account, the changes of fair value associated with the hedged risk; this applies even if the hedged item should be otherwise measured.

When derivatives hedge the cash flow variability risk of the hedged item (cash flow hedge, e.g. hedging the variability on the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the changes in the fair value of the derivatives, considered an effective hedge, are initially recognized in the equity reserve related to other comprehensive income and then reclassifies to profit and loss account in the same period during which the hedged transaction affects the profit and loss account.

The changes in the fair value of derivatives that do not meet the conditions required to qualify for hedge accounting are recognized in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognized in the profit and loss account item "Financial income (expense)"; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognized in the profit and loss account item "Other operating (expense) income". Economic effects of transactions to buy or sell commodities entered into to meet the entity’s normal operating requirements and for which the settlement is provided with the delivery of the underlying, are recognized on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

 

4 Financial statements¹⁴

Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature¹⁵. The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS. The statement of changes in shareholders’ equity includes profit and loss for the year, transactions with shareholders and other changes in shareholders’ equity. The statement of cash flows is presented using the indirect method, whereby net profit is adjusted for the effects of non-cash transactions.

 

5 Use of accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting

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for oil and natural gas activities, specifically in 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 recognition of revenues in the oilfield services construction and engineering businesses. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates follows.

Oil and gas activities
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Field reserves will only be categorized as proved when all the criteria for attribution of proved status have been met. At this stage, all booked reserves are classified as proved undeveloped. Volumes are subsequently reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings occur at the point of first oil or gas production. 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 and upward and 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 as 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 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, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment.

Impairment of assets
Assets are impaired when there are events or changes in circumstances that indicate the 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 for crude oil, natural gas, commodity chemicals and refined products. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred costs – see also item "Current assets") related to natural gas volumes not collected under long-term purchase 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 related to the activity involved. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. Oil, natural gas and petroleum product prices (and prices from products which are derived there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. The estimate of the future

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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 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 an indefinite useful life are not subject to amortization. The Company tests for impairment such assets at the cash-generating unit level on an annual basis and whenever there is an indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash generating unit is lower than the carrying amount, goodwill attributed to that cash generating unit is impaired up to that difference; if the carrying amount of goodwill is less than the amount of impairment, assets of the cash generating unit are impaired pro-rata on the basis of their carrying amount for the residual difference.

Asset retirement obligations
Obligations to remove tangible 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 future asset retirement obligations 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 subjectivity of these estimates is also increased by the accounting method used that requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically, at the time the asset is installed at the production location). When liabilities are initially recorded, the related fixed assets are increased by an equal corresponding amount. The liabilities are updated with the passage of time (i.e. interest accretion) and any change in the estimates following the modification of future cash flows and discount rate adopted. The recognized asset retirement obligations are based on future retirement cost estimates and incorporate many assumptions such as: expected recoverable quantities of crude oil and natural gas, abandonment time, future inflation rates and the risk-free rate of interest adjusted for the Company’s credit costs.

Business combinations
Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business at their respective fair values. Any positive residual difference is recognized as "Goodwill". Negative residual differences are credited to the profit and loss account. Management uses all available information to make these fair value determinations and, for major business combinations, typically engages independent external advisors to assist in the fair value determination of the acquired assets and liabilities.

Environmental liabilities
Together with other companies in the industries in which it operates, 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 has been incurred and the amount can be reasonably 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 insurance recoveries.

Provisions for 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 return on plan assets, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for

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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. The inflation rates reflect market conditions observed country by country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved; and (v) determination of the expected rates of return on assets is made through compound averaging. For each plan, the distribution of investments among bonds, equity and cash and their specific average expected rate of return is taken into account. Differences between expected and actual costs and between the expected return and the actual return on plan assets routinely occur and are called actuarial gains and losses. Eni applies the corridor method to amortize its actuarial losses and gains. This method amortizes on a pro-rata basis the net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period that exceed the greater of 10% of: (i) the present value of the defined benefit obligation; and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan. Additionally, obligations for other long-term benefits are determined by adopting actuarial assumptions. The effects of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety.

Contingencies
In addition to accruing the estimated costs for environmental liabilities, asset retirement obligation and employee benefits, Eni accrues for all contingencies that are both probable and estimable. These other contingencies are primarily related to litigation and tax issues. Determining the appropriate amount to accrue is a complex estimation process that includes subjective judgments of the management.

Revenue recognition in the Engineering & Construction segment
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 income, derived from a change in the scope of work, is 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.

 

6 Recent accounting principles

Accounting standards and interpretations issued by the IASB/IFRIC and endorsed by the EU
By Commission Regulation (EU) No. 475/2012 of June 5, 2012, the Amendments to IAS 1 "Presentation of Financial Statements - Presentation of Items of Other Comprehensive Income" (hereinafter "Amendments to IAS 1") have been endorsed. The Amendments to IAS 1 require, interalia, entities to group items presented in other comprehensive income on the basis of whether they are potentially reclassifiable to the profit and loss account subsequently, according to applicable IFRSs (reclassification adjustments). The Amendments to IAS 1 shall be applied for annual periods beginning on or after July 1, 2012 (for Eni: 2013 financial statements).

By Commission Regulation (EU) No. 475/2012 of June 5, 2012, the revised IAS 19 "Employee Benefits" (hereinafter "IAS 19") has been endorsed. The document requires, interalia: (i) to recognize actuarial gains and losses in other comprehensive income, eliminating the possibility to adopt the corridor approach. Actuarial gains and losses recognized in other comprehensive income will not be recycled through profit and loss account in subsequent periods; and (ii) to replace the separate presentation of the expected return on plan assets and the interest cost, with a single "net interest expense or income". This aggregate is determined by applying the discount rate used

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to measure the defined benefit obligation to the net defined benefit liability. The new provisions require, interalia, additional disclosures with reference to defined benefit plans. IAS 19 shall be applied for annual periods beginning on or after January 1, 2013¹⁶.

By Commission Regulation (EU) No. 1254/2012 of December 11, 2012, IFRS 10 "Consolidated Financial Statements" (hereinafter "IFRS 10") and the revised IAS 27 "Separate Financial Statements" (hereinafter "revised IAS 27") have been endorsed. The documents state, respectively, the provisions for the presentation and the preparation of consolidated and separate financial statements. IFRS 10 provide, interalia, a new definition of control to be consistently applied to all entities (included vehicles). According to this definition, an entity controls an investee when it is exposed, or has rights, to its (positive and negative) returns from its involvement and has the ability to affect those returns through its power over the investee. The standard provides some indicators to be considered in assessing control which include, interalia, potential voting rights, protective rights, the presence of agency relationships and franchise agreements. Furthermore, the new provisions acknowledge the existence of control of an investee even if the investor holds less than majority of voting rights due to shareholding dispersion or passive attitude of other shareholders. IFRS 10 and the revised IAS 27 shall be applied for annual periods beginning on or after January 1, 2014.

By Commission Regulation (EU) No. 1254/2012 of December 11, 2012, IFRS 11 "Joint Arrangements" (hereinafter "IFRS 11") and the revised IAS 28 "Investments in Associates and Joint Ventures" (hereinafter "revised IAS 28") have been endorsed. Depending on the rights and obligations of the parties arising from arrangements, IFRS 11 classifies joint arrangements into two types – joint operations and joint ventures – and states the required accounting treatment. With reference to joint ventures, the new provisions require to account for them using the equity method, eliminating proportionate consolidation. A joint operator accounts for assets/liabilities and expenses/revenues relating to the joint operation on the basis of its rights and obligations determined and specified in the contractual arrangements, rather than basing on its ownership interest in the joint operation. The revised IAS 28 defines, interalia, the accounting treatment to be adopted on disposal of an equity interest, or a portion of an equity interest, in a joint venture or an associate. IFRS 11 and the revised IAS 28 shall be applied for annual periods beginning on or after January 1, 2014.

By Commission Regulation (EU) No. 1254/2012 of December 11, 2012, IFRS 12 "Disclosure of Interests in Other Entities" (hereinafter "IFRS 12") has been endorsed. The standard combines all the disclosures to be provided in financial statements regarding subsidiaries, joint arrangements, associates and unconsolidated structured entities. IFRS 12 shall be applied for annual periods beginning on or after January 1, 2014.

By Commission Regulation (EU) No. 1255/2012 of December 11, 2012, IFRS 13 "Fair Value Measurement" (hereinafter "IFRS 13") has been endorsed. The standard defines a framework for fair value measurements, required or permitted by other IFRSs, and the required disclosures about fair value measurements. Fair value is defined as the price that would be received to sell an asset (or paid to transfer a liability) in an orderly transaction between market participants at the measurement date. IFRS 13 shall be applied for annual periods beginning on or after January 1, 2013.

By Commission Regulation (EU) No. 1256/2012 of December 13, 2012, the Amendments to IAS 32 "Financial Instruments: Presentation – Offsetting Financial Assets and Financial Liabilities" (hereinafter "the Amendments to IAS 32") and the Amendments to IFRS 7 "Financial Instruments: Disclosures – Offsetting Financial Assets and Financial Liabilities" (hereinafter "the Amendments to IFRS 7") have been endorsed. The documents state, respectively, the requirements for offsetting financial assets and financial liabilities and the related disclosures. In particular, the Amendments to IAS 32 state that: (i) in order to set off financial assets and liabilities, the right of set-off must be legally enforceable in all circumstances, such as in the normal course of business, in the event of default or in the event of insolvency or bankruptcy, of one or all of the counterparties; and (ii) in presence of specific characteristics, the gross simultaneous settlement of financial assets and liabilities, that eliminate or result in insignificant credit and liquidity risk, may be considered equivalent to net settlement. The Amendments to IFRS 7 relating to disclosures shall be applied for annual periods beginning on or after January 1, 2013. Conversely, the Amendments to IAS 32 shall be applied for annual periods beginning on or after January 1, 2014.

 

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Accounting standards and interpretations issued by the IASB/IFRIC and not yet endorsed by the EU
On November 12, 2009, the IASB issued IFRS 9 "Financial Instruments" (hereinafter "IFRS 9") which changes recognition and measurement criteria of financial assets and their classification in the financial statements. In particular, the new provisions require, interalia, a classification and measurement model of financial assets based exclusively on the following categories: (i) financial assets measured at amortized cost; and (ii) financial assets measured at fair value. The new provisions also require that investments in equity instruments, other than subsidiaries, joint ventures or associates, shall be measured at fair value with effects taken to the profit and loss account. If these investments are not held for trading purposes, subsequent changes in the fair value can be recognized in other comprehensive income, even if dividends are taken to the profit and loss account. Amounts taken to other comprehensive income shall not be subsequently transferred to the profit or loss account even at disposal. In addition, on October 28, 2010, the IASB updated IFRS 9 by incorporating the recognition and measurement criteria of financial liabilities. In particular, the new provisions require, interalia, that if a financial liability is measured at fair value through profit or loss, subsequent changes in the fair value attributable to changes in the own credit risk shall be presented in other comprehensive income; the component related to own credit risk is recognized in profit and loss account if the treatment of the changes in own credit risk would create or enlarge an accounting mismatch. On December 16, 2011, the IASB issued the document "Mandatory effective date and transition disclosures" which defer the effective date of IFRS 9 provisions to annual periods beginning on or after January 1, 2015 (previously January 1, 2013).

On June 28, 2012, the IASB issued the document "Consolidated Financial Statements, Joint Arrangements and Disclosure of Interests in Other Entities: Transition Guidance (Amendments to IFRS 10, IFRS 11 and IFRS 12)", which provides some clarifications and relieves on the transition requirements of IFRS 10, IFRS 11 and IFRS 12. The provisions shall be applied for annual periods beginning on or after January 1, 2013.

On May 17, 2012, the IASB issued the document "Annual Improvements to IFRSs 2009-2011 Cycle", which includes, basically, technical and editorial changes to existing standards. The provisions shall be applied for annual periods beginning on or after January 1, 2013.

Eni is currently reviewing these new IFRS to determine the likely impact on the Group’s results.

 

 

 

 

 

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Current assets

7 Cash and cash equivalents

Cash and cash equivalents of euro 7,765 million (euro 1,500 million at December 31, 2011) included financing receivables originally due within 90 days amounting to euro 5,861 million (euro 323 million at December 31, 2011). Cash and cash equivalents increased as a consequence of the reimbursement of intercompany loans mainly made by Snam prior to the divestment. The latter were related to amounts on deposit with financial institutions accessible only on a 48-hour notice. Restricted cash amounted to euro 84 million and referred to the Saipem segment as a consequence of judicial investigations and commercial proceedings. More information about the judicial investigations is disclosed in note 34 – Guarantees, commitments and risks – Algeria – Corruption investigation. The average maturity of financing receivables due within 90 days was 23 days and the effective average interest rate amounted to 0.5% (1.1% at December 31, 2011).

8 Other financial assets available for sale

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Securities held for operating purposes
Listed bonds issued by sovereign states		173		174
Listed securities issued by financial institutions		47		22
Non-quoted securities		5		5
		225		201
Securities held for non-operating purposes
Listed bonds issued by sovereign states		16		13
Listed securities issued by financial institutions		21		21
		37		34
		262		235

At December 31, 2011 and December 31, 2012, no financial assets were held for trading.

At December 31, 2012, bonds issued by sovereign states amounted to euro 187 million (euro 189 million at December 31, 2011). A break-down by country is presented below:

Nominal value (euro million)

Fair value (euro million)

Nominal rate of return (%)

Maturity date

Rating - Moody’s

Rating - S&P

Sovereign states

Fixed rate bonds

Belgium

28

31

from 2.35 to 4.38

from 2014 to 2021

Aa3

AA

Italy

23

23

from 2.50 to 5.25

from 2013 to 2034

Baa2

BBB+

Austria

17

17

from 1.57 to 3.15

from 2013 to 2015

Aaa

AA+

Portugal

24

23

from 2.73 to 3.83

from 2013 to 2019

Ba3

BB

Spain

14

14

from 3.00 to 3.83

from 2014 to 2018

Baa3

BBB-

Netherlands

12

13

from 2.46 to 3.02

from 2013 to 2016

Aaa

AAA

Germany

10

10

from 2.67 to 2.78

from 2014 to 2015

Aaa

AAA

France

10

10

from 2.20 to 3.01

from 2013 to 2014

Aa1

AA+

Finland

2

1

1.60

2015

Aaa

AAA

Slovakia

14

15

from 0.34 to 4.81

from 2013 to 2017

A2

A

Ireland

13

13

from 4.61 to 4.68

from 2019 to 2020

Ba1

BBB+

United States of America

15

12

from 2.54 to 3.54

from 2014 to 2019

Aaa

AA+

Floating rate bonds

Italy

5

5

2013

Baa2

BBB+

Total sovereign states

187

187

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Securities amounting to euro 48 million were issued by financial institutions with a rating ranging from Aaa to Baa3 (Moody’s) and from AAA to BBB- (S&P).

The effects of fair value evaluation of securities are set out below:

(euro million)		Carrying amount at Dec. 31, 2011		Changes recognized in equity		Carrying amount at Dec. 31, 2012

Fair value		(9	)		16			7
Deferred tax liabilities		1			(2	)		(1	)
Other reserves of shareholders’ equity		(8	)		14			6

Securities held for operating purposes of euro 201 million (euro 225 million at December 31, 2011) were designed to hedge the loss provisions of the Group’s insurance company Eni Insurance Ltd for euro 196 million (euro 220 million at December 31, 2011).

The break-down by currency of other financial assets held for trading or available for sale is presented below:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Euro		193		179
U.S. Dollar		51		38
Indian Rupee		18		18
		262		235

The fair value of securities was calculated basing on quoted market prices.

9 Trade and other receivables

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Trade receivables		17,709		19,966
Financing receivables:
- for operating purposes - short-term		468		440
- for operating purposes - current portion of long-term receivables		162		228
- for non-operating purposes		28		1,153
		658		1,821
Other receivables:
- from disposals		169		209
- other		6,059		6,625
		6,228		6,834
		24,595		28,621

Receivables are stated net of the valuation allowance for doubtful accounts of euro 1,636 million (euro 1,651 million at December 31, 2011):

(euro million)		Carrying amount at Dec. 31, 2011		Additions		Deductions		Other changes		Carrying amount at Dec. 31, 2012

Trade receivables		1,067		164		(169	)		(6	)		1,056
Financing receivables		6										6
Other receivables		578		7		(11	)					574
		1,651		171		(180	)		(6	)		1,636

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At the balance sheet date, Eni had in place transactions to transfer to factoring institutions certain trade receivables without recourse due in 2013 for euro 2,054 million of which without notification for euro 1,709 million (euro 1,779 million at December 31, 2011 without notification, due in 2012). Transferred receivables mainly related to the Refining & Marketing segment (euro 1,225 million), the Gas & Power segment (euro 754 million) and the Chemical segment (euro 75 million). Following the contractual arrangements with the financing institutions relating to receivables without notification, Eni collects the transferred receivables and transfers the collected amounts to those institutions. Furthermore, Engineering & Construction transferred without notification certain trade receivables without recourse due in 2013 for euro 149 million through Eni’s subsidiary Serfactoring SpA (euro 188 million at December 31, 2011, due in 2012).

The increase in trade receivables from the prior year balance sheet date of euro 2,257 million mainly related to increases in the Gas & Power segment (euro 2,843 million) and the Exploration & Production segment (euro 482 million) and a decrease of euro 976 million as a consequence of the deconsolidation of Snam and its subsidiaries.

Trade and other receivables were as follows:

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Trade receivables

Other receivables

Total

Trade receivables

Other receivables

Total

Neither impaired nor past due		14,505		5,062		19,567		16,859		5,714		22,573
Impaired (net of the valuation allowance)		977		221		1,198		1,257		204		1,461
Not impaired and past due in the following periods:
- within 90 days		953		86		1,039		1,295		84		1,379
- 3 to 6 months		360		61		421		216		22		238
- 6 to 12 months		441		190		631		159		239		398
- over 12 months		473		608		1,081		180		571		751
		2,227		945		3,172		1,850		916		2,766
		17,709		6,228		23,937		19,966		6,834		26,800

Trade receivables not impaired and past due primarily pertained to high-credit-rating public administrations and other highly-reliable counterparties for oil, natural gas and chemical products supplies.

Additions to the allowance reserve for doubtful trade receivable accounts amounted to euro 164 million (euro 167 million in 2011) and primarily related to the Gas & Power segment (euro 118 million), the Refining & Marketing segment (euro 18 million) and Chemical segment (euro 17 million). Deductions amounted to euro 169 million (euro 52 million in 2011) and related to the Gas & Power segment (euro 132 million) and the Refining & Marketing segment (euro 26 million).

Trade receivables included amounts withheld to guarantee certain contract work in progress for euro 178 million (euro 103 million at December 31, 2011).

Trade receivables in currencies other than euro amounted to euro 7,236 million.

Receivables related to divesting activities of euro 209 million (euro 169 million at December 31, 2011) included the current portion of receivables relating to the divestment of a 1.71% interest in the Kashagan project for euro 114 million and to the divestment of a 3.25% interest in the Karachaganak project (equal to Eni’s 10% interest) to the Kazakh partner KazMunaiGas for euro 82 million. A description of both transactions is reported in note 20 – Other non-current receivables.

Other receivables of euro 6,625 million (euro 6,059 million at December 31, 2011) included receivables for euro 481 million (euro 504 million at December 31, 2011) relating to the recovery of costs incurred to develop an oil&gas project in the Exploration & Production segment that is currently undergoing arbitration procedure and for euro 333 million amounts of gas to be delivered to gas customers which off-took lower gas volumes than the contractual minimum take thus triggering the take-or-pay clause provided for by the relevant long-term sales contracts. Deferred revenues amounting to euro 522 million are stated among other current and non-current liabilities.

Financing receivables associated with financing operating activities of euro 668 million (euro 630 million at December 31, 2011) included loans made to unconsolidated subsidiaries, joint ventures and associates for executing

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industrial project for euro 351 million (euro 345 million at December 31, 2011), cash deposits to hedge the loss provision made by Eni Insurance Ltd for euro 280 million (euro 250 million at December 31, 2011) and receivables for financial leasing for euro 26 million (euro 31 million at December 31, 2011). More information about receivables for financial leasing is disclosed in note 18 – Other financial assets.

Financing receivables not related to operating activities amounted to euro 1,153 million (euro 28 million at December 31, 2011) and primarily related to: (i) receivables from Cassa Depositi e Prestiti for euro 883 million, of which euro 879 million as settlement of the total consideration of euro 3,517 million relating to the divestment of 1,013,619,522 ordinary shares of Snam SpA and euro 4 million of interests on delay in payment; (ii) residual receivables from Snam SpA for euro 141 million; (iii) restricted deposits in escrow for euro 93 million of Eni Trading & Shipping SpA of which euro 72 million with Citigroup Global Markets Ltd and euro 21 million with commercial counterparts relating to derivatives; and (iv) restricted deposits in escrow of receivables of the Engineering & Construction segment for euro 25 million (euro 28 million at December 31, 2011).

Financing receivables in currencies other than euro amounted to euro 331 million.

Other receivables were as follows:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Receivables originated from divestments		169		209
Accounts receivable from:
- joint venture operators in exploration and production		3,827		4,217
- non-financial government entities		62		33
- insurance companies		171		176
- prepayments for services		837		616
- from factoring arrangements		150		130
- other receivables		1,012		1,453
		6,059		6,625
		6,228		6,834

Receivables deriving from factoring arrangements of euro 130 million (euro 150 million at December 31, 2011) related to Serfactoring SpA and consisted primarily of advances for factoring arrangements with recourse and receivables for factoring arrangements without recourse.

Other receivables in currencies other than euro amounted to euro 5,737 million.

Receivables with related parties are described in note 42 – Transactions with related parties.

Because of the short-term maturity of trade receivables, the fair value approximated their carrying amount.

10 Inventories

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Crude oil, gas and petroleum products

Chemical products

Work in progress

Other

Total

Crude oil, gas and petroleum products

Chemical products

Work in progress

Other

Total

Raw and auxiliary materials and consumables		892		172				1,722		2,786		948		190				1,748		2,886
Products being processed and semi-finished products		127		25				1		153		133		15				1		149
Work in progress						869				869						1,595				1,595
Finished products and goods		2,892		804				71		3,767		2,912		891				63		3,866
		3,911		1,001		869		1,794		7,575		3,993		1,096		1,595		1,812		8,496

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Work in progress increased by euro 726 million since the amount of work done was higher than the amount invoiced according to contractual terms.

Contract works in progress for euro 1,595 million (euro 869 million at December 31, 2011) are stated net of prepayments for euro 7 million (euro 11 million at December 31, 2011) which corresponded to the amount of the works executed and accepted by customers.

Changes in inventories and in the loss provision were as follows:

(euro million)

Carrying amount at the beginning of the year

Additions

New or increased provisions

Deductions

Changes in the scope of consolidation

Currency translation differences

Other changes

Carrying amount at the end of the year

December 31, 2011
Gross carrying amount		6,694			1,091									(20	)		38			(42	)		7,761
Loss provision		(105	)					(94	)		20						(2	)		(5	)		(186	)
Net carrying amount		6,589			1,091			(94	)		20			(20	)		36			(47	)		7,575
December 31, 2012
Gross carrying amount		7,761			1,158									(226	)		(18	)		(9	)		8,666
Loss provision		(186	)					(58	)		64			10			1			(1	)		(170	)
Net carrying amount		7,575			1,158			(58	)		64			(216	)		(17	)		(10	)		8,496

Additions for the year amounting to euro 1,158 million were recorded in the Engineering & Construction segment (euro 762 million) and the Refining & Marketing segment (euro 252 million). Changes in the scope of consolidation of euro 216 million related for euro 215 million to the deconsolidation of Snam and its subsidiaries as a consequence of the loss of control.

11 Current income tax assets

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Italian subsidiaries		399		487
Foreign subsidiaries		150		284
		549		771

Income taxes are described in note 39 – Income tax expense.

12 Other current tax assets

(euro million)		Dec. 31, 2011		Dec. 31, 2012

VAT		581		862
Excise and customs duties		239		197
Other taxes and duties		568		171
		1,388		1,230

The decrease in other taxes and duties amounting to euro 397 million was mainly related to foreign subsidiaries of the Exploration & Production segment (euro 323 million).

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13 Other current assets

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Fair value of non-hedging and trading derivatives		1,562		916
Fair value of cash flow hedge derivatives		157		31
Other current assets		607		677
		2,326		1,624

The fair value of non-hedging derivative contracts and derivatives contracts held for trading is presented below:

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Derivatives on exchange rate
Interest currency swap		16		50				8		44
Currency swap		204		5,819		833		158		3,349		4,597
Outright		2		116				3		215		8
		222		5,985		833		169		3,608		4,605
Derivatives on interest rate
Interest rate swap		6				1,885		1		23
		6				1,885		1		23
Derivatives on commodities
Over the counter		1,181		5,644		4,378		713		3,648		9,505
Future		68		452		438		26		825		9
Other		85				581		7		30		1
		1,334		6,096		5,397		746		4,503		9,515
		1,562		12,081		8,115		916		8,134		14,120

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation methods commonly used on the marketplace.

Fair values of non-hedging and trading derivatives of euro 916 million (euro 1,562 million at December 31, 2011) consisted of: (i) euro 564 million (euro 1,450 million at December 31, 2011) of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to movements in foreign currencies, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; and (ii) euro 352 million (euro 112 million at December 31, 2011) of commodity and trading derivatives entered by the Gas & Power segment in order to optimize the economic margin and by Eni Trading & Shipping SpA for trading purposes.

Fair value of cash flow hedge derivatives of euro 31 million (euro 157 million at December 31, 2011) pertained to the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated to highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanism of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. Negative fair value of contracts expiring by 2013 is disclosed in note 25 – Other current liabilities; positive and negative fair value of contracts expiring beyond 2013 is disclosed in note 20 – Other non-current receivables and in note 30 – Other non-current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are given in note 32 – Shareholders’ equity and in note 36 – Operating expenses.

Purchase and sale commitments of cash flow hedge derivatives amounted to euro 31 million and euro 510 million, respectively (purchase and sale commitments of euro 3,297 million and euro 610 million, respectively, at December 31, 2011).

Information on hedged risks and hedging policies is disclosed in note 34 – Guarantees, commitments and risks - Risk factors.

Other assets amounted to euro 677 million (euro 607 million at December 31, 2011) and included: (i) prepayments and accrued income for euro 146 million (euro 260 million at December 31, 2011); (ii) prepayments of euro 129 million that were made to gas suppliers upon triggering the take-or-pay clause provided by the relevant

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long-term supply arrangements to be collected within 2013; (iii) rentals for euro 51 million (euro 18 million at December 31, 2011); and (iv) insurance premiums for euro 49 million (euro 64 million at December 31, 2011).

Transactions with related parties are described in note 42 – Transactions with related parties.

Non-current assets

14 Property, plant and equipment

(euro million)

Net book amount at the beginning of the year

Additions

Depreciation

Impairments

Changes in the scope of consolidation

Currency translation differences

Reclassification to assets held for sale

Other changes

Net book amount at the end of the year

Gross book amount at the end of the year

Provisions for depreciation and impairments

December 31, 2011
Land		665			9									100			(9	)		(2	)		8			771			799			28
Buildings		832			305			(131	)		(40	)					12	)		(9	)		458			1,427			3,544			2,117
Plant and machinery		42,991			3,704			(6,094	)		(601	)		16			866			(209	)		6,821			47,494			121,166			73,672
Industrial and commercial equipment		991			383			(206	)		(2	)					(5	)					(702	)		459			1,789			1,330
Other assets		1,172			117			(113	)		(5	)		(116	)		6			(1	)		(231	)		829			2,308			1,479
Tangible assets in progress and advances		20,753			7,140						(243	)					523						(5,575	)		22,598			24,257			1,659
		67,404			11,658			(6,544	)		(891	)					1,393			(221	)		779			73,578			153,863			80,285
December 31, 2012
Land		771			5									(109	)		(8	)		(8	)		4			655			678			23
Buildings		1,427			61			(108	)		(45	)		(316	)		(2	)		(7	)		148			1,158			3,150			1,992
Plant and machinery		47,494			1,546			(7,012	)		(1,079	)		(9,719	)		(313	)		(304	)		8,283			38,896			112,170			73,274
Industrial and commercial equipment		459			74			(112	)		(3	)		(62	)		3						3			362			1,660			1,298
Other assets		829			89			(103	)		(75	)		(12	)		(7	)					5			726			2,239			1,513
Tangible assets in progress and advances		22,598			9,447						(407	)		(2,207	)		(187	)		(130	)		(7,445	)		21,669			23,400			1,731
		73,578			11,222			(7,335	)		(1,609	)		(12,425	)		(514	)		(449	)		998			63,466			143,297			79,831

Capital expenditures by segment were the following:

(euro million)		2011		2012

Capital expenditures
Exploration & Production		8,162			8,407
Gas & Power		128			156
Refining & Marketing		860			836
Chemicals		216			163
Engineering & Construction		1,084			998
Corporate and financial companies		73			71
Other activities - Snam (a)		1,153			539
Other activities		10			14
Elimination of intra-group profits		(28	)		38
		11,658			11,222

(a)		Capital expenditures for 2011 pertaining to the segment Other activities - Snam has been reclassified from the Gas & Power segment.

Capital expenditures included capitalized finance expenses of euro 173 million, of which euro 26 million relating to discontinued operations (euro 147 million in 2011, of which euro 36 million relating to discontinued operations) and related to the Exploration & Production segment (euro 105 million), the Refining & Marketing segment (euro 39 million) and the Chemical segment (euro 3 million). The interest rates used for capitalizing finance expense ranged from 2.1% to 5.1% (1.0% and 3.7% at December 31, 2011).

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The main depreciation rates used ranged as follows:

(%)
Buildings					2		-	10
Plant and machinery					2		-	10
Industrial and commercial equipment					4		-	33
Other assets					6		-	33

The break-down of impairments losses recorded in 2012 amounting to euro 1,609 million (euro 891 million in 2011) and the associated tax effect is provided below:

(euro million)		2011		2012

Impairment losses
Refining & Marketing		484		843
Exploration & Production		189		547
Chemicals		174		112
Gas & Power		5		80
Other segments		39		27
		891		1,609
Tax effects
Refining & Marketing		194		96
Exploration & Production		65		154
Chemicals		47		33
Gas & Power		2		21
Other segments		1		2
		309		306
Impairments net of the relevant tax effects
Refining & Marketing		290		747
Exploration & Production		124		393
Chemicals		127		79
Gas & Power		3		59
Other segments		38		25
		582		1,303

In assessing whether impairment is required, the carrying values of property, plant and equipment are compared with their recoverable amounts. The recoverable amount is the higher of an asset’s fair value less costs to sell and its value-in-use. Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by using the value-in-use which is calculated by discounting the estimated cash flows arising from the continuing use of an asset. The valuation is carried out for individual asset or for the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets (cash generating unit - CGU). The Group has identified its main CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields whereby technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Refining & Marketing segment, refining plants, warehouses and commercial facilities relating to each distribution channels and by Country (ordinary network, high-ways network, and wholesale activities); (iii) in the Chemical segment, production plants by business and related facilities; and (iv) in the Engineering & Construction segment, the business units Offshore E&C and Onshore E&C, onshore drilling facilities and individual rigs for offshore operations. The recoverable amount is calculated by discounting the estimated cash flows deriving from the continuing use of the CGU and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life. Cash flows are determined on the basis of the best information available at the moment of the assessment deriving: (i) for the first four years of each projection, from the Company’s four-year plan adopted by the top management which provides information on expected oil and gas production volumes, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates; (ii) beyond the four-year plan horizon, cash flow projections are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and along a time horizon which considers the following factors: (a) for the oil&gas CGUs, the residual life of the reserves and the associated projections of operating costs and development expenditures; (b) for the CGUs of the Refining & Marketing segment and the Chemical segment, the economical and technical life of the plants and associated projections of operating costs, expenditures to support plant efficiency, refining and marketing margins and, in the case of chemical plants their

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normalized operating results before depreciation, interest and taxes; and (c) for the CGUs of the gas market and the Engineering & Construction segment, the perpetuity method of the last-year-plan by using a nominal growth rate ranging from 0% to 2% considering possible adjustments to reflect any cyclicality observed in the business; and (iii) commodity prices are estimated on the basis of the forward prices prevailing in the marketplace as of the balance sheet date for the first four years of the cash flow projections and the long-term price assumptions adopted by the Company’s management for strategic planning purposes and capital budget allocation (see note 3 – Summary of significant accounting policies). In particular, the long-term price of oil adopted for assessing the future cash flows of the oil&gas CGUs was $90 per barrel which is adjusted to take into account the expected inflationary rate from 2016 onwards.

Values-in-use are estimated by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production, Refining & Marketing and Chemical segments to the Company’s weighted average cost of capital net of the risk factors attributable to Saipem and the G&P segment which are assessed on a stand alone basis. Then the discount rates are adjusted to factor in risks specific to each Country of activity (adjusted post-tax WACC). In 2012, the adjusted post-tax rates used for assessing values-in-use marginally decreased from the previous year reflecting a reduction in the financial parameters used for assessing the cost of capital: cost of borrowings to Eni determined by expected trends for borrowing spreads and management’s estimates about the composition of the Company’s finance debt and risk-free yields reflecting an expected decline in the risk premium of Italy. Those positive factors were partially absorbed by the increased weight of net equity in the determination of the cost of capital to the Group as the Board of Directors has reassessed the optimal mix between internally-generated funds versus third parties borrowings following the divestment of Snam. It is worth mentioning that the increased equity risk of the Eni share due to the divestment of a business with low volatility had no impact on the assessment of the cost of capital used for the impairment evaluations in the Exploration & Production, Refining & Marketing and Chemical segments. This conclusion is underpinned by the fact that in the past management adopted discount rates which excluded the mitigating effect of the lower volatility of Snam in the Eni’s portfolio. In 2012, the adjusted WACC used for impairment test purposes ranged from 7.2% to 13.0%.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

The amount of impairment losses recorded in the Refining & Marketing segment of euro 843 million reflected management’s expectations of a reduced profitability outlook due to continuing weak trading conditions in the refining business negatively affected by rising feedstock costs, higher costs for energy utilities which are indexed to the price of crude oil, excess capacity in the Mediterranean area and anticipated poor demand for fuels on the back of the economic downturn. Based on these drivers, management recognized impairment losses at the Company’s refining plants by adjusting their book value to their lower values-in-use considering expectations of unprofitable margins in the long term. Other minor impairments were recorded at a retail network, marginal lines of business and certain safety and maintenance expenditures incurred in the period that were written-off because they related to assets previously impaired. The largest impairment losses were recorded at two refineries which were tested for impairment using a post-tax discount rate of 7.6%, corresponding to a pre-tax discount rate of 10.2% and 9.0%, respectively.

The Exploration & Production segment recorded asset impairments amounting to euro 547 million of which euro 350 million related to proved properties and euro 197 million to unproved properties. The main drivers were downward reserve revisions and decreasing prices of oil and gas properties located in USA, of a gas property located in India and changed economics of an oil property located in Turkmenistan. These impairment losses were assessed using a post-tax discount rate of: (i) 7.3%, corresponding to a pre-tax discount rate of 10.9%, for an asset located in USA; (ii) 8.2%, corresponding to a pre-tax discount rate of 13.6%, for an asset located in India; and (iii) 8.3%, corresponding to a pre-tax discount rate of 15.7%, for an asset located in Turkmenistan.

In the Chemical segment impairment losses amounted to euro 112 million and related to loss-making business lines producing olefins and polyethylene at the Brindisi (Italy) and Dunkerque (France) plants and expenditures incurred in the period that were written-off because they related to assets previously impaired.

The Gas & Power segment recorded impairment losses of euro 80 million relating for euro 71 million to the tangible assets existing at an offshore storage field in the British section of the North Sea which development project has been suspended in the light of continuing weakness in the gas scenario.

Change in the scope of consolidation of euro 12,425 million comprised the deconsolidation of Snam following the sale to Cassa Depositi e Prestiti SpA of a 30% stake and loss of control therein (euro 12,432 million) and the inclusion in the scope of consolidation following the finalization of the 100% acquisition of Nuon Belgium NV (now merged in Eni Gas & Power NV) and Nuon Power Generation Walloon NV (now Eni Power Generation NV) which markets gas and electricity mainly to residential and business customers in Belgium (euro 7 million).

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Foreign currency translation differences of euro 514 million were primarily related to translations of entities accounts denominated in U.S. dollar (euro 759 million), partially offset by translations of entities accounts denominated in Norwegian krone (euro 207 million).

The reclassification to assets held for sale of euro 449 million comprised certain non-strategic assets of the Exploration & Production segment (euro 434 million).

Other changes of euro 998 million related to the initial recognition and change in estimates of the costs for dismantling and site restoration of euro 1,418 million, of which euro 1,351 million regarded the Exploration & Production segment. Such increase was partially offset by sales for a book value of euro 515 million and by depreciations related to the discontinued operations for euro 194 million. Sales of euro 515 million related to certain non-strategic assets of the Exploration & Production segment for euro 467 million, of which euro 163 million relating to the sale of the 3.25% interest in the Karachaganak project (equal to the Eni’s 10% interest). More information is disclosed in note 20 – Other non-current receivables.

Unproved mineral interests included in tangible assets in progress and advances are presented below:

(euro million)

Book amount at the beginning of the year

Acquisitions

Impairment losses

Transfers to proved mineral interest

Other changes and currency translation differences

Book amount at the end of the year

December 31, 2011
Congo		1,248									(8	)		40			1,280
Nigeria					697									61			758
Turkmenistan		688									(70	)		17			635
Algeria		446			57						(34	)		16			485
USA		718						(64	)		(458	)		21			217
India		55												(7	)		48
Other countries		106									(34	)		1			73
		3,261			754			(64	)		(604	)		149			3,496
December 31, 2012
Congo		1,280									(2	)		(24	)		1,254
Nigeria		758												(15	)		743
Turkmenistan		635						(109	)		(1	)		(9	)		516
Algeria		485									(124	)		(6	)		355
USA		217						(62	)		(51	)		42			146
India		48						(26	)								22
Other countries		73									(44	)					29
		3,496						(197	)		(222	)		(12	)		3,065

Impairment losses of euro 197 million are discussed in the previous paragraph.

Accumulated provisions for impairments amounted to euro 6,816 million and euro 8,058 million at December 31, 2011 and 2012, respectively.

At December 31, 2012, Eni pledged property, plant and equipment for euro 21 million primarily as collateral against certain borrowings (euro 27 million as of December 31, 2011).

Government grants recorded as a decrease of property, plant and equipment amounted to euro 132 million (euro 724 million at December 31, 2011). The decrease of euro 592 million related for euro 524 million to the deconsolidation of Snam.

Assets acquired under financial lease agreements amounted to euro 39 million (euro 19 million at December 31, 2011), of which euro 29 million related to service stations in the Refining & Marketing segment and euro 10 million related to FPSO ships used by the Exploration & Production segment to support oil production and treatment activities.

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 34 – Guarantees, commitments and risks - Liquidity risk.

Property, plant and equipment under concession arrangements are described in note 34 – Guarantees, commitments and risks - Asset under concession arrangements.

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Property, plant and equipment by segment

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Property, plant and equipment, gross
Exploration & Production		96,561			103,369
Gas & Power		4,206			4,373
Refining & Marketing		14,884			15,744
Chemicals		5,438			5,589
Engineering & Construction		11,809			12,621
Corporate and financial companies		422			470
Other activities - Snam (a)		19,449
Other activities		1,617			1,617
Elimination of intra-group profits		(523	)		(486	)
		153,863			143,297
Accumulated depreciation, amortization and impairment losses
Exploration & Production		51,034			55,836
Gas & Power		1,705			1,961
Refining & Marketing		10,126			11,305
Chemicals		4,478			4,661
Engineering & Construction		3,840			4,408
Corporate and financial companies		226			243
Other activities - Snam (a)		7,433
Other activities		1,541			1,541
Elimination of intra-group profits		(98	)		(124	)
		80,285			79,831
Property, plant and equipment, net
Exploration & Production		45,527			47,533
Gas & Power		2,501			2,412
Refining & Marketing		4,758			4,439
Chemicals		960			928
Engineering & Construction		7,969			8,213
Corporate and financial companies		196			227
Other activities - Snam (a)		12,016
Other activities		76			76
Elimination of intra-group profits		(425	)		(362	)
		73,578			63,466

(a)		Property, plant and equipment as of December 31, 2011, pertaining to the segment Other activities - Snam has been reclassified from the Gas & Power segment.

15 Inventory - compulsory stock

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Crude oil and petroleum products		2,284		2,538
Natural gas		149
		2,433		2,538

Compulsory inventories were primarily held by Italian subsidiaries (euro 2,418 million and euro 2,525 million at December 31, 2011 and 2012, respectively) in accordance with minimum stock requirements of oil, petroleum products and natural gas set forth by applicable laws. Compulsory stock of natural gas went to zero at period-end as a consequence of the deconsolidation of Snam.

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16 Intangible assets

(euro million)

Net book amount at the beginning of the year

Additions

Amortization

Impairment losses

Changes in the scope of consolidation

Currency translation differences

Other changes

Net book amount at the end of the year

Gross book amount at the end of the year

Provisions for depreciation and impairments

December 31, 2011
Intangible assets with finite useful lives
Exploration expenditures		538		1,245		(1,244	)								17			8			564		2,634		2,070
Industrial patents and intellectual property rights		150		37		(85	)		(2	)					(1	)		57			156		1,474		1,318
Concessions, licenses, trademarks and similar items		575		10		(159	)											421			847		2,827		1,980
Service concession arrangements		3,562		308		(142	)								(13	)		(25	)		3,690		6,361		2,671
Intangible assets in progress and advances		658		171														(581	)		248		254		6
Other intangible assets		1,514		9		(128	)								7			20			1,422		2,074		652
		6,997		1,780		(1,758	)		(2	)					10			(100	)		6,927		15,624		8,697
Intangible assets with indefinite useful lives
Goodwill		4,175							(152	)					2			(2	)		4,023
		11,172		1,780		(1,758	)		(154	)					12			(102	)		10,950
December 31, 2012
Intangible assets with finite useful lives
Exploration expenditures		564		1,871		(1,886	)								(10	)		9			548		2,653		2,105
Industrial patents and intellectual property rights		156		59		(58	)		(1	)		(74	)		1			55			138		1,197		1,059
Concessions, licenses, trademarks and similar items		847		18		(134	)		(1	)		(46	)					(1	)		683		2,516		1,833
Service concession arrangements		3,690		170		(3	)		(37	)		(3,716	)		(2	)		(70	)		32		101		69
Intangible assets in progress and advances		248		159					(1	)		(57	)					(86	)		263		269		6
Other intangible assets		1,422		18		(127	)		(1,030	)		40			7			32			362		2,144		1,782
		6,927		2,295		(2,208	)		(1,070	)		(3,853	)		(4	)		(61	)		2,026		8,880		6,854
Intangible assets with indefinite useful lives
Goodwill		4,023							(1,347	)		(216	)		2			(1	)		2,461
		10,950		2,295		(2,208	)		(2,417	)		(4,069	)		(2	)		(62	)		4,487

Capitalized exploration expenditures at the end of the year of euro 548 million mainly related to the residual book value of license acquisition costs that are amortized on a straight-line basis over the contractual term of the exploration lease or fully written off against profit and loss upon expiration of terms or management’s decision to cease any exploration activities. Additions for the year of euro 1,871 million included exploration drilling expenditures which are fully capitalized to reflect their investment nature and then entirely amortized for euro 1,650 million (euro 973 million in 2011) and license acquisition costs of euro 221 million (euro 270 million in 2011) primarily related to the acquisition of new exploration acreage in Liberia, Indonesia and Kenya.

Concessions, licenses, trademarks and similar items for euro 683 million primarily comprised transmission rights for natural gas imported from Algeria (euro 614 million) and concessions for mineral exploration (euro 47 million).

Service concession arrangements of euro 32 million primarily pertained to foreign gas distribution activities (euro 3,690 million, of which euro 3,618 million in Italy at December 31, 2011). The decrease of euro 3,658 million was essentially a consequence of the deconsolidation of Snam (euro 3,716 million).

Other intangible assets with finite useful lives of euro 362 million decreased by euro 1,060 million due to impairment losses recorded at intangible assets in the Gas & Power segment. A loss of euro 774 million (euro 511 million net of tax effect) was recorded on the customer relationship which was recognized upon the business combination of Distrigas NV (now Eni Gas & Power NV) and then allocated to the European market CGU. The impairment review to test the recoverability of the book value of such CGU brought to a lower value-in-use which was partly attributed to said customer relationship. In particular, the driver of the impairments was affected by a continuing loss of customers in Benelux, primarily in the wholesaler segment, considering the reduced profitability outlook in the light of continuing demand weakness, rising competitive pressure and oversupplies, as described below in the commentary about the impairment loss attributed to the European market CGU. The residual book

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value of the customer relationship amounted to euro 168 million (euro 111 million net of taxes) at the balance sheet date and will continue being amortized in accordance to the supply contract having the longest term (19 years at inception). An impairment loss of euro 256 million was recorded to write off the book value of an option to develop an offshore storage facility for commercial modulation of gas in the British North Sea, which was recognized upon the acquisition of Eni Hewett Ltd, driven by continuing weakness in the European gas scenario.

Other intangible assets also comprised: (i) royalties for the use of licenses by Versalis SpA amounting to euro 56 million (euro 60 million at December 31, 2011); and (ii) estimated costs for Eni’s social responsibility projects in relation to oil development programs in Val d’Agri and in North Adriatic area connected to mineral rights under concession for euro 44 million (euro 50 million at December 31, 2011) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna.

The main amortization rates used were as follows:

(%)
Exploration expenditures					14		-	33
Industrial patents and intellectual property rights					20		-	33
Concessions, licenses, trademarks and similar items					3		-	33
Service concession arrangements					2		-	4
Other intangible assets					4		-	25

Impairment losses of intangible assets with indefinite useful life (goodwill) amounted to euro 1,347 million and pertained to the Gas & Power segment.

Changes in the scope of consolidation of intangible assets with indefinite useful life (goodwill) of euro 216 million comprised the deconsolidation of Snam Group following the loss of control (euro 314 million) and the inclusion of Nuon Belgium NV (now merged in Eni Gas & Power NV) and Nuon Power Generation Walloon NV (now Eni Power Generation NV) following the 100% acquisition (euro 98 million).

The carrying amount of goodwill at the end of the year was euro 2,461 million (euro 4,023 million at December 31, 2011) net of cumulative impairments amounting to euro 2,075 million (euro 726 million at December 31, 2011). The break-down of goodwill by operating segment is as follows:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Gas & Power		2,531		1,286
Engineering & Construction		749		750
Exploration & Production		270		265
Refining & Marketing		159		160
Other activities - Snam (a)		314
		4,023		2,461

(a)		Goodwill as of December 31, 2011, pertaining to the segment Other activities - Snam has been reclassified from the Gas & Power segment.

Goodwill acquired through business combinations has been allocated to the cash generating units ("CGUs") that are expected to benefit from the synergies of the acquisition. The CGUs of the Gas & Power segment are represented by such commercial business units whose cash flows are largely interdependent and therefore benefit from acquisition synergies. The recoverable amounts of the CGUs are determined by discounting the future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from their disposal at the end of the useful life. For the determination of the cash flows see note 14 – Property, plant and equipment.

Values-in-use are determined by discounting post-tax cash flows at a rate which corresponds: (i) in Exploration & Production, Refining & Marketing and Chemical segments to the Company’s weighted average cost of capital net of the risk factors attributable to Saipem and the Gas & Power segment which are assessed on a stand alone basis. Then the discount rates are adjusted to factor in risks specific to each Country of activity (adjusted post-tax WACC). In 2012, the adjusted post-tax rates used for assessing values-in-use marginally decreased from the previous year reflecting a reduction in the financial parameters used for assessing the cost of capital: cost of borrowings to Eni determined by expected trends for borrowing spreads and management’s estimates about the composition of the Company’s finance debt and reduced risk-free yields reflecting an expected decline in the risk premium of Italy.

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Those positive factors were partially absorbed by the increased weight of net equity in the determination of the cost of capital to the Group as the Board of Directors has reassessed the optimal mix between internally-generated funds versus third parties borrowings following the divestment of Snam. It is worth mentioning that the increased equity risk of the Eni share due to the divestment of a business with low volatility had no impact on the assessment of the cost of capital used for the impairment evaluations in the Exploration & Production, Refining & Marketing and Chemical segments. This conclusion is underpinned by the fact that in the past management adopted discount rates which excluded the mitigating effect of the lower volatility of Snam in the Eni’s portfolio. In 2012, the adjusted WACC used for impairment test purposes ranged from 7.2% to 13.0%; and (ii) the impairment test rate for the Gas & Power segment was estimated on the basis of a sample of comparable companies in the utility industry. The impairment test rate for the Engineering & Construction segment was derived from market data. Rates used in the Gas & Power segment were adjusted to take into consideration risks specific to each Country of activity, while rates used in the Engineering & Construction segment did not reflect any Country risks as most of the Company assets are not permanently located in a specific Country. Rates for the Gas & Power segment ranged from 6.9% to 8.5%, substantially unchanged from the previous year. In the Engineering & Construction segment, the discount rate was 7.8%, with a decrease of 0.7 percentage points from the previous year due to a lower equity risk.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

Goodwill has been allocated to the following CGUs:

Gas & Power segment

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Domestic gas market		767		767
Foreign gas market		1,763		519
- of which European market		1,668		511
Other		1
		2,531		1,286

Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of Italgas SpA minorities in 2003 through a public offering (euro 706 million). This CGU engages in supplying gas to residential customers and small businesses. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of that CGU, including the allocated goodwill.

Goodwill allocated to the CGU European Market was mainly recognized upon the purchase price allocations in the business combinations mainly of Distrigas NV (now Eni Gas & Power NV) in Belgium and other smaller entities (Altergaz SA, now Eni Gas & Power France SA in France) in previous years and, in January 2012, the 100% acquisition of Nuon Belgium NV (now merged in Eni Gas & Power NV) and Nuon Power Generation Walloon NV (now Eni Power Generation NV), companies marketing gas and electricity mainly to residential and professional customers in Belgium (euro 98 million). The CGU European Market comprises gas marketing activities managed by the companies acquired and gas marketing activities managed directly or indirectly by the Gas & Power Division of the parent company Eni SpA (North-West Europe area, France, Germany, Benelux, United Kingdom, Switzerland and Austria). Those business units jointly benefited from the business combination synergies. In performing the impairment review of the recoverability of the CGU carrying amount at the balance sheet date, management recognized an impairment loss amounting to euro 1,255 million considering a reduced profitability outlook and fundamental modifications pointing to a higher cyclicality of the gas business.

The key assumptions adopted in assessing future cash flow projections of both the CGUs Domestic Market and European Market included marketing margins, forecast sales volumes, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers was derived from the four-year plan approved by the Company’s top management which reduced with respect to past reviews the projected returns and cash flows particularly in the European Market, driven by expectations for continuing demand weakness on the back of the current economic downturn and rising competitive pressures. The European Market CGU is expected to be negatively affected by declining marketing margins due to continuing weak trends in spot prices of gas against which selling prices in the European markets are benchmarked, and the projections in 2013 of negative spreads towards the oil-linked costs of gas supplies. Other elements of risk are tied with ongoing development in pricing regulation in the retail segment across several European countries driven by growing pressure by administrative authorities. In the light of the expected trends in the gas market, management planned to renegotiate the economic terms and flexibility conditions at the Company’s main long-term supply contracts. The expected results of these

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renegotiations are factored in the economic and financial projections of the four-year plan adopted by the management for the gas business. For the European market CGU, management is now assuming in the updated plan with respect to the previous plan: (i) a reduction of 33% on average in unit marketing margins used to assess the European market CGU in the four-year period of the plan and a one-third reduction in unit marketing margins used in the perpetuity to assess the terminal value of the CGU on the basis of the business cyclicality; (ii) a decline of 3% in sales volumes over the plan period; (iii) a slightly lower discount rate; and (iv) to assess the terminal value, a growth rate for the long period of the perpetuity of the last-year equal to zero, unchanged from previous assumptions.

Value in use of the CGU European Market was assessed by discounting the associated post-tax cash flows at a post-tax rate of 7.3% corresponding to the pre-tax rate of 12.0% (7.5% and 9.3%, respectively in 2011). Value-in-use of the CGU Italian Market was assessed by discounting the associated post-tax cash flows at a post-tax rate of 6.9% corresponding to the pre-tax rate of 14.0% (7.0% and 13.1%, respectively in 2011).

The excess of the recoverable amount of the CGU domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to euro 549 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 32.3% on average in the projected commercial margins; (ii) a decrease of 32.3% on average in the projected sales volumes; (iii) an increase of 8.2 percentage points in the discount rate; and (iv) a negative nominal growth rate of 13.2%. The recoverable amount of the CGU and the relevant sensitivity analysis were calculated solely on the basis of retail margins, thus excluding wholesale and business client margins (industrial, thermoelectric and others).

Furthermore, Eni recorded impairments of the goodwill allocated to marginal activities of the gas segment (Tigáz in Hungary, Adriaplin in Slovenia and other subsidiaries in Argentina) as a consequence of the lack of profitability prospects in the relevant local markets due to tariff revisions and other factors (euro 44 million) and, as well, of the Hewett project in the North Sea due to the drivers described above (euro 48 million).

Engineering & Construction segment

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Offshore E&C		415		415
Onshore E&C		315		316
Other		19		19
		749		750

The segment goodwill of euro 750 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA (euro 710 million) and allocated to the CGUs Offshore E&C and Onshore E&C. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amounts of both those CGUs, including the allocated portions of goodwill.

The key assumptions adopted for assessing the recoverable amounts of those two CGUs which exceeded their respective carrying amounts related to operating results, the discount rate and the growth rates adopted to determine the terminal value. Information on those drivers were collected from the four-year-plan approved by the Company’s top management, while the terminal value was estimated by using a perpetual nominal growth rate of 2% applied to the cash flow of the last year in the four-year plan normalized. Value in use of both CGUs was assessed by discounting the associated post-tax cash flows at a post-tax rate of 7.8% (8.5% in 2011) which corresponds to the pre-tax rate of 9.9% and 10.7% for the Offshore E&C business unit and the Onshore E&C one, respectively (11.1% and 12.1%, respectively in 2011). The headroom of the Offshore E&C business unit of euro 3,224 million would be reduced to zero under each of the following alternative changes in the above mentioned assumptions: (i) a decrease of 44% in the operating result of the four-year plan; (ii) an increase of about 4 percentage points in the discount rate; and (iii) negative real growth rate. Changes in each of the assumptions that would cause the headroom of the Onshore E&C business unit to be reduced to zero are greater than those applicable to the Offshore E&C construction CGU described above.

The Exploration & Production and the Refining & Marketing segments tested their goodwill, yielding the following results: (i) in the Exploration & Production segment with goodwill amounting to euro 265 million, management believes that there are no reasonably possible changes in the pricing environment and production/cost profiles that would cause the headroom of the relevant CGUs to be reduced to zero. Goodwill mainly refers to the portion of the purchase price that was not allocated to proved or unproved properties in the business combinations Lasmo, Burren Energy (Congo) and First Calgary executed in previous reporting periods; and (ii) in the Refining

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& Marketing segment goodwill amounted to euro 160 million at the balance sheet date. Goodwill amounting to euro 141 million pertained to retail networks acquired in previous years in Austria, Czech Republic, Hungary and Slovakia for which profitability expectations have remained unchanged from the previous-year impairment review and marginal lines of business in Italy and Europe for euro 19 million.

17 Investments

Investments accounted for using the equity method

(euro million)

Book amount at the beginning of the year

Additions

Divestments and reimbursements

Share of profit of equity-accounted investments

Share of loss of equity-accounted investments

Deduction for dividends

Changes in the scope of consolidation

Currency translation differences

Other changes

Book amount at the end of the year

December 31, 2011
Investments in unconsolidated entities controlled by Eni		256			8			(19	)		35			(7	)		(39	)					4			(16	)		222
Joint ventures		2,735			93			(35	)		376			(68	)		(276	)					45			(268	)		2,602
Associates		2,677			134			(34	)		267			(31	)		(138	)					45			99			3,019
		5,668			235			(88	)		678			(106	)		(453	)					94			(185	)		5,843
December 31, 2012
Investments in unconsolidated entities controlled by Eni		222			6			(11	)		37			(4	)		(36	)		29			(2	)		(26	)		215
Joint ventures		2,602			185			(1	)		319			(78	)		(265	)		(473	)		(23	)		(19	)		2,247
Associates		3,019			139			(321	)		170			(151	)		(129	)		(48	)		(32	)		(844	)		1,803
		5,843			330			(333	)		526			(233	)		(430	)		(492	)		(57	)		(889	)		4,265

Additions of euro 330 million mainly related to a capital contribution made to Angola LNG Ltd (euro 108 million) which is currently engaged in building a liquefaction plant in order to monetize Eni’s gas reserves in that Country (Eni’s interest in the project being 13.6%). Other capital contributions related to the subscription of the new companies Gas Bridge 1 BV and Gas Bridge 2 BV by Snam SpA for a total amount of euro 133 million.

Divestments and reimbursements of euro 333 million related to the sale of 5% of the share capital of Galp Energia SGPS SA to Amorim Energia BV with a book value of euro 294 million. Further information about this transaction is disclosed in the commentary of other changes.

Eni’s share of profit of equity-accounted investments and dividend decrease pertained to the following entities:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Share of profit of equity-accounted investments

Deduction for dividends

Eni’s interest (%)

Share of profit of equity-accounted investments

Deduction for dividends

Eni’s interest (%)

Unión Fenosa Gas SA		152		148		50.00		149		108		50.00
Galp Energia SGPS SA (a)		144		39		33.34		80		55		24.34
United Gas Derivatives Co		49		44		33.33		68		60		33.33
Blue Stream Pipeline Co BV		34		9		50.00		39		44		50.00
Unimar Llc		32				50.00		38		78		50.00
Eni BTC Ltd		28		34		100.00		30		31		100.00
Supermetanol CA		17		25		34.51		18		15		34.51
Saipon Snc		31				60.00		10				60.00
PetroSucre SA		37				26.00		3				26.00
Azienda Energia e Servizi Torino SpA		23		26		49.00
Other investments		131		128				91		39
		678		453				526		430

(a)		The investment was accounted for under the equity method until the date of loss of significant influence.

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Eni’s share of losses of equity-accounted investments related to the following entities:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

		Share of loss of equity-accounted investments		Eni’s interest (%)		Share of loss of equity-accounted investments		Eni’s interest (%)

EnBW Eni Verwaltungsgesellschaft mbH		30		50.00		82		50.00
Zagoryanska Petroleum BV						50		60.00
Angola LNG Ltd						35		13.60
Distribuidora de Gas del Centro SA						12		31.35
Pokrovskoe Petroleum BV		9		30.00		8		30.00
Artic Russia BV		7		60.00		7		60.00
Enirepsa Gas Ltd		14		50.00		6		50.00
Inversora de Gas del Centro SA						5		25.00
PetroJunin SA						5		40.00
South Stream Transport BV						5		20.00
GreenStream BV		23		50.00		1		50.00
CARDÓN IV SA		12		50.00
Other investments		11				17
		106				233

Losses at equity-accounted investments were driven by: (i) a reduced profitability outlook at EnBW Eni Verwaltungsgesellschaft mbH which led to write down the expected synergies deriving from the business combination (euro 82 million); (ii) a downward reserve revision of a joint project in the Ukraine at Zagoryanska Petroleum BV (euro 50 million); (iii) non-capitalizable exploration and pre-production expenses at Angola LNG Ltd (euro 35 million); and (iv) reduced expectations for a tariff increase in local markets driving down future cash flows at Distribuidora de Gas del Centro SA (euro 12 million) and Inversora de Gas del Centro SA (euro 5 million).

Changes in the scope of consolidation of equity-accounted investments of euro 521 million related to deconsolidation of Snam.

Other changes of euro 889 million mainly related to the fact that the book value of Galp Energia SGPS SA amounting to euro 1,669 million was reclassified to other investments due to loss of significant influence on the investees as a consequence of the sale of 5% of the share capital of the entities to Amorim Energia BV, thus sanctioning Eni’s exit from the current shareholders’ agreement governing Galp. The transaction was executed on July 20, 2012 and involved the sale of 41.5 million shares of Galp at a price of euro 14.25 a share, for a total consideration of euro 582 million that correspond to a book value of euro 294 million. Eni’s interest in Galp Energia decreased to 28.34% and was stated as an available-for-sale financial asset. On the other hand, prior to the described transaction, Eni had recorded an increase in the book value of Galp amounting to euro 835 million driven by a capital increase made by Galp’s subsidiary Petrogal whereby a new shareholder subscribed for its share of the capital increase by contributing a cash amount which was fairly in excess of the net book value of the interest acquired.

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List of equity-accounted investments:

(euro million)	Dec. 31, 2011		Dec. 31, 2012

	Net carrying amount		Number of shares held		Eni’s interest (%)		Net carrying amount		Number of shares held		Eni’s interest (%)

Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd		100		34,000,000		100.00		97		34,000,000		100.00
Other investments (*)		122						118
		222						215
Joint ventures
Unión Fenosa Gas SA		465		273,100		50.00		507		273,100		50.00
Blue Stream Pipeline Co BV		476		1,000		50.00		461		1,000		50.00
Artic Russia BV		428		12,000		60.00		436		12,000		60.00
Raffineria di Milazzo ScpA		130		175,000		50.00		132		175,000		50.00
Eteria Parohis Aeriou Thessalonikis AE		130		116,546,500		49.00		131		116,546,500		49.00
GreenStream BV		128		100,000,000		50.00		125		100,000,000		50.00
CARDÓN IV SA		74		6,455		50.00		73		6,455		50.00
Unimar Llc		111		50		50.00		70		50		50.00
Supermetanol CA		59		49,000		34.51		62		49,000		34.51
Eteria Parohis Aeriou Thessalias AE		45		38,445,008		49.00		46		38,445,008		49.00
Petromar Lda		23		1		70.00		42		1		70.00
Est Reti Elettriche SpA (ex Est PiÓ SpA)		30		2,940,000		70.00		12		1,221,500		70.00
Saipon Snc		30		12,000		60.00		9		12,000		60.00
Azienda Energia e Servizi Torino SpA		169		54,150,000		49.00
Toscana Energia SpA		159		70,304,854		48.08
Zagoryanska Petroleum BV		32		10,800		60.00				10,800		60.00
Other investments (*)		113						141
		2,602						2,247
Associates
Angola LNG Ltd		1,008		1,141,284,004		13.60		1,060		1,279,887,652		13.60
PetroSucre SA		244		5,727,800		26.00		242		5,727,800		26.00
EnBW Eni Verwaltungsgesellschaft mbH		237		1		50.00		163		1		50.00
United Gas Derivatives Co		102		950,000		33.33		106		950,000		33.33
Fertilizantes Nitrogenados de Oriente CEC		68		1,933,662,121		20.00		68		1,933,662,121		20.00
Rosetti Marino SpA		25		800,000		20.00		29		800,000		20.00
Termica di Milazzo Srl		26		9,296,400		40.00		23		9,296,400		40.00
Distribuidora de Gas del Centro SA		31		50,303,329		31.35		14		50,303,329		31.35
Galp Energia SGPS SA		1,103		276,472,161		33.34
ACAM Gas SpA		48		3,336,410		49.00
Gaz de Bordeaux SAS		26		257,576		34.00
Other investments (*)		101						98
		3,019						1,803
		5,843						4,265

(*)		Each individual amount included herein was lower than euro 25 million.

Carrying amounts of investments in unconsolidated entities controlled by Eni, joint ventures and associates, included differences between the purchase price and the corresponding net equity amounting to euro 275 million, of which euro 195 million referred to Unión Fenosa Gas SA (goodwill) and euro 80 million to EnBW Eni Verwaltungsgesellschaft mbH (of which goodwill euro 16 million).

The table below sets out the provisions for losses included in the provisions for contingencies of euro 176 million (euro 151 million at December 31, 2011), primarily related to the following equity-accounted investments:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation)		100		102
Société Centrale Electrique du Congo SA				19
Southern Gas Constructors Ltd		11		10
Charville - Consultores e Serviços Lda		7		7
Other investments		33		38
		151		176

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Other investments

(euro million)

Net book amount at the beginning of the year

Additions

Divestments

Valuation at fair value

Currency translation differences

Other changes

Value at the end of the year

Gross book amount at the end of the year

Accumulated impairment charges

December 31, 2011
Investments in unconsolidated entities controlled by Eni		29			2									(1	)		(27	)		3			3
Associates		10												(10	)		13			13			21			8
Other investments		383			8									7			(15	)		383			390			7
		422			10									(4	)		(29	)		399			414			15
December 31, 2012
Investments in unconsolidated entities controlled by Eni		3			12															15			16			1
Associates		13						(13	)								12			12			12
Other investments		383			49			(503	)		2,528			(3	)		2,604			5,058			5,059			1
		399			61			(516	)		2,528			(3	)		2,616			5,085			5,087			2

Investments in unconsolidated entities controlled by Eni and associates are stated at cost net of impairment losses. Other investments, for which fair value cannot be reliably determined, were recognized at cost and adjusted for impairment losses.

Additions of euro 61 million mainly related to the acquisition of a 15% interest in the share capital of Novamont SpA for euro 35 million and of the 5.2% of the share capital of Genomatica Inc for euro 12 million and to a capital contribution made to Servizio Fondo Bombole Metano SpA for euro 12 million.

Divestments of euro 516 million related for euro 358 million to the sale through an accelerated book-building procedure with institutional investors of 4% of the share capital of Galp Energia SGPS SA for a total consideration of euro 381 million and a gain on divestment of euro 23 million (further information is disclosed in the next paragraph) and to the sale of Interconnector (UK) Ltd for euro 136 million.

Valuation at fair value of euro 2,528 million related to the initial recognition and subsequent measurement at market prices of the interests in Snam SpA (euro 1,465 million) and Galp Energia SGPS SA (euro 1,063 million) that, as a consequence of the loss of control on Snam following the transaction with Cassa Depositi e Prestiti (see note 31 – Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale) and the loss of significant influence on Galp following Eni’s exit from the shareholders’ pact, were stated as financial investment in the item "Other investments". The initial recognition corresponded to the market prices recorded on the date of sale of control/significant influence which occurred on October 15, 2012 and July 20, 2012, respectively. The difference between the initial measurement at market prices and the book value of the underlying interests was reported through profit. The subsequent changes in the market prices of the share from the initial recognition to the balance sheet date were reported in comprehensive income, with the exception of the shares underlying convertible bonds which changes in market prices were reported through profit as management elected to apply the fair value option provided by IAS 39 in order to eliminate an accounting mismatch deriving from the measurement at fair value through profit of the options embedded in the convertible bonds. More explicitly: (i) at the date of loss of control the residual interest in Snam amounted to 683.9 million of shares equal to 20.23% of the share capital which were initially recognized at a market fair value of euro 2,394 million, calculated at the price of euro 3.5 a share current at the date of loss of control which resulted in a revaluation gain of euro 1,451 million reported as discontinued operation. The fair value option was applied to 288.7 million shares underlying a convertible bond issued on January 15, 2013 which resulted in a fair value gain through the income statement of euro 6 million reported as continuing operation following the re-measurement at market fair value at the balance sheet date; positive changes in fair value of the residual interest in Snam of euro 8 million was recorded in other components of comprehensive income. At December 31, 2012, the residual interest in Snam, equal to 20.23% of the share capital, was stated at a fair value of euro 2,408 million at the current market price of euro 3.52 a share; and (ii) at the date of loss of Eni’s significant influence the residual interest in Galp amounted to 235 million of shares equal to 28.34% of the share capital which were initially recognized at a market fair value of euro 2,534 million, measured at the market price of euro 10.78 a share current at the date of loss of significance influence which brought to profit a revaluation gain of euro 865 million. On November 27, 2012, through an accelerated book-building procedure, Eni sold 33.2 million shares of Galp Energia, corresponding to 4% of its share capital at a price of euro 11.48 a share with a gain of euro 23 million. The fair value option was applied to 66.3 million shares, equal to the 8% of share capital of Galp, which were underlying a convertible bond issued at the same time as the 4% sale. At December 31, 2012, the residual interest in Galp of 201.84 million of shares equal to 24.34% of the share capital

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was stated at a market value of euro 2,374 million at the market price of euro 11.76 a share. The fair value option on part of the interest in Galp brought profit a gain of euro 65 million relating to the share underlying the convertible bond; a positive change in market value at the residual interest in Galp was brought to other components of comprehensive income (euro 133 million).

Other changes of euro 2,616 million related to the reclassification from investments accounted for using the equity method of Galp Energia SGPS SA for euro 1,669 million and the book value of Snam SpA before fair value valuation for euro 943 million.

The net carrying amount of other investments of euro 5,085 million (euro 399 million at December 31, 2011) was related to the following entities:

(euro million)	Dec. 31, 2011		Dec. 31, 2012

	Net carrying amount		Number of shares held		Eni’s interest (%)		Net carrying amount		Number of shares held		Eni’s interest (%)

Investments in unconsolidated entities controlled by Eni (*)		3						15
Associates		13						12
Other investments:
- Snam SpA								2,408		683,936,947		20.23
- Galp Energia SGPS SA								2,374		201,839,604		24.34
- Nigeria LNG Ltd		91		118,373		10.40		90		118,373		10.40
- Darwin LNG Pty Ltd		73		213,995,164		10.99		65		213,995,164		10.99
- Novamont SpA								35		3,530		15.00
- Interconnector (UK) Ltd		136		2,050,017		16.07
- other (*)		83						86
		383						5,058
		399						5,085

(*)		Each individual amount included herein was lower than euro 25 million.

Provisions for losses related to other investments, included within the provisions for contingencies, amounted to euro 18 million (euro 21 million at December 31, 2011) and were primarily in relation to the following entities:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Caspian Pipeline Consortium R - Closed Joint Stock Co		16		14
Other investments		5		4
		21		18

Other information about investments
The following table summarizes key financial data, net to Eni, as disclosed in the latest available financial statements of unconsolidated entities controlled by Eni, joint ventures and associates:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Unconsolidated entities controlled by Eni

Joint ventures

Associates

Unconsolidated entities controlled by Eni

Joint ventures

Associates

Total assets		2,393			5,655		6,165		1,604		5,032		3,223
Total liabilities		2,279			3,085		3,144		1,497		2,827		1,429
Net sales from operations		86			3,011		6,347		97		2,971		1,889
Operating profit		(2	)		484		316		5		475		259
Net profit		41			299		234		39		237		170

Total assets and liabilities of unconsolidated controlled entities of euro 1,604 million and euro 1,497 million, respectively (euro 2,393 million and euro 2,279 million at December 31, 2011) pertained to entities acting as sole operator in the management of oil and gas contracts for euro 1,249 million and euro 1,249 million (euro 2,027

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million and euro 2,027 million at December 31, 2011). The residual amount pertained to not significant entities that were excluded from the scope of consolidation for the reasons described in note 1 – Basis of presentation.

18 Other financial assets

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Receivables for financing operating activities		1,516		1,160
Securities held for operating purposes		62		69
		1,578		1,229

Receivables for financing operating activities are stated net of the valuation allowance for doubtful accounts of euro 30 million (euro 32 million at December 31, 2011).

Operating financing receivables of euro 1,160 million (euro 1,516 million at December 31, 2011) primarily pertained to loans granted by the Exploration & Production segment (euro 567 million), the Gas & Power segment (euro 429 million) and the Refining & Marketing segment (euro 98 million) and receivables for financial leasing for euro 21 million (euro 47 million at December 31, 2011). Financing receivables granted to unconsolidated subsidiaries, joint ventures and associates amounted to euro 642 million.

Receivables for financial leasing pertained to the disposal of the Belgian gas network by Finpipe GIE.

The following table shows principal receivable by maturity date, which was obtained by summing future lease payment receivables discounted at the effective interest rate, interest and the nominal value of future lease receivables:

(euro million)		Maturity range

		Within 12 months		Between one and five years		Total

Principal receivable		26		21		47
Interests				3		3
Undiscounted value of future lease payments		26		24		50

Receivables with a maturity date within one year is disclosed among current assets in the item trade receivables for operating purposes - current portion of long-term receivables in note 9 – Trade and other receivables.

Receivables for financing operating activities in currencies other than euro amounted to euro 999 million (euro 1,338 million at December 31, 2011).

Receivables for financing operating activities due beyond five years amounted to euro 624 million (euro 896 million at December 31, 2011).

The valuation at fair value of financing receivables of euro 1,217 million has been determined based on the present value of expected future cash flows discounted at rates ranging from 0.4% to 3.3% (0.7% and 3.1% at December 31, 2011).

Securities of euro 69 million (euro 62 million at December 31, 2011), designated as held-to-maturity investments, are listed bonds issued by sovereign states (euro 65 million) and by the European Investment Bank (euro 4 million).

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The following table analyses securities per issuing entity:

Amortized cost (euro million)

Nominal value (euro million)

Fair value (euro million)

Nominal rate of return (%)

Maturity date

Rating - Moody’s

Rating - S&P

Sovereign states
Fixed rate bonds
Italy		20		21		21		from 3.75 to 4.75		from 2013 to 2021		Baa2		BBB+
Slovenia		9		9		9		from 3.42 to 4.88		from 2013 to 2014		Baa2		A-
Floating rate bonds
Italy		12		12		12				from 2014 to 2016		Baa2		BBB+
Belgium		7		7		7				2016		Aa3		AA
France		5		5		5				2014		Aa1		AA+
Spain		10		9		9				from 2014 to 2015		Baa3		BBB-
Slovakia		2		2		2				2015		A2		A
Total sovereign states		65		65		65
European Investment Bank		4		4		4				2018		Aaa		AAA
		69		69		69

Securities with a maturity beyond five years amounted to euro 12 million.

The valuation at fair value of financial securities has resulted in marginal effects. The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in note 42 – Transactions with related parties.

19 Deferred tax assets

Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for euro 3,630 million (euro 4,045 million at December 31, 2011).

(euro million)

Amount at Dec. 31, 2011

Additions

Deductions

Changes in the scope of consolidation

Currency translation differences

Other changes

Amount at Dec. 31, 2012

		5,514		1,642		(1,326)		(1,208)		(58)		349		4,913

The deductions of euro 1,326 million comprised a write down of euro 1,030 million that was recognized on deferred tax assets recorded by the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes. Management recorded a write down on those deferred tax assets to reflect a lower likelihood that those deferred tax assets can be recovered in future periods due to an expected reduction in taxable income generated in Italy, and as Eni has lost the availability of Snam taxable profit against which Italian tax assets can be utilized following the deconsolidation of Snam.

Deferred tax assets are described in note 29 – Deferred tax liabilities.

Income taxes are described in note 39 – Income tax expense.

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20 Other non-current receivables

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Tax receivables from:
- Italian tax authorities
. income tax		16		113
. interest on tax credits		66		62
		82		175
- foreign tax authorities		72		118
		154		293
Other receivables:
- related to divestments		535		752
- other non-current		258		361
		793		1,113
Fair value of non-hedging derivatives		714		429
Fair value of cash flow hedge derivative instruments		33		2
Other asset		2,531		2,563
		4,225		4,400

The increase in income tax receivables from Italian tax authorities of euro 97 million related to Eni SpA for euro 85 million and comprised the tax relief provided for by Article 2, paragraph 1, of the Law Decree No. 201/2011 that allow to refund of tax payments of Ires made in excess in fiscal years prior to 2012 as a consequence of the non-deductibility of payroll costs relating to Irap.

Receivables originated from divestments amounted to euro 752 million (euro 535 million at December 31, 2011) and comprised: (i) the residual outstanding amount of euro 236 million recognized following the compensation agreed with the Republic of Venezuela for the expropriated Dación oilfield in 2006. The receivable accrues interests at market conditions as the collection has been fractionated in installments. As agreed by the parties, the reimbursement can be made in kind through equivalent assignment of volumes of crude oil. In 2012, the reimbursement amounted to euro 71 million ($92 million). Negotiations for further compensations are ongoing; (ii) the long-term portion of a receivable of euro 229 million related to the divestment of the 1.71% interest in the Kashagan project to the local partner KazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea SpA and the Kashagan government, which became effective from January 1, 2008. The reimbursement of the receivable is provided for in three annual installments commencing from the date of the production start-up which is planned within June 2013. The receivable accrues interest income at market rates. The short-term portion is disclosed in note 9 – Trade and other receivables; and (iii) the long-term portion of a receivable of euro 130 million related to the divestment of the 3.25% interest in the Karachaganak project (equal to the Eni’s 10% interest) to the Kazakh partner KazMunaiGas as part of an agreement reached in December 2011 between the Contracting Companies of the Final Production Sharing Agreement (FPSA) and Kazakh Authorities which settled disputes on the recovery of the costs incurred by the International Consortium to develop the field, as well as a certain tax claims. The agreement, effective from June 28, 2012, entailed a net cash consideration to Eni, to be paid in cash in three years through monthly installments starting from July 2012. The receivable accrues interest income at market rates. In the second half of 2012, reimbursements amounted to euro 41 million. The short-term portion is disclosed in note 9 – Trade and other receivables.

Receivables with related parties are described in note 42 – Transactions with related parties.

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The fair value of non-hedging derivative contracts was as follows:

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Derivatives on exchange rate
Interest currency swap		277		948		219		235		868		284
Currency swap		16		197				29		714		645
		293		1,145		219		264		1,582		929
Derivatives on interest rate
Interest rate swap		82		713		300		80		736		2
		82		713		300		80		736		2
Derivatives on commodities
Over the counter		326		3,010		922		80		581		547
Future		2		120				5		147		4
Other		11				116
		339		3,130		1,038		85		728		551
		714		4,988		1,557		429		3,046		1,482

Derivative fair values are calculated basing on market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques generally adopted in the marketplace.

Fair values of non-hedging derivatives of euro 429 million (euro 714 million at December 31, 2011) consisted of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not related to specific trade or financing transactions.

Fair value of cash flow hedge derivatives of euro 2 million (euro 33 million at December 31, 2011) related to the Gas & Power segment. Further information is disclosed in note 13 – Other current assets. Fair value related to the contracts expiring beyond 2013 is disclosed in note 30 – Other non-current liabilities; fair value related to the contracts expiring in 2013 is disclosed in note 13 – Other current assets and in note 25 – Other current liabilities. The effects of fair value evaluation of cash flow hedges are disclosed in note 32 – Shareholders’ equity and note 36 – Operating expenses.

The nominal values of cash flow hedge derivatives for purchase and sale commitments were euro 21 million and euro 60 million, respectively (euro 204 million and euro 379 million at December 31, 2011, respectively).

Information on the hedged risks and the hedging policies is disclosed in note 34 – Guarantees, commitments and risks - Risk factors.

Other non-current asset amounted to euro 2,563 million (euro 2,531 million at December 31, 2011), of which euro 2,367 million (euro 2,227 million at December 31, 2011) were deferred costs relating to gas quantities which, although not off-taken, the Company has obligation to prepay by disbursing the whole contractual price of a fraction of it in order to fulfill the take-or-pay clauses provided by the relevant long-term supply contracts (see "Other payables" of note 22 – Trade and other payables). In accordance to those arrangements, the Company is contractually required to off-take minimum annual quantities of gas, or in case of failure is held to pay the whole price or a fraction of it for the uncollected volumes up to the minimum annual quantity. The Company is entitled to off-take the pre-paid volumes in future years alongside the contract execution, for its entire duration or a shorter term as the case may be. Those prepayments were classified as non-current assets, as the Company plans to off-take the prepaid quantities beyond the term of 12 months. The increase of euro 140 million from December 31, 2011 was due to the gas volumes for which the take-or-pay obligation has been triggered in 2012; such increase was partially offset by the renegotiation of certain contracts which were finalized in 2012 with effects retroactive to the beginning of 2011 and provided for a reduction in the contractual minimum take. Those deferred costs, which are equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-years impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. The amount of pre-paid volumes reflects ongoing weak market conditions in the European gas sector due to declining demand and strong competitive pressures fuelled by oversupplies. Those trends prevented Eni from fulfilling its minimum take obligations associated with its gas supply contracts. Management plans to recover those pre-paid volumes over the long-term leveraging on: (i) the expected developing trends in long-term gas demand; (ii) a projected sales expansion in target European markets and Italy supported by the Company’s strengthening market leadership and an improved competitiveness of the Company’s cost position

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considering the expected benefits of ongoing and planned contract renegotiations; and (iii) the expected benefits associated with the reduction of minimum take quantities in future years and other operating flexibilities (i.e. changes in delivery points and LNG supplies in place of those by pipeline) which the Company has already achieved or plans to achieve as a result of ongoing and planned contract renegotiations, including the no renewal of expiring contracts.

Current liabilities

21 Short-term debt

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Banks		786		253
Commercial papers		2,997		1,481
Other financial institutions		676		489
		4,459		2,223

The decrease in short-term debt of euro 2,236 million included net repayments for euro 753 million and the deconsolidation of the financial debts pertaining to Snam (more information is provided in note 26 – Long-term debt and current maturities of long-term debt – Information on net borrowings). Commercial papers of euro 1,481 million (euro 2,997 million at December 31, 2011) were issued by the Group’s financial subsidiaries Eni Finance USA Inc (euro 1,357 million) and Eni Finance International SA (euro 124 million).

The break-down by currency of short-term debt is provided below:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Euro		2,896		219
U.S. dollar		1,430		1,815
Other currencies		133		189
		4,459		2,223

In 2012, the weighted average interest rate on short-term debt was 1.5% (1.1% in 2011).

At December 31, 2012, Eni had undrawn committed and uncommitted borrowing facilities amounting to euro 1,241 million and euro 10,932 million, respectively (euro 2,551 million and euro 9,346 million at December 31, 2011). Those facilities bore interest rates reflecting prevailing conditions on the marketplace. Charges for unutilized facilities were immaterial.

Payables due to related parties are described in note 42 – Transactions with related parties.

At December 31, 2012, Eni did not report any default on covenants or other contractual provisions in relation to borrowing facilities.

The fair value of short-term debts matched their respective carrying amounts considering the short-term maturity.

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22 Trade and other payables

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Trade payables		13,436		14,993
Advances		2,313		2,247
Other payables:
- related to capital expenditures		2,280		2,103
- others		4,883		4,238
		7,163		6,341
		22,912		23,581

Increased trade receivables amounting to euro 1,557 million primarily related to the Gas & Power segment (euro 1,252 million), Exploration & Production (euro 374 million), Refining & Marketing (euro 306 million) and, as decrease, to the change in the scope of consolidation following the deconsolidation of Snam (euro 446 million).

Advances of euro 2,247 million (euro 2,313 million at December 31, 2011) related to prepayments and advances on contract work in progress for euro 865 million and for euro 814 million, respectively (euro 795 million and euro 1,037 million at December 31, 2011, respectively) and other advances for euro 568 million (euro 481 million at December 31, 2011). Advances on contract work in progress were in respect of the Engineering & Construction segment.

Other payables were as follows:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Payables related to capital expenditures due to
Suppliers in relation to investing activities		1,544		1,626
Joint venture operators in exploration and production activities		468		440
Other		268		37
		2,280		2,103
Other payables due to
Joint venture operators in exploration and production activities		2,356		2,375
Employees		589		372
Social security entities		269		223
Non-financial government entities		137		243
Other		1,532		1,025
		4,883		4,238
		7,163		6,341

Other payables decreased of euro 822 million following the deconsolidation of Snam (euro 638 million).

Other payables due to others of euro 1,025 million (euro 1,532 million at December 31, 2011) included payables due to gas suppliers for euro 542 million (euro 719 million at December 31, 2011) relating to the triggering of the take-or-pay clause, net of the amounts paid by Eni for the year. Payments to gas suppliers decreased by euro 177 million reflecting the economic benefits associated with the renegotiations of certain take-or-pay contracts which were finalized in 2012 which effects were retroactive to the beginning of 2011 and provided for a reduction in the contractual minimum take. The decrease was partially offset by increased receivables due to the take-or-pay volumes accrued in 2012, net of amounts paid in the course of the year. For further information see note 20 – Other non-current receivables.

Payables to related parties are described in note 42 – Transactions with related parties.

The fair value of trade and other payables matched their respective carrying amounts considering the short-term maturity of trade payables.

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23 Income taxes payable

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Italian subsidiaries		390		156
Foreign subsidiaries		1,702		1,466
		2,092		1,622

Income taxes are described in note 39 – Income tax expense.

24 Other taxes payable

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Excise and customs duties		1,049		1,286
Other taxes and duties		847		876
		1,896		2,162

25 Other current liabilities

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Fair value of non-hedging and trading derivatives		1,668		888
Fair value of cash flow hedge derivatives		121		32
Fair value of fair value hedge derivatives				5
Other liabilities		448		512
		2,237		1,437

The fair value of non-hedging derivative contracts and derivatives contracts held for trading is presented below:

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Derivatives on exchange rate
Currency swap		448		3,979		8,076		180		7,531		1,291
Interest currency swap		6		116
Other		1				23		1		102
		455		4,095		8,099		181		7,633		1,291
Derivatives on interest rate
Interest rate swap		3				735		1				88
		3				735		1				88
Derivatives on commodities
Over the counter		1,066		3,829		4,620		684		8,311		2,969
Future		63		418		173		11		382		43
Other		81				548		11				2
		1,210		4,247		5,341		706		8,693		3,014
		1,668		8,342		14,175		888		16,326		4,393

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques commonly used on the marketplace.

Fair values of non-hedging and trading derivatives of euro 888 million (euro 1,668 million at December 31, 2011) consisted of: (i) euro 538 million (euro 1,587 million at December 31, 2011) of derivatives that did not meet

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the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to movements in foreign currencies, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; (ii) euro 349 million (euro 80 million at December 31, 2011), of commodity and trading derivatives entered by the Gas & Power segment in order to optimize the economic margin and by Eni Trading & Shipping SpA for trading purposes; and (iii) euro 1 million (same amount as of December 31, 2011), of derivatives embedded in the pricing formulas of certain long-term supply contracts of gas in the Exploration & Production segment.

The fair value of cash flow hedge derivatives amounted to euro 32 million (euro 121 million at December 31, 2011) and essentially pertained to the Gas & Power segment. Those derivatives were designated to hedge exchange rate and commodity risk exposures as described in note 13 – Other current assets. Fair value of contracts expiring by end of 2013 is disclosed in note 13 – Other current assets; fair value of contracts expiring beyond 2013 is disclosed in note 30 – Other non-current liabilities and in note 20 – Other non-current receivables. The effects of the evaluation at fair value of cash flow hedge derivatives are disclosed in note 32 – Shareholders’ equity and in note 36 – Operating expenses.

The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for euro 341 million and euro 271 million, respectively (euro 3,409 million and euro 452 million at December 31, 2011, respectively).

The fair value of fair value hedge derivatives amounted to euro 5 million and pertained to derivatives entered into during the 2012 in order to hedge certain contracts for the sale and purchase of oil products.

The nominal value of fair value hedge derivatives referred to purchase and sale commitments for euro 24 million while sale commitments were not recorded.

Information on hedged risks and hedging policies is disclosed in note 34 – Guarantees, commitments and risks - Risk factors.

Other current liabilities of euro 512 million (euro 448 million at December 31, 2011) included advances cashed in from gas customers (euro 142 million) who off-took lower volumes than the contractual minimum take provided by the relevant long-term supply contract with the Company. The classification reflects the Company’s belief that the underlying volumes will be off-taken the next year.

Non-current liabilities

26 Long-term debt and current maturities of long-term debt

		Maturity range		2011		2012		Current maturity 2013		2014		2015		2016		2017		After		Total

Banks		2013-2027		9,654		4,016		913		694		621		622		227		939		3,103
Ordinary bonds		2013-2040		15,049		16,824		2,006		1,331		2,222		1,494		2,650		7,121		14,818
Convertible bonds		2015				990						990								990
Other financial institutions		2013-2025		435		410		42		53		47		50		50		168		368
				25,138		22,240		2,961		2,078		3,880		2,166		2,927		8,228		19,279

The decrease in long-term debt, including the current portion of long-term debt, of euro 2,898 million included new issuances for euro 10,484 million and repayments for euro 3,784 million and the deconsolidation of Snam as described in the following paragraph "Information on net borrowings".

Debt due to banks of euro 4,016 million (euro 9,654 million at December 31, 2011) included amounts against committed borrowing facilities for euro 5 million.

Debt due to other financial institutions of euro 410 million (euro 435 million at December 31, 2011) comprised euro 31 million of finance lease transactions (euro 15 million at December 31, 2011).

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Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the maintenance of certain financial ratios based on Eni’s Consolidated Financial Statements or a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees would be required to be agreed upon with the European Investment Bank. In addition, Eni entered into long and medium term facilities with Citibank Europe Plc providing for conditions similar to those applied by the European Investment Bank. At December 31, 2012 and 2011, debts subjected to restrictive covenants amounted to euro 1,994 million and euro 2,316 million, respectively. A possible non-compliance with those covenants would be immaterial to the Company’s ability to finance its operations. As of the balance sheet date, Eni was in compliance with those covenants.

Bonds of euro 16,824 million (euro 15,049 million at December 31, 2011) consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 12,579 million and other bonds for a total of euro 4,245 million.

The following table provides a break-down of bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2012:

Amount

Discount on bond issue and accrued expense

Total

Currency

Maturity

% rate

(euro million)

from

to

from

to

Issuing entity
Euro Medium Term Notes:
- Eni SpA		1,500		63			1,563		EUR				2016				5.000
- Eni SpA		1,500		46			1,546		EUR				2013				4.625
- Eni SpA		1,500		10			1,510		EUR				2019				4.125
- Eni SpA		1,250		69			1,319		EUR				2014				5.875
- Eni SpA		1,250					1,250		EUR				2017				4.750
- Eni SpA		1,000		33			1,033		EUR				2020				4.250
- Eni SpA		1,000		28			1,028		EUR				2018				3.500
- Eni SpA		1,000		18			1,018		EUR				2020				4.000
- Eni SpA		750		10			760		EUR				2019				3.750
- Eni Finance International SA		551		12			563		GBP		2018		2021		4.750		6.125
- Eni Finance International SA		370		9			379		EUR		2017		2032		3.750		5.600
- Eni Finance International SA		361		2			363		YEN		2013		2037		1.150		2.810
- Eni Finance International SA		193		4			197		USD		2013		2015		4.450		4.800
- Eni Finance International SA		34					34		USD				2013				variable
- Eni Finance International SA		16					16		EUR				2015				variable
		12,275		304			12,579
Other bonds:
- Eni SpA		1,109		(2	)		1,107		EUR				2017				4.875
- Eni SpA		1,000		13			1,013		EUR				2015				4.000
- Eni SpA		1,000		3			1,003		EUR				2015				variable
- Eni SpA		341		2			343		USD				2020				4.150
- Eni SpA		265					265		USD				2040				5.700
- Eni SpA		215		(1	)		214		EUR				2017				variable
- Eni USA Inc		303		(3	)		300		USD				2027				7.300
		4,233		12			4,245
		16,508		316			16,824

As of December 31, 2012, ordinary bonds maturing within 18 months (euro 3,051 million) were issued by Eni SpA (euro 2,865 million), Eni Finance International SA (euro 186 million). During 2012, new bonds of euro 1,864 million were issued by Eni SpA and Eni Finance International SA (euro 1,793 million and euro 71 million, respectively).

Convertible bonds of euro 990 million comprised unsecured bonds exchangeable into ordinary Galp Energia SGPS SA shares for euro 1,028 million. The bonds have maturity of 3 years and pay a coupon of 0.25 per cent per annum. Underlying the exchangeable bonds are approximately 66.3 million ordinary shares of Galp, corresponding to approximately 8% of the current outstanding share capital of Galp. The bonds will be exchangeable into Galp ordinary shares at a strike price of approximately euro 15.50 a share, representing a 35% premium to market prices current at the date of the issuance. The bonds are stated at amortized cost, while the call option embedded in the bonds is measured at fair value through profit. Changes in fair value of the shares underlying the bonds were reported through profit as opposed to equity based on the fair value option provided by IAS 39 from inception (for more information see note 17 – Investments).

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The following table provides a break-down by currency of long-term debt and its current portion and the related weighted average interest rates.

		Dec. 31, 2011 (euro million)		Average rate (%)		Dec. 31, 2012 (euro million)		Average rate (%)

Euro		22,196		3.2		19,413		3.6
U.S. dollar		1,926		5.0		1,899		5.3
British pound		551		5.3		564		5.3
Japanese yen		462		2.0		363		2.1
Other currencies		3		6.3		1		6.7
		25,138				22,240

As of December 31, 2012, Eni had undrawn long-term committed borrowing facilities of euro 6,928 million (euro 3,201 million at December 31, 2011). Those facilities bore interest rates and charges for unutilized facilities reflecting prevailing conditions on the marketplace.

Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 12.3 billion were drawn as of December 31, 2012. The Group has credit ratings of A and A-1, respectively for long and short-term debt assigned by Standard & Poor’s and A3 and P-2 for long and short-term debt assigned by Moody’s; the outlook is negative in both ratings.

Fair value of long-term debt, including the current portion of long-term debt amounted to euro 24,937 million (euro 27,103 million at December 31, 2011):

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Ordinary bonds		16,895		19,239
Banks		9,727		4,171
Convertible bonds				1,059
Other financial institutions		481		468
		27,103		24,937

Fair value was calculated by discounting the expected future cash flows at discount rates ranging from 0.4% to 3.3% (0.7% and 3.1% at December 31, 2011). The fair value of convertible bonds was determined on the basis of the market quotation.

At December 31, 2012, Eni did not pledge restricted deposits as collateral against its borrowings.

Information on net borrowings
In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS as endorsed by IASB less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

Management believes that net borrowings is an useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

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(euro million)		Dec. 31, 2011		Dec. 31, 2012

Current

Non-current

Total

Current

Non-current

Total

A.	Cash and cash equivalents		1,500				1,500		7,765				7,765
B.	Available-for-sale securities		37				37		34				34
C.	Liquidity (A+B)		1,537				1,537		7,799				7,799
D.	Financing receivables		28				28		1,153				1,153
E.	Short-term debt towards banks		786				786		253				253
F.	Long-term debt towards banks		1,601		8,053		9,654		913		3,103		4,016
G.	Bonds		397		14,652		15,049		2,006		15,808		17,814
H.	Short-term debt towards related parties		503				503		403				403
I.	Other short-term debt		3,170				3,170		1,567				1,567
L.	Other long-term debt		38		397		435		42		368		410
M.	Total borrowings (E+F+G+H+I+L)		6,495		23,102		29,597		5,184		19,279		24,463
N.	Net borrowings (M-C-D)		4,930		23,102		28,032		(3,768)		19,279		15,511

The decrease in consolidated net borrowings of euro 12,521 million comprised the effects of the deconsolidation of the finance debt held by Snam amounting to euro 12,448 million, following Eni’s loss of control on the investee. Snam arranged financing with third-party lenders in order to reimburse intercompany loans.

Available-for-sale securities of euro 34 million (euro 37 million at December 31, 2011) were held for non-operating purposes. The Company held at the reporting date certain held-to-maturity and available-for-sale securities which were destined to operating purposes amounting to euro 270 million (euro 287 million at December 31, 2011), of which euro 196 million (euro 220 million at December 31, 2011) were held to hedge the loss reserve of Eni Insurance Ltd. Those securities are excluded from the calculation above.

Financing receivables of euro 1,153 million (euro 28 million at December 31, 2011) were held for non-operating purposes and comprised euro 883 million of Cassa Depositi e Prestiti SpA of which euro 879 million relating to the residual amount of the total consideration (euro 3,517 million) for the transaction covering 1,013.6 million ordinary shares of Snam and euro 4 million of relevant accrued interests. The Company held at the reporting date certain financing receivables which were destined for operating purposes amounting to euro 668 million (euro 630 million at December 31, 2011), of which euro 351 million (euro 345 million at December 31, 2011) were in respect of financing granted to unconsolidated entities which executed capital projects and investments on behalf of Eni’s Group companies and a euro 280 million cash deposit (euro 250 million at December 31, 2011) to hedge the loss reserve of Eni Insurance Ltd. Those financing receivables are excluded from the calculation above.

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27 Provisions for contingencies

(euro million)

Carrying amount at Dec. 31, 2011

New or increased provisions

Initial recognition and changes in estimates

Accretion discount

Reversal of utilized provisions

Reversal of unutilized provisions

Currency translation differences

Changes in the scope of consolidation

Other changes

Carrying amount at Dec. 31, 2012

Provision for site restoration, abandonment and social projects		6,780						1,451			263			(300	)		(4	)		(14	)		(378	)		(391	)		7,407
Provision for environmental risks		3,084			91						22			(195	)		(24	)					(140	)		90			2,928
Provision for legal and other proceedings		1,074			669									(247	)		(173	)		(1	)		(72	)		(9	)		1,241
Provision for taxes		344			91									(33	)					(5	)					(2	)		395
Loss adjustments and actuarial provisions for Eni’s insurance companies		343			136									(142	)											6			343
Provision for redundancy incentives		163			24						22			(5	)		(1	)								(1	)		202
Provision for losses on investments		172			30												(18	)		(1	)					11			194
Provision for sale price revisions		22			195									(29	)		(3	)		(1	)					(6	)		178
Provision for OIL insurance cover		98			10												(1	)					(1	)					106
Provision for onerous contracts		125			1									(71	)											(1	)		54
Provision for long-term construction contracts		60			27									(33	)		(2	)											52
Provision for the supply of goods		28			24									(27	)		(1	)											24
Provision for coverage of unaccounted-for gas		54																					(54	)
Other (*)		388			256						1			(117	)		(28	)		(1	)		(28	)		8			479
		12,735			1,554			1,451			308			(1,199	)		(255	)		(23	)		(673	)		(295	)		13,603

(*)		Each individual amount included herein was lower than euro 50 million.

Provisions for site restoration, abandonment and social projects amounted to euro 7,407 million. Those provisions comprised the discounted estimated costs that the Company expects to incur for decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration (euro 7,026 million). Initial recognition and changes in estimates amounted to euro 1,451 million and were primarily due to estimates revisions of decommissioning costs in the Exploration & Production segment for euro 1,381 million and costs associated with certain social projects agreed with the Basilicata Italian region as part of the oil development plans in that region for euro 3 million. Changes in the scope of consolidation of euro 378 million related to the deconsolidation of Snam. Other changes of euro 391 million comprised the reclassification to liabilities directly associated with assets held for sale of provisions for decommissioning relating to Exploration & Production assets (euro 361 million). An amount of euro 263 million was recognized through profit and loss as unwinding of discount of the year. The discount rates adopted ranged from 0.7% to 9.4% (from 1.4% to 9.3% at December 31, 2011). Main expenditures associated with site restoration and decommissioning operations are expected to be incurred over a 30-year period starting from 2017.

Provisions for environmental risks amounted to euro 2,928 million. Those provisions comprised the estimated costs for environmental clean-up and restoration of certain industrial sites which were owned or held in concession by the Company, and subsequently divested, shut-down or liquidated. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to perform certain cleaning-up and restoration projects and reliable cost estimation is available. At December 31, 2012, provisions for environmental risks primarily related to Syndial SpA (euro 2,423 million) and the Refining & Marketing segment (euro 373 million). Additions of euro 91 million primarily related to Syndial SpA (euro 41 million) and the Refining & Marketing segment (euro 38 million). Reversal of utilized provisions of euro 195 million primarily related to Syndial SpA (euro 109 million) and the Refining & Marketing segment (euro 67 million). Changes in the scope of consolidation of euro 140 million related to the deconsolidation of Snam. Other changes of euro 90 million comprised the economic effects relating to discontinued operations (euro 69 million).

Provisions for legal and other proceedings of euro 1,241 million comprised the expected liabilities due to failure to perform certain contractual obligations and estimated future losses on pending litigation including legal,

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antitrust, administrative matters and arbitration proceedings. These provisions represented the Company’s best estimate of the expected probable liabilities associated with pending litigation and primarily related to the Gas & Power segment (euro 661 million) and Syndial SpA (euro 294 million). Additions and reversal of utilized provisions of euro 669 million and euro 247 million, respectively, mainly related to the Gas & Power segment and were recognized to take account of gas price revisions at both purchase and sale contracts, also including the settlement of few arbitrations. Reversals of unutilized provision of euro 173 million were primarily made by the Gas & Power segment due to lower than anticipated charges for price revisions at certain long-term gas purchase contracts. Changes in the scope of consolidation of euro 72 million related to the deconsolidation of Snam.

Provisions for taxes of euro 395 million included the estimated charges that the Company expects to incur for unsettled tax claims in connection with uncertainties in the application of tax rules at certain Italian and foreign subsidiaries in the Exploration & Production segment (euro 322 million) and the Engineering & Construction segment (euro 44 million).

Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance Ltd of euro 343 million represented the expected liabilities accrued on the basis for third parties claims. Against such liability was recorded a receivable of euro 124 million recognized towards insurance companies for reinsurance contracts.

Provisions for redundancy incentives of euro 202 million were recognized due to a restructuring program involving the Italian personnel for the period 2010-2011 in compliance with Law No. 223/1991 and further provisions provided for by Law No. 228/2012 which provided a scheme for early retirement.

Provisions for losses on investments of euro 194 million were made with respect to certain investees for which expected or incurred losses exceeded carrying amounts.

Provisions for the OIL mutual insurance scheme of euro 106 million included the estimated future increase of insurance charges, as a result of accidents that occurred in past periods that will be recognized to the mutual insures over the next 5 years by Eni.

Provisions for onerous contracts of euro 54 million related to the execution of contracts where the expected costs exceed the relevant benefits. In particular, the provision comprised the estimated expected losses on a re-gasification project in the United States.

Provisions for long-term construction contracts of euro 52 million related to the Engineering & Construction segment.

Provisions for the supply of goods in the amount of euro 24 million included the estimated costs of supply contract revisions made by Eni SpA.

28 Provisions for employee benefits

(euro million)		Dec. 31, 2011		Dec. 31, 2012

TFR		394		294
Foreign pension plans		334		400
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans		104		99
Other benefits		207		189
		1,039		982

Provisions for benefits upon termination of employment primarily related to a provisions accrued by Italian companies for employee retirement, determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code. The benefit is paid upon retirement as a lump sum, the amount of which corresponds to the total of the provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in the law regime, from January 1, 2007 accruing benefits have been contributing to a pension fund or a treasury fund held by the Italian administration for post-retirement benefits (Inps). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, contributions of future TFR provisions to pension funds or the Inps treasury fund determines that these amounts will be treated in

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accordance to a defined contribution scheme. Amounts already accrued before January 1, 2007 continue to be accounted for as defined benefits to be assessed based on actuarial assumptions.

Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement.

Group companies provide healthcare benefits to retired managers. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company.

Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers both of which normally vest over a three-year period upon fulfillment of certain performance conditions. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses which will be granted to those managers who will achieve certain individual performance goals weighted with the likelihood that the Company delivers the planned profitability targets upon the same period. Provisions for the long-term incentive scheme are assessed on the basis of the estimated trends of a performance indicator as benchmarked against a group of international oil companies. Jubilee awards are benefits due following the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration.

Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

	Foreign pension plans

(euro million)

TFR

Gross liability

Plan assets

FISDE and other foreign medical plans

Other benefits

Total

2011
Present value of benefit liabilities and plan assets at beginning of year		433			1,109			(468	)		120			206			1,400
Current cost					41						2			53			96
Interest cost		20			39						6			4			69
Amendments					6												6
Expected return on plan assets								(17	)								(17	)
Employee contributions								(36	)								(36	)
Actuarial gains/losses		(13	)		(24	)		(7	)		3						(41	)
Benefits paid		(50	)		(26	)		15			(12	)		(55	)		(128	)
Currency translation differences and other changes		1			(35	)		(57	)		(1	)		(1	)		(93	)
Present value of benefit liabilities and plan assets at end of year		391			1,110			(570	)		118			207			1,256
2012
Present value of benefit liabilities and plan assets at beginning of year		391			1,110			(570	)		118			207			1,256
Current cost					43						1			53			97
Interest cost		15			41						5			5			66
Expected return on plan assets								(22	)								(22	)
Employee contributions								(27	)								(27	)
Actuarial gains/losses		63			63			(2	)		22			(2	)		144
Benefits paid		(34	)		(35	)		20			(7	)		(47	)		(103	)
Curtailments and settlements					(3	)											(3	)
Currency translation differences and other changes		(81	)		74			(18	)		(4	)		(27	)		(56	)
Present value of benefit liabilities and plan assets at end of year		354			1,293			(619	)		135			189			1,352

Negative currency translation differences and other changes for euro 56 million included the deconsolidation of Snam for euro 113 million.

Other benefits of euro 189 million (euro 207 million at December 31, 2011) primarily concerned the deferred monetary incentive plan for euro 107 million (euro 118 million at December 31, 2011), Jubilee awards for euro 56

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million (euro 61 million at December 31, 2011) and the long-term incentive plan for euro 11 million (euro 7 million at December 31, 2011).

The reconciliation analysis of benefit obligations and plan assets was as follows:

		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

(euro million)

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Present value of benefit obligations with plan assets							877			1,009
Present value of plan assets							(570	)		(619	)
Net present value of benefit obligations with plan assets							307			390
Present value of benefit obligations without plan assets		391		354			233			284			118			135			207		189
Actuarial gains (losses) not recognized		3		(60	)		(139	)		(212	)		(11	)		(34	)
Past service cost not recognized							(67	)		(62	)		(3	)		(2	)
Net liabilities recognized in provisions for employee benefits		394		294			334			400			104			99			207		189

The net liability for foreign employee pension plans of euro 400 million (euro 334 million at December 31, 2011) included the liabilities related to joint ventures operating in exploration and production activities for euro 149 million and euro 182 million at December 31, 2011 and 2012, respectively. A receivable of an amount equivalent to such liability was recorded.

Costs charged to the profit and loss account net of discontinued operations were as follows:

(euro million)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits		Total

2011
Current cost					41			2			48			91
Interest cost		16			39			6			4			65
Expected return on plan assets					(17	)								(17	)
Amortization of actuarial gains/losses					8						(1	)		7
Effect of curtailments and settlements					2									2
		16			73			8			51			148
2012
Current cost					43			1			53			97
Interest cost		15			41			5			5			66
Expected return on plan assets					(22	)								(22	)
Amortization of actuarial gains/losses					11			1			(2	)		10
Effect of curtailments and settlements					(3	)								(3	)
		15			70			7			56			148

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The main actuarial assumptions used in the evaluation of post-retirement benefit obligations at year end and in the estimate of costs expected for 2013 were as follows:

(%)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

2011
Discount rate		4.8		2.6-15.5		4.8		3.6-4.8
Weighted average expected return rate on plan assets				3.2-12.3
Rate of compensation increase		3.0		2.0-12.3
Rate of price inflation		2.0		0.1-13.8		2.0		2.0
2012
Discount rate		3.0		1.9-15.5		3.0		1.2-3.0
Weighted average expected return rate on plan assets				2.9-10.6
Rate of compensation increase		3.0		2.0-14.0
Rate of price inflation		2.0		0.5-13.8		2.0		2.0

Italian plans were based on mortality tables prepared by Ragioneria Generale dello Stato (RG48), with the exception of the medical plan FISDE for which were adopted mortality tables prepared by Istat (Istat Proiettate e Selezionate - IPS55). Expected return rates by plan assets have been determined by reference to quoted prices expressed in regulated markets.

Plan assets consisted of the following:

(%)		Plan assets		Expected return

Securities		11.3		4.5-13.0
Bonds		56.4		1.5-11.0
Real estate		4.7		5.2-5.7
Other		27.6		0.5-10.0
		100.0

The actual return of the plan assets amounted to euro 24 million (the same amount as of December 31, 2011).

With reference to healthcare plans, the effects deriving from a 1% change of the actuarial assumptions of medical costs were as follows:

(euro million)		1% Increase		1% Decrease

Impact on current costs and interest costs		1		(1	)
Impact on net benefit obligation		19		(16	)

The amount expected to be accrued to employee benefit plans for 2013 amounted to euro 114 million, of which euro 66 million referred to defined benefit plans.

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The break-down of changes in the actuarial estimates of the net liability with respect to prior year amounts due to the difference between actual data at the end of the reporting period and the corresponding prior year actuarial assumptions is provided below:

(euro million)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

2008
Impact on net benefit obligation		7			15			3			1
Impact on plan assets					(62	)
2009
Impact on net benefit obligation		(7	)		4			3			2
Impact on plan assets					(16	)
2010
Impact on net benefit obligation		(1	)		(31	)		1			4
Impact on plan assets					3
2011
Impact on net benefit obligation		3			(21	)		2
Impact on plan assets					10
2012
Impact on net benefit obligation		3			16			(3	)		(5	)
Impact on plan assets					(2	)

The present value of liabilities for employee benefit plans and the fair value of plan assets consisted of the following:

(euro million)		Dec. 31, 2008		Dec. 31, 2009		Dec. 31, 2010		Dec. 31, 2011		Dec. 31, 2012

Present value of liabilities
TFR		443			447			433			391			354
Foreign pension plans		802			1,146			1,109			1,110			1,293
FISDE and other foreign medical plans		94			115			120			118			135
Other benefits		168			188			206			207			189
		1,507			1,896			1,868			1,826			1,971
Fair value of plan assets
Foreign pension plans		(453	)		(500	)		(468	)		(570	)		(619	)
		(453	)		(500	)		(468	)		(570	)		(619	)
Present value of net liabilities
TFR		443			447			433			391			354
Foreign pension plans		349			646			641			540			674
FISDE and other foreign medical plans		94			115			120			118			135
Other benefits		168			188			206			207			189
		1,054			1,396			1,400			1,256			1,352

 

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29 Deferred tax liabilities

Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for euro 3,630 million (euro 4,045 million at December 31, 2011).

(euro million)

Amount at Dec. 31, 2011

Additions

Deductions

Currency translation differences

Changes in the scope of consolidation

Other changes

Amount at Dec. 31, 2012

	7,120		1,656		(1,105)		(67)		(1,270)		406		6,740

Deferred tax assets and liabilities consisted of the following:

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Deferred tax liabilities		11,165			10,370
Deferred tax assets available for offset		(4,045	)		(3,630	)
		7,120			6,740
Deferred tax assets not available for offset		(5,514	)		(4,913	)
		1,606			1,827

Net deferred tax liabilities of euro 6,740 million (euro 7,120 million at December 31, 2011) comprised the recognition of the deferred tax effect against equity on the fair value evaluation of derivatives designated as cash flow hedge amounting to euro 9 million of deferred tax assets.

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The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below:

(euro million)

Carrying amount at Dec. 31, 2011

Additions

Deductions

Currency translation differences

Changes in the scope of consolidation

Other changes

Carrying amount at Dec. 31, 2012

Deferred tax liabilities
Accelerated tax depreciation		7,225			1,116			(172	)		(58	)		(668	)		(37	)		7,406
Difference between the fair value and the carrying amount of assets acquired following business combinations		1,306			84			(191	)		(21	)		(17	)					1,161
Site restoration and abandonment (tangible assets)		444			178			(29	)		11			(18	)		(49	)		537
Application of the weighted average cost method in evaluation of inventories		213			7			(68	)					(66	)		3			89
Capitalized interest expense		158						(11	)					(120	)		(3	)		24
Other		1,819			271			(634	)		1			(381	)		77			1,153
		11,165			1,656			(1,105	)		(67	)		(1,270	)		(9	)		10,370
Deferred tax assets
Site restoration and abandonment (provisions for contingencies)		(1,979	)		(320	)		67			4			106			(31	)		(2,153	)
Depreciation and amortization		(2,033	)		(336	)		27			36			66			222			(2,018	)
Accruals for impairment losses and provisions for contingencies		(1,796	)		(714	)		538						102			(14	)		(1,884	)
Unrealized intercompany profits		(777	)		(135	)		178			4			33			4			(693	)
Assets revaluation as per Laws No. 342/2000 and No. 448/2001		(621	)											617			3			(1	)
Carry-forward tax losses		(600	)		(799	)		273			10			11			(2	)		(1,107	)
Other		(2,286	)		(520	)		262			15			284			(69	)		(2,314	)
		(10,092	)		(2,824	)		1,345			69			1,219			113			(10,170	)
Impairments of deferred tax assets		533			1,182			(19	)		(11	)		(11	)		(47	)		1,627
		(9,559	)		(1,642	)		1,326			58			1,208			66			(8,543	)
Net deferred tax liabilities		1,606			14			221			(9	)		(62	)		57			1,827

Italian taxation law, modified by Article 23 of Law Decree No. 98/2011, allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than the five subsequent years, and in many cases, indefinitely. The tax rate applied to determine the portion of carry-forwards tax losses to be utilized equaled to an average rate of 25.2% for Italian companies, by considering the different taxation for energy companies and companies included in the consolidation statement for fiscal purposes, and an average rate of 34.2% for foreign companies.

Carry-forward tax losses amounted to euro 3,222 million and can be used indefinitely for euro 3,171 million. Carry-forward tax losses regarded Italian companies for euro 1,596 million and foreign companies euro 1,626 million. Carry-forward tax losses amounted to euro 2,739 million which are likely to be utilized against future taxable profit and were in respect of Italian companies for euro 1,503 million and foreign subsidiaries for euro 1,236 million. Deferred tax assets recognized on these losses amounted to euro 379 million and euro 423 million, respectively.

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30 Other non-current liabilities

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Fair value of non-hedging derivatives		591		271
Fair value of cash flow hedging derivatives		37		13
Other payables due to tax authorities				1
Other payables		70		57
Other liabilities		2,202		1,635
		2,900		1,977

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques commonly used on the marketplace.

The fair value of non-hedging derivative contracts is presented below:

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Derivatives on exchange rate
Currency swap		1				3		42		2,055		420
Other								1		3
		1				3		43		2,058		420
Derivatives on interest rate
Interest rate swap		255		50		4,136		65				530
		255		50		4,136		65				530
Derivatives on commodities
Over the counter		310		3,760		416		89		405		952
Future		3		14				1		66		9
Other		22				126		13				33
		335		3,774		542		103		471		994
Options embedded in convertible bonds								60
		591		3,824		4,681		271		2,529		1,944

Fair values of non-hedging derivatives of euro 271 million (euro 591 million at December 31, 2011) consisted of: (i) euro 198 million (euro 577 million at December 31, 2011) of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net business exposures to foreign currency exchange rates, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; (ii) euro 60 million related to the call option embedded in the bonds exchangeable into Galp Energia SGPS SA ordinary shares (further information is disclosed in note 26 – Long-term debt and current portion of long-term debt.); and (iii) euro 13 million (euro 14 million at December 31, 2011) related to derivatives embedded in the pricing formulas of long-term gas supply contracts in the Exploration & Production segment.

Fair value of cash flow hedge derivatives amounted to euro 13 million (euro 37 million at December 31, 2011) and pertained to the Gas & Power segment. Those derivatives were designated to hedge exchange rate and commodity risk exposures as described in note 13 – Other current assets. Fair value of contracts expiring beyond 2013 is disclosed in note 20 – Other non-current receivables; fair value of contracts expiring by 2013 is disclosed in note 25 – Other current liabilities and in note 13 – Other current assets. The effects of fair value evaluation of cash flow hedge derivatives are disclosed in note 32 – Shareholders’ equity and in note 36 – Operating expenses.

The nominal value of these derivatives referred to purchase and sale commitments for euro 24 million and euro 223 million, respectively (euro 340 million and euro 310 million at December 31, 2011, respectively).

Information on the hedged risks and the hedging policies is shown in note 34 – Guarantees, commitments and risks - Risk factors.

Other liabilities of euro 1,635 million (euro 2,202 million at December 31, 2011) comprised advances received from Suez following a long-term agreement for supplying natural gas and electricity of euro 968 million (euro 1,061 million at December 31, 2011) and advances relating to amounts of gas of euro 380 million (euro 299 million at

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December 31, 2011) which were off-taken below the minimum take for the year by certain of Eni’s clients, reflecting take-or-pay clauses contained in the long-term sale contracts. Management believes that the underlying gas volumes will be off-taken beyond the twelve-month time horizon.

31 Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale

Discontinued operations

Snam
On October 15, 2012, after the occurrence of conditions precedent, including in particular, the Antitrust Authority approval, Eni finalized the sale to Cassa Depositi e Prestiti SpA ("CDP") of a stake of 30% less one share in the voting share capital of Snam and as part of the transaction lost control over the investee. The transaction implemented the provisions of Law No. 27/2012, pursuant to which Eni was mandated to divest its controlling shareholding in Snam in accordance with the model of ownership unbundling and required to fully divest its residual interests in Snam with no time limits. The transaction involved 1,013,619,522 ordinary shares of Snam at a price of euro 3.47 a share yielding a capital gain through profit of euro 2,019 million. Total consideration of the sale amounted to euro 3,517 million. The exclusion of Snam from consolidation reduced financial debt by euro 12,448 million. Prior to the divestment, Snam had already reimbursed intercompany loans via third-party financing. Including the sale of a further 5% interest in Snam made to institutional investors in July, after the transaction with CDP, the residual interest of Eni in Snam is equal to 20.23% at the balance sheet date. The remaining interest was classified as an available-for-sale financial instrument and measured at fair value also considering the sterilization of the voting rights as provided for by the Decree of the President of the Council of Ministers issued on May 25, 2012 (further information is disclosed in note 17 – Investments).

Snam through its wholly-owned subsidiaries Snam Rete Gas SpA, GNL Italia SpA, Stoccaggi Gas Italia SpA and Italgas SpA, operates the natural gas transport activity by means of large backbones, the distribution of gas to residential and commercial users and small enterprises located in urban areas through low-pressures networks, re-gasification services of LNG and storage services through depleted fields designed to support strategic storage of gas and modulation needs of selling companies considering the seasonality in gas demand. As the Company considers those activities to be a major line of business, management recorded results of operations of Snam and its subsidiaries as discontinued operations.

As provided for by International Financial Reporting Standards (IFRS 5), the Snam Group was excluded from the scope of consolidation of Eni from the date of loss of control. Therefore, the economic amounts represented as discontinued operations included intragroup eliminations. In particular: (i) in the profit and loss account, results relating to discontinued operations including the gain on disposal and the fair value revaluation of the residual interest at the date of loss of control, net of tax effects, are presented in a specific line item before net profit of the year; and (ii) in the statement of cash flows, net cash provided by operating activities relating to discontinued operations are separately indicated.

The amounts relating to discontinued operations comprised in the profit and loss account and the statement of cash flows present the relevant comparisons.

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The main line items of profit and loss and cash flow statement of the discontinued operations net of intra-group transactions are provided below:

(euro million)		2010		2011		2012

Revenues				1,895			1,906			1,886
Operating expenses				1,266			1,274			998
Operating profit				629			632			888
Finance income (expense)				22			17			(51	)
Income (expense) from investments				44			48			3,508
Profit before income taxes				695			697			4,345
Income taxes				(576	)		(771	)		(613	)
Net profit				119			(74	)		3,732
- attributable to Eni				66			(42	)		3,590
- attributable to non-controlling interest				53			(32	)		142
Earnings per share		(euro per share)		0.02			(0.01	)		0.99
Net cash provided by operating activities				554			619			15
Net cash flow from investing activities				(1,411	)		(1,516	)		(1,004	)
Net cash used in financing activities				(356	)		(356	)		11,172
Capital expenditures				1,420			1,529			756

Income (expense) from investments of euro 3,508 million comprised the gain on divestment to Cassa Depositi e Prestiti SpA for euro 2,019 million and the fair value revaluation of the residual interest at the date of loss of control for euro 1,451 million.

Income taxes of euro 613 million comprised the tax effect on the gain on divestment to Cassa Depositi e Prestiti SpA for euro 27 million and on the fair value revaluation of the residual interest at the date of loss of control for euro 18 million.

Profits earned by Snam as discontinued operations do not represent Snam as if it was a standalone entity, since the profits on transactions with Eni Group are included in continuing operations as provided for by the guidelines of IFRS 5. For further information about the transaction see the Information Statement published in application of the Consob Regulation No. 17221/2010 and later additions and modifications and Article 71 of the Consob regulation on issuers (available at the Eni website eni.com).

Assets held for sale and liabilities directly associated
As of December 31, 2012, non-current assets held for sale and liabilities directly associated with non-current assets held for sale of euro 516 million and euro 361 million pertained to marginal assets in the Exploration & Production segment (euro 434 million and euro 361 million, respectively) and to Super Octanos SA in the Refining & Marketing segment (euro 52 million).

32 Shareholders’ equity

Non-controlling interest

(euro million)		Net profit		Shareholders’ equity

		2011		2012		Dec. 31, 2011		Dec. 31, 2012

Saipem SpA		552			627			2,802		3,232
Snam SpA		385			356			1,730
Hindustan Oil Exploration Co Ltd		(6	)		(55	)		123		65
Tigáz Zrt					(47	)		74		33
Others		12			4			192		184
		943			885			4,921		3,514

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Eni shareholders’ equity

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Share capital		4,005			4,005
Legal reserve		959			959
Reserve for treasury shares		6,753			6,201
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect		49			(16	)
Reserve related to the fair value of available-for-sale securities net of the tax effect		(8	)		144
Other reserves		1,421			292
Cumulative currency translation differences		1,539			943
Treasury shares		(6,753	)		(201	)
Retained earnings		42,531			41,040
Interim dividend		(1,884	)		(1,956	)
Net profit for the year		6,860			7,788
		55,472			59,199

Share capital
At December 31, 2012 the parent company’s issued share capital consisted of euro 4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (4,005,358,876 ordinary shares at December 31, 2011, nominal value euro 1 each).

On May 8, 2012, Eni’s Shareholders’ Meeting declared a dividend distribution of euro 0.52 a share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2011 dividend of euro 1.04 a share, of which euro 0.52 a share paid as interim dividend. The balance was payable on May 24, 2012, to shareholders on the register on May 21, 2012.

On July 16, 2012, the Extraordinary and Ordinary Shareholders’ Meeting resolved: (i) to eliminate the par value of all the ordinary shares representing the share capital; (ii) to cancel 371,173,546 treasury shares without par value without changing the amount of the share capital and reducing the "Reserve for the purchase of treasury shares" by euro 6,551 million, equal to the book value of the cancelled shares; (iii) to authorize the Board of Directors to purchase, within 18 months from the date of the resolution, up to a 363,000,000 ordinary Eni shares on the Mercato Telematico Azionario for a total amount up to euro 6,000 million; and (iv) to attribute the total amount of euro 6,000 million to a specific reserve destined to the purchase of own shares, formed by using equal amounts from available reserves.

Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

Reserve for treasury shares
The reserve for treasury shares represents the reserve which was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings. The amount of euro 6,201 million (euro 6,753 million at December 31, 2011) included treasury shares purchased. Changes in the amount of the reserve reflected the resolution adopted by Eni Shareholders’ Meeting as described under the item "Share capital".

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Reserve for available-for-sale financial instruments and cash flow hedging derivatives net of the related tax effect
The valuation at fair value of available-for-sale financial instruments and cash flow hedging derivatives, net of the related tax effect, consisted of the following:

Reserve as of December 31, 2010		(3	)					(3	)		(275	)		101			(174	)		(278	)		101			(177	)
Changes of the year 2011		(6	)		1			(5	)		76			(7	)		69			70			(6	)		64
Amount recognized in the profit and loss account											276			(122	)		154			276			(122	)		154
Reserve as of December 31, 2011		(9	)		1			(8	)		77			(28	)		49			68			(27	)		41
Changes of the year 2012		157			(5	)		152			(24	)		9			(15	)		133			4			137
Amount recognized in the profit and loss account											(78	)		28			(50	)		(78	)		28			(50	)
Reserve as of December 31, 2012		148			(4	)		144			(25	)		9			(16	)		123			5			128

Reserve for available-for-sale financial instruments of euro 144 million, net of the related tax effect, comprised the fair value valuation of the investments for euro 138 million (Galp Energia SGPS SA for euro 130 million and Snam SpA for euro 8 million), and other securities for euro 6 million.

Other reserves Other reserves amounted to euro 292 million (euro 1,421 million at December 31, 2011) and related to:

•		a reserve of euro 247 million represented an increase in Eni’s shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiary Snamprogetti SpA to Saipem Project SpA, both merged into Saipem SpA, at a price higher than the book value of the interest transferred thus decreasing for an equal amount the non-controlling interest (the same amount as of December 31, 2011);
•		a reserve of euro 157 million deriving from Eni SpA’s equity (the same amount as of December 31, 2011);
•		a reserve of euro 18 million related to the sale of treasury shares to Saipem managers upon exercise of stock options (euro 11 million at December 31, 2011);
•		a negative reserve of euro 124 million represented the impact on Eni’s shareholders’ equity associated with the acquisition of a non-controlling interest of 45.86% in the subsidiary Altergaz SA, now Eni Gas & Power France SA (a negative reserve of euro 119 million at December 31, 2011);
•		a negative reserve of euro 7 million related to the share of "Other comprehensive income" on equity-accounted entities (negative for euro 15 million at December 31, 2011);
•		others for euro 1 million.

As a consequence of the deconsolidation of Snam, the reserves recognized following the sale of Italgas SpA and Stoccaggi Gas Italia SpA to Snam SpA and the sale of treasury shares following the exercise of stock options by Snam managers were reclassified to retained earnings (euro 1,140 million).

Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

Treasury shares
A total of 11,388,287 Eni’s ordinary shares (382,654,833 at December 31, 2011) were held in treasury for a total cost of euro 201 million (euro 6,753 million at December 31, 2011). The decrease of 371,266,546 in treasury

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shares reflected the resolution by Eni Shareholders’ Meeting to cancel 371,173,546 shares as described in the item "Share capital". In addition, 93,000 treasury shares were sold to eligible Eni managers who exercised stock options under stock-base compensation scheme granted in previous years. Outstanding treasury shares, amounting to euro 161 million (euro 240 million at December 31, 2011) and represented by 8,259,520 ordinary shares (11,873,205 ordinary shares at December 31, 2011), were available for the 2005¹⁷ and 2007-2008¹⁸ stock option plans.

The number of shares underlying those plans decreased by 3,613,685 shares as described below:

(number)		Stock option

Number of shares as of December 31, 2011		11,873,205
Rights exercised		(93,000	)
Rights cancelled		(3,520,685	)
		(3,613,685	)
Number of shares as of December 31, 2012		8,259,520

More information about stock option plans is disclosed in note 36 – Operating expenses.

Interim dividend
The interim dividend for the year 2012 amounted to euro 1,956 million corresponding to euro 0.54 per share, as resolved by the Board of Directors on September 20, 2012, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 27, 2012.

Distributable reserves
At December 31, 2012, Eni shareholders’ equity included distributable reserves of approximately euro 48,200 million.

Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity

		Net profit		Shareholders’ equity

(euro million)		2011		2012		Dec. 31, 2011		Dec. 31, 2012

As recorded in Eni SpA’s Financial Statements		4,213			9,078			35,255			40,577
Excess of net equity in individual accounts of consolidated subsidiaries over their corresponding carrying amounts in the statutory accounts of the parent company		3,972			258			24,355			21,663
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(320	)		(2,683	)		4,400			1,503
- elimination of tax adjustments and compliance with Group account policies		(248	)		1,222			(673	)		739
- elimination of unrealized intercompany profits		115			638			(4,291	)		(2,652	)
- deferred taxation		71			160			1,337			873
- other adjustments								10			10
		7,803			8,673			60,393			62,713
Non-controlling interest		(943	)		(885	)		(4,921	)		(3,514	)
As recorded in Consolidated Financial Statements		6,860			7,788			55,472			59,199

 

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33 Other information

Main acquisitions

Nuon Belgium NV and Nuon Power Generation Walloon NV
In January 2012, Eni finalized the purchase of a 100% interest in Nuon Belgium NV (now merged in Eni Gas & Power NV) that provide gas and electricity to the Belgian retail and business market and of a 100% interest in Nuon Power Generation Walloon NV (now Eni Power Generation NV) that owns lands and all the rights and permits for the construction of an electric power plant. The allocation of the cost to assets and liabilities of euro 214 million was made on a definitive basis.

The final allocation of the purchase costs is disclosed below:

(euro million)		Nuon Belgium NV and Nuon Power Generation Wallon NV

		Carrying value		Fair value

Current assets		206		206
Property, plant and equipment		7		7
Intangible assets		5		49
Goodwill		5		98
Other non-current assets		25		25
Assets acquired		248		385
Current liabilities		150		150
Net deferred tax liabilities				15
Provisions for contingencies		4		4
Other non-current liabilities		2		2
Liabilities acquired		156		171
Eni’s shareholders equity		92		214

Net sales from operations and the net profit for the 2011 were as follows:

(euro million)		Nuon Belgium NV and Nuon Power Generation Wallon NV
		2011

Net sales from operations		741
Net profit		11

 

 

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Supplemental cash flow information

(euro million)				2010		2011		2012

Effect of investment of companies included in consolidationand businesses
Current assets		409						108
Non-current assets		316			122			171
Net borrowings		13						46
Current and non-current liabilities		(457	)		(4	)		(99	)
Net effect of investments		281			118			226
Non-controlling interests		(7	)		(3	)
Fair value of investments held before the acquisition of control		(76	)
Purchase price		198			115			226
less:
Cash and cash equivalents		(55	)					(48	)
Cash flow on investments		143			115			178
Effect of disposal of consolidated subsidiaries and businesses
Current assets		82			618			2,112
Non-current assets		855			136			18,740
Net borrowings		(267	)		257			(12,443	)
Current and non-current liabilities		(302	)		(662	)		(4,123	)
Net effect of disposals		368			349			4,286
Fair value of share capital held after the sale of control		(149	)					(943	)
Gain on disposal		309			727			2,021
Non-controlling interest		(46	)		(5	)		(1,840	)
Selling price		482			1,071			3,524
less:
Cash and cash equivalents		(267	)		(65	)		(3	)
Cash flow on disposals		215			1,006			3,521

34 Guarantees, commitments and risks

Guarantees

		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Unsecured guarantees

Other guarantees

Total

Unsecured guarantees

Other guarantees

Total

Consolidated subsidiaries				10,953		10,953				11,350		11,350
Unconsolidated entities controlled by Eni				164		164				161		161
Joint ventures and associates		6,159		1,135		7,294		6,208		892		7,100
Others		1		269		270		2		289		291
		6,160		12,521		18,681		6,210		12,692		18,902

Other guarantees issued on behalf of consolidated subsidiaries of euro 11,350 million (euro 10,953 million at December 31, 2011) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 7,511 million (euro 7,396 million at December 31, 2011), of which euro 5,491 million related to the Engineering & Construction segment (euro 5,065 million at December 31, 2011); (ii) VAT recoverable from tax authorities for euro 1,370 million (euro 1,097 million at December 31, 2011); and (iii) insurance risk for euro 298 million reinsured by Eni (euro 319 million at December 31, 2011). At December 31, 2012, the underlying commitment covered by such guarantees was euro 11,266 million (euro 10,577 million at December 31, 2011).

Other guarantees issued on behalf of unconsolidated subsidiaries of euro 161 million (euro 164 million at December 31, 2011) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for euro 154 million (euro 157 million at December 31, 2011). At December 31, 2012, the underlying commitment covered by such guarantees was euro 34 million (euro 45 million at December 31, 2011).

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Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of euro 7,100 million (euro 7,294 million at December 31, 2011) primarily consisted of: (i) an unsecured guarantee of euro 6,122 million (euro 6,074 million at December 31, 2011) given by Eni SpA to Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating to the Milan-Bologna fast-track railway by CEPAV (Consorzio Eni per l’Alta Velocità) Uno; consortium members, excluding entities controlled by Eni, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) unsecured guarantees, letters of patronage and other guarantees given to banks in relation to loans and lines of credit received for euro 828 million (euro 1,051 million at December 31, 2011), of which euro 657 million related to a contract released by Eni SpA on behalf of Blue Stream Pipeline Co BV (Eni 50%) to a consortium of international financial institutions (euro 669 million at December 31, 2011); and (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for euro 91 million (euro 108 million at December 31, 2011). At December 31, 2012, the underlying commitment covered by such guarantees was euro 456 million (euro 810 million at December 31, 2011).

Unsecured and other guarantees given on behalf of third parties of euro 291 million (euro 270 million at December 31, 2011) primarily consisted of: (i) guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%) as security against payment commitments of fees in connection with the re-gasification activity (euro 227 million). The expected commitment has been valued at euro 159 million (euro 224 million at December 31, 2011); and (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit for euro 10 million on behalf of minor investments or companies sold (euro 33 million at December 31, 2011). At December 31, 2012, the underlying commitment covered by such guarantees was euro 278 million (euro 252 million at December 31, 2011).

Commitments and risks

(euro million)		Dec. 31, 2011		Dec. 31, 2012

Commitments		15,992		16,247
Risks		2,165		431
		18,157		16,678

Other commitments of euro 16,247 million (euro 15,992 million at December 31, 2011) related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to euro 11,260 million (euro 9,710 million at December 31, 2011). The increase of euro 1,550 million related to the closing of a settlement agreement approving the development and future capital expenditures in the Karachaganak project; (ii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Angola LNG Supply Service for the acquisition of re-gasified gas at the Pascagoula plant (USA). The expected commitment has been estimated at euro 2,613 million (euro 3,267 million at December 31, 2011) and it has included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk"; (iii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Gulf LNG Energy for the acquisition of re-gasification capacity at the Pascagoula terminal (6 BCM/y) over a twenty-year period (2011-2031). The expected commitment has been estimated at euro 1,167 million (euro 1,252 million at December 31, 2011) and it has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk"; (iv) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Cameron LNG Llc for the acquisition of re-gasification capacity at the Cameron plant (USA) (6 BCM/y) over a twenty-year period (until 2029). The expected commitment has been estimated at euro 946 million (euro 1,274 million at December 31, 2011) and it has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk"; (v) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 139 million in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oil fields in Val d’Agri (euro 142 million at December 31, 2011). The commitment has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk"; and (vi) a commitment entered into by Eni USA Gas Marketing Llc for the contract of gas transportation from the Cameron plant (USA) to the American network. The expected commitment has been estimated at euro 100 million (euro 108 million at December 31, 2011) and it has been included in the off-balance sheet contractual commitments in the following paragraph "Liquidity risk".

Risks of euro 431 million (euro 2,165 million at December 31, 2011) primarily concerned potential risks associated with: (i) the value of assets of third parties under the custody of Eni for euro 123 million (euro 1,867 million at December 31, 2011). The decrease of euro 1,744 million related for euro 1,714 million to the

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deconsolidation of Snam; and (ii) contractual assurances given to acquirers of certain investments and businesses of Eni for euro 308 million (euro 298 million at December 31, 2011).

 

Non-quantifiable commitments
A parent company guarantee was issued on behalf of CARDÓN IV (Eni’s interest 50%), a joint venture operating in the Perla oilfield located in Venezuela, for the supplying to PDVSA GAS of gas quantities until 2036 (end of the concession agreement). At December 31, 2012, the commitment amounted to a maximum of $800 million corresponding for Eni to the maximum amount of the penalty clause provided for in case of an unilateral and anticipated resolution of the supply contract. Eni replaced such guarantee in March 2013, as a consequence of ongoing contract renegotiations. In particular, the penalty clause for unilateral anticipated resolution and, consequently, the maximum value of the guarantee will be determined by applying the local legislation in case of non-fulfillment. The valorization of the gas to be provided for by Eni amounted to a total of $11 billion. As well as not corresponding to an effective reference for evaluating the guarantee issued, such amount represents the maximum exposure risk for Eni. A similar guarantee was issued to Eni by PDVSA relating to the fulfillment of the commitments relating to the gas quantities to be collected by PDVSA GAS.

Following the integration signed on April 19, 2011, Eni confirmed to RFI - Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) on October 15, 1991, to guarantee a correct and timely execution of the section Milano-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as General Contractor. In order to pledge the guarantee given, the regulation of CEPAV Due binds the associates to give proper sureties and guarantees on behalf of Eni.

Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain of Eni’s assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity.

 

Risk factors

FOREWORD
The main risks that the Company is facing and actively monitoring and managing are: (i) financial risks mainly related to market risk deriving from exposure to fluctuations in commodity prices, interest rates, foreign currency exchange rates and the credit risk deriving from the possible default of a counterparty as well as the liquidity risk deriving from the risk that suitable sources of funding for the Group’s operations may not be available; (ii) the Country risk in the upstream business; (iii) risks arising from any possible development in the regulatory framework; (iv) operational risks (in particular risks deriving from exploration and production activities and those relating to HSE issues); and (v) the strategic risks, mainly those related to the exposure to a set of market variables which the Company has opted to retain based on strategic considerations, trends in the competitive environment, particularly in the natural gas market, and cyclicality of the oil and gas sector.

In 2012, Eni issued the Management System Guidelines "Integrated Risk Management" (IRM) aimed at providing the principles for the integrated risk management as well as for regulating each phase of the RMI process, individuating roles and responsibilities of the main actors involved (for further information see the "Risk management" paragraph below).

Financial risks
Financial risks are those connected with market, credit and liquidity. Management of financial risks is based on guidelines issued centrally aiming at adapting and coordinating Eni policies on financial risks matters ("Guidelines financial risks management and control"). The basis of this policy is the pooled and integrated management of commodity risks and the development of asset backed trading activities for optimizing Eni’s exposure to such risks.

Market risk
Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Finance International, Eni Finance USA and

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Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA and Eni Finance International manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies are managed by the parent company, including the negotiation of emission trading certificates. The commodity risk of each business unit (Eni’s divisions or subsidiaries) is pooled and managed by Eni Trading business unit, with Eni Trading & Shipping executing the negotiation of commodity derivatives. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni does not enter into derivative transactions on interest rates or exchange rates on a speculative basis.

The optimization in managing the commodity risk involves a whole set of transactions in commodity derivatives with the aim of:

a)

hedging certain underlying commodity prices set in contractual arrangements with third parties. Hedging derivatives can be entered also to hedge highly probable future transactions;

d)		proprietary trading. It consists in entering purchase/sale commodity contracts in both commodity and financial markets, targeting to earn an uncertain profit based on expected trends in the commodity pricing environment; and
e)		Asset Backed Trading (ABT). It consists in entering proprietary trading activities in commodity and financial markets, in order to maximize the economic value of the flexibilities associated with Eni’s assets and contracts. Price risks related to asset backed trading activities are mitigated by the natural hedge granted by the assets’ availability. Such risk management activity can be implemented through strategies of dynamic forward trading where the underlying items are represented by the Company’s assets.

Furthermore, the Company may enter derivative contracts on commodities as part of origination activities. Under this scheme, the Company acting as the originator may combine a number of derivative contracts in order to manage a given risk exposure of a third party or a business unit, normally in the wholesale market of commodities. Such trading activities may be naturally hedged by the existing assets of the originator, or, in case of absence of a suitable asset, they are managed by either trading the associated price or volume risk exposure or hedging each price or volume component of the base contract.

The framework defined by Eni’s policies and guidelines prescribes that measurement and control of market risk be performed on the basis of maximum tolerable levels of risk exposure defined in terms of limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon, or in accordance with value at risk techniques. These techniques make a statistical assessment of the market risk on the Group’s activity, i.e. potential gain or loss in fair values, due to changes in market conditions taking account of the correlation existing among changes in fair value of existing instruments. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of value at risk, pooling Group companies’ risk positions.

Eni’s calculation and measurement techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department.

With regard to commodity risk, Eni’s policies and guidelines define rules to manage this risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of value at risk and stop loss in connection with exposure deriving from commercial activities and from Asset Backed Trading activities as well as exposure deriving from proprietary trading executed by the subsidiary Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools Group companies requests for negotiating commodity

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derivatives, ensuring execution services to the Trading Business Unit. The three different market risks, whose management and control have been summarized above, are described below.

Exchange rate risk
Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro. Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance department which pools Group companies’ positions, hedging the Group net exposure through the use of certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value on the basis of market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period.

Interest rate risk
Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. Borrowing requirements of Group companies are pooled by the Group’s central finance department in order to manage net positions and the funding of portfolio developments consistently with management’s plans while maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be accounted for under the hedge accounting method in accordance with IAS 39. Value at risk deriving from interest rate exposure is measured daily on the basis of a variance/covariance model, with a 99% confidence level and a 20-day holding period.

Commodity risk
Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil and gas prices generally has a negative impact on Eni’s results of operations and vice versa. Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable margins. In order to accomplish this, Eni uses derivatives traded on the organized markets of ICE and NYMEX (futures) and derivatives traded over the counter (swaps, forward, contracts for differences and options) with the underlying commodities being crude oil, refined products or electricity. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable evaluation techniques. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. Value at risk deriving from commodity exposure is measured daily on the basis of a historical simulation technique, with a 95% confidence level and a one-day holding period.

The following table shows amounts in terms of value at risk, recorded in 2012 (compared with 2011) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section. VaR values are stated in euro as stated in the revision of "Eni Guidelines on Management and Control of Financial Risks" approved by the Board of Directors on December 15, 2011.

(Interest and exchange rate risk - Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

		2011		2012

(euro million)

High

Low

Average

At year end

High

Low

Average

At year end

Interest rate		5.34		1.07		2.65		2.92		8.69		1.41		3.13		1.88
Exchange rate		0.85		0.15		0.44		0.34		1.31		0.12		0.44		0.19

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(Commodity risk - Value at risk - Historic simulation method; holding period: 1 day; confidence level: 95%)

		2011		2012

(U.S. $ million) (a)

High

Low

Average

At year end

High

Low

Average

At year end

Area oil, products (b)		44.28		9.05		25.60		9.05		35.70		5.66		18.02		10.88
Area Gas & Power (c)		77.83		24.57		44.77		51.41		67.41		30.89		44.39		31.35

(a)		From January 2012, the value at risk is expressed in euro terms, following a review of "Eni Guidelines on Management and Control of Financial Risks" approved by the Board of Directors on December 15, 2011. The value at risk, previously, has been expressed in dollars. 2011 values have been restated accordingly and converted at the average exchange rate published by ECB for the period.
(b)		Area oil, products refers to the Eni SpA Trading Department (risk exposure from Refining & Marketing Division), Versalis SpA and Eni Trading & Shipping SpA.
(c)		The Gas & Power area refers to the Eni SpA Trading Department (risk exposure from Gas & Power Division) and Tigáz Zrt.

Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of the business. The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also credit litigation and receivable collection activities are assessed. Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance department, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterpart on a daily basis. Exceptional market conditions have forced the Group to adopt contingency plans and under certain circumstances to suspend eligibility to be a Group financial counterparty. Actions implemented also have been intended to limit concentrations of credit risk by maximizing counterparty diversification and turnover.

Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long-term debt to total debt as well as fixed rate medium and long-term debt to total medium and long-term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks.

The actions implemented as part of 2012 Eni’s financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper also targeting to increase the flexibility of funding facilities. The minimization of liquidity risks is a strategic driver of the next 4-year Financial Plan. In particular in 2012, Eni issued three bonds addressed to institutional investors for a total amount of euro 1.82 billion, all at fixed rate with maturity of approximately 8 years. In November, as part of the divestment process of its interest in Galp, Eni also issued a convertible bond with underlying Galp shares equal to 8% of the share capital of the investee for a total amount of euro 1.028 billion at fixed rate with a maturity of three years.

Eni’s financial policies are designed to achieve the following targets: (i) ensuring adequate funds to cover short-term obligations and reimbursement of long-term debt due; (ii) maintaining an adequate level of financial flexibility to support Eni’s development plans; (iii) attaining a balance between duration and composition of the

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finance debt; and (iv) maintaining a cash reserve following the great flow of liquidity achieved from the divestment of 2012, particularly the disposition of Snam. The cash reserve will be commeasured in order to: (i) reduce the refinancing with maturity of one year, allowing the Company to be financially independent also in case of negative trends in the trading environment; (ii) increase the level of liquidity to face possible extraordinary needs; and (iii) increase the flexibility of the Company’s financial structure considering lingering uncertainties in the credit markets, in a similar way as the policies adopted by the peer group companies and with a view of improving the Company’s financial rating assessment. Cash stock will be available only for short-term operations, with a very low risk profile.

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.

At December 31, 2012, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 12,173 million, of which euro 1,241 million were committed, and long-term committed borrowing facilities of euro 6,928 million which were completely drawn at the balance sheet date. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial.

Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 12.3 billion were drawn as of December 31, 2012. The Group has credit ratings of A and A-1, respectively, for long and short-term debt assigned by Standard & Poor’s and A3 and P-2 assigned by Moody’s; the outlook is negative in both ratings.

Eni’s credit ratings are potentially exposed to risk of further downgrading of the sovereign credit rating of Italy in addition to a possible deterioration in the global macroeconomic outlook, particularly the risks of a break-up of the Euro-zone. 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. Eni, through the constant monitoring of the international economic environment and continuing dialogue with financial investors and rating agencies, believes to be ready to perceive emerging critical issues screened by the financial community and to be able to react quickly to any changes in the financial and the global macroeconomic environment and implement the necessary actions to mitigate such risks, coherently with Company strategies.

Finance debt repayments including expected payments for interest charges and derivatives
The tables below summarize the Group main contractual obligations for finance debt repayments, including expected payments for interest charges and derivatives.

(euro million)		Maturity year

		2012		2013		2014		2015		2016		2017 and thereafter		Total

December 31, 2011
Non-current financial liabilities		1,635		3,010		5,076		2,936		2,840		9,378		24,875
Current financial liabilities		4,459												4,459
Fair value of derivative instruments		1,789		303		74		87		52		112		2,417
		7,883		3,313		5,150		3,023		2,892		9,490		31,751
Interest on finance debt		832		761		664		553		485		1,595		4,890
Guarantees to banks		576												576

 

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(euro million)		Maturity year

		2013		2014		2015		2016		2017		2018 and thereafter		Total

December 31, 2012
Non-current financial liabilities		2,555		2,090		3,941		2,180		2,956		8,275		21,997
Current financial liabilities		2,223												2,223
Fair value of derivative instruments		925		132		89		2		11		50		1,209
		5,703		2,222		4,030		2,182		2,967		8,325		25,429
Interest on finance debt		840		725		622		550		465		1,491		4,693
Guarantees to banks		212												212

Trade and other payables
The tables below summarize the Group trade and other payables by maturity.

(euro million)		Maturity year

		2012		2013-2016		2017 and thereafter		Total

December 31, 2011
Trade payables		13,436						13,436
Advances, other payables		9,476		32		38		9,546
		22,912		32		38		22,982

 

(euro million)		Maturity year

		2013		2014-2017		2018 and thereafter		Total

December 31, 2012
Trade payables		14,993						14,993
Advances, other payables		8,588		19		38		8,645
		23,581		19		38		23,638

Expected payments by period under contractual obligations and commercial commitments
The Group has in place a number of contractual obligations arising in the normal course of the business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations pertain to take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to off-take the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors. The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

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(euro million)		Maturity year

		2013		2014		2015		2016		2017		2018 and thereafter		Total

Operating lease obligations (a)		722		515		323		250		201		560		2,571
Decommissioning liabilities (b)		174		198		85		259		555		13,777		15,048
Environmental liabilities (c)		362		375		260		160		69		551		1,777
Purchase obligations (d)		20,761		19,486		19,394		17,815		16,482		169,815		263,753
- Gas
. take-or-pay contracts		18,463		17,763		17,840		16,377		15,094		161,787		247,324
. ship-or-pay contracts		1,746		1,303		1,263		1,159		1,119		5,515		12,105
- Other take-or-pay or ship-or-pay obligations		171		170		163		156		146		909		1,715
- Other purchase obligations (e)		381		250		128		123		123		1,604		2,609
Other obligations		4		3		3		3		3		123		139
- Memorandum of intent relating Val d’Agri		4		3		3		3		3		123		139
		22,023		20,577		20,065		18,487		17,310		184,826		283,288

(a)		Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(b)		Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(c)		Environmental liabilities do not include the environmental charge of 2010 amounting to euro 1,109 million for the proposal to the Italian Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment are not reasonably estimable.
(d)		Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(e)		Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the USA (euro 2,113 million).

Capital expenditure commitments
In the next four years Eni plans to make capital expenditures of euro 56.8 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects. At December 31, 2012, capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties.

The amounts shown in the table below include euro 600 million of committed expenditures to execute certain environmental projects.

		Maturity year

(euro million)		2013		2014		2015		2016		2017 and thereafter		Total

Committed on major projects		6,718		7,680		6,897		3,991		11,839		37,125
Other committed projects		6,940		3,782		1,584		1,100		8,496		21,902
		13,658		11,462		8,481		5,091		20,335		59,027

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Other information about financial instruments
The carrying amount of financial instruments and relevant economic effect as of and for the years ended December 31, 2011 and 2012 consisted of the following:

		2011		2012

		Finance income (expense) recognized in		Finance income (expense) recognized in

(euro million)

Carrying amount

Profit and loss account

Other comprehensive income

Carrying amount

Profit and loss account

Other comprehensive income

Held-for-trading financial instruments
Non-hedging and trading derivatives (a)		17			76						186			(408	)
Held-to-maturity financial instruments
Securities (b)		62			1						69			1
Available-for-sale financial instruments
Securities (b)		262			8			(6	)		235			8			16
Investments valued at fair value
Other non-current investments (c)											4,782			4,717			141
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other (d)		24,730			(65	)					27,913			(54	)
Financing receivables (b)		2,174			112						2,981			70
Trade payables and other (e)		22,982			(123	)					23,638			104
Financing payables (b)		29,597			(851	)					24,463			(831	)
Net assets (liabilities) for hedging derivatives (f)		32			(309	)		76			(17	)		(290	)

(a)		In the profit and loss account, economic effects were recognized as loss within "Other operating income (loss)" for euro 157 million (income for euro 188 million in 2011) and as expense within "Finance income (expense)" for euro 251 million (expense for euro 112 million in 2011).
(b)	i	Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(c)		Income were recognized in the profit and loss account within "Income (expense) from investments" for euro 1,247 million and within "Net profit (loss) for the period - Discontinued operations" for euro 3,470 million.
(d)		In the profit and loss account, economic effects were essentially recognized as expense within "Purchase, services and other" for euro 25 million (expense for euro 138 million in 2011) (impairments net of reversal) and as expense for euro 31 million within "Finance income (expense)" (income for euro 77 million in 2011) (positive exchange rate differences at year-end and amortized cost).
(e)		In the profit and loss account, exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were primarily recognized within "Finance income (expense)".
(f)	i	In the profit and loss account, income or expense were recognized within "Net sales from operations" and "Purchase, services and other" as expense for euro 289 million (expense for euro 292 million in 2011) and within "Other operating income (loss)" as expense for euro 1 million (expense for euro 17 million in 2011) (time value component).

 

Fair value of financial instruments Following the classification of financial assets and liabilities, measured at fair value in the balance sheet, is provided according to the fair value hierarchy defined on the basis of the relevance of the inputs used in the measurement process. In particular, on the basis of the features of the inputs used in making the measurements, the fair value hierarchy shall have the following levels:

(a)

Level 1: quoted prices (unadjusted) in active markets for identical financial assets or liabilities;

(b)		Level 2: measurements based on the basis of inputs, other than quoted prices above, which, for assets and liabilities that have to be measured, can be observable directly (e.g. prices) or indirectly (e.g. deriving from prices); and
(c)		Level 3: inputs not based on observable market data.

Financial instruments measured at fair value in the balance sheet as of at December 31, 2012, were classified as follows: (i) level 1, "Other financial assets available for sale", "Non-hedging derivatives - Future" and "Other investments" valued at fair value; and (ii) level 2, derivative instruments different from "Future" included in "Other current assets", "Other non-current assets", "Other current liabilities" and "Other non-current liabilities". During the 2012, no transfers were done between the different hierarchy levels of fair value.

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The table below summarizes the amount of financial instruments valued at fair value:

(euro million)				Note		Dec. 31, 2011		Dec. 31, 2012

Current assets
Other financial assets available for sale		(8)		262		235
Non-hedging derivatives - Future		(13)		68		26
Other non-hedging and trading derivatives		(13)		1,494		890
Cash flow hedge derivatives		(13)		157		31
Non-current assets
Other investments valued at fair value		(17)				4,782
Non-hedging derivatives - Future		(20)		2		5
Other non-hedging derivatives		(20)		712		424
Cash flow hedge derivatives		(20)		33		2
Current liabilities
Non-hedging derivatives - Future		(25)		63		11
Other non-hedging and trading derivatives		(25)		1,605		877
Cash flow hedge derivatives		(25)		121		32
Fair value hedge derivatives		(25)				5
Non-current liabilities
Non-hedging derivatives - Future		(30)		3		1
Other non-hedging derivatives		(30)		588		270
Cash flow hedge derivatives		(30)		37		13

Legal Proceedings

Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will not have an adverse effect on Eni’s Consolidated Financial Statements. The following is a description of the most significant proceedings currently pending. Unless otherwise indicated below, no provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably.

 

1. Environment

1.1 Criminal proceedings

(i) Investigation of the quality of groundwater in the area of the refinery of Gela. A criminal proceeding is pending before the Public Prosecutor of Gela relating to an alleged breach of environmental rules concerning the pollution of water and soil and illegal disposal of liquid and solid waste materials within the activity of the Gela refinery. Both a first degree Court at Gela and a second degree court dismissed the case because the statute of limitations expired.

(ii) Alleged negligent fire (Priolo). The Public Prosecutor of Siracusa commenced an investigation relating to certain Eni managers who were in charge of conducting operations at the refinery of Priolo prior to divesting the refinery to Erg Raffinerie Mediterranee SpA in July 31, 2002. The investigation aimed at ascertaining whether Eni managers acted with negligence in connection with a fire that occurred at the Priolo plants on April 30 and May 1-2, 2006. Upon conclusion of the preliminary investigations the Public Prosecutor requested the mentioned managers would stand trial for negligent behavior. The Ministry for the Environment has been acting as plaintiff. The proceeding is pending.

(iii) Groundwater at the Priolo site – Prosecuting body: Public Prosecutor of Siracusa. The Public Prosecutor of Siracusa (Sicily) has started an investigation in order to ascertain the level of contamination of the groundwater at the Priolo site. The Company has been notified that a number of its executive officers in charge at the time of the events subject to probe, including chief executive officers and plant general managers of the Company’s subsidiaries AgipPetroli SpA (now merged into the parent company Eni SpA in the Refining & Marketing Division), Syndial and Polimeri Europa (now Versalis SpA) are being investigated. According to the technical surveys the ground and the groundwater at the Priolo site should be considered polluted according to Legislative Decree No. 152/2006. This contamination was caused by a spill-over made in the period prior to 2001

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and not subsequent to 2005; the equipment still operating on the site represent another source of risk, in particular the ones owned by ISAB Srl (ERG). According to the findings, the Public Prosecutor requested the dismissal of the proceeding. The decision of the Judge on the dismissal of the proceeding is still pending.

(iv) Fatal accident Truck Center Molfetta – Prosecuting body: Public Prosecutor of Trani. On May 11, 2010, Eni SpA, eight employees of the Company and a former employee were notified of closing of the investigation into alleged manslaughter, grievous bodily harm and illegal disposal of waste materials in relation to a fatal accident occurred in March 2008 that caused the death of four workers deputed to the cleaning of a tank owned by a company part of the Italian Railways Group. The tank was used for the transportation of liquid sulphur produced by Eni in the refinery of Taranto. The Public Prosecutor has removed three defendants and transmitted evidence to the Judge for the Preliminary Investigations requesting to dismiss the proceeding. The Judge for the Preliminary Investigations accepted the above mentioned request. In the hearing of April 19, 2011, the Judge admitted as plaintiffs against the above mentioned individuals all the parts, excluding the relatives of one of the victims, whose position has been declared inadmissible because of lack of a cause of action. The Judge declared inadmissible all the requests brought by other parties to act as plaintiffs against Eni. On December 5, 2011, the Judge pronounced an acquittal sentence for the individuals involved and for Eni SpA, as the indictments are groundless. On July 3, 2012, the Public Prosecutor filed an appeal against this decision.

(v) Syndial SpA (company incorporating EniChem Agricoltura SpA - Agricoltura SpA in liquidation - EniChem Augusta Industriale Srl - Fosfotec Srl) – Proceeding about the industrial site of Crotone. A criminal proceeding is pending before the Public Prosecutor of Crotone relating to allegations of environmental disaster, poisoning of substances used in the food chain and omitted cleanup due to the activity at a landfill site which was taken over by Eni’s subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrial waste from Montedison activities till 1989 and then no additional waste was discharged there. Eni’s subsidiary carried out the cleanup of the landfill in 1999 through 2000. The defendants are certain managers at Eni’s subsidiaries which have owned and managed the landfill since 1991. A technical assessment of the circumstances is pending.

(vi) Eni SpA - Gas & Power Division – Industrial site of Praia a Mare. Based on complaints filed by certain offended persons, the Public Prosecutor of Paola started an enquiry about alleged diseases related to tumors which those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. On the basis of the findings of independent appraisal reports, in the course of 2009 the Public Prosecutor resolved that a number of ex-manager of that industrial complex would stand trial. In the preliminary hearing held in November 2010, 189 persons entered the trial as plaintiff; while 107 persons were declared as having been offended by the alleged crime. The plaintiffs have requested that both Eni and Marzotto SpA would bear civil liability. However, compensation for damages suffered by the offended persons has yet to be determined. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants would stand trial for culpable manslaughter, culpable injuries, environmental disaster and negligent conduct about safety measures on the workplace. The proceeding is pending.

(vii) Syndial SpA and Versalis SpA - Porto Torres – Prosecuting body: Public Prosecutor of Sassari. The Public Prosecutor of Sassari (Sardinia) resolved that a number of officers and senior managers of companies engaging in petrochemicals operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s fully-owned subsidiary Syndial, would stand trial due to allegations of environmental damage and poisoning of water and crops. The Province of Sassari, the Municipality of Porto Torres and other entities have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine fauna of the industrial port of Porto Torres. The trial before a jurisdictional body of the Italian criminal law which is charged with judging the most serious crimes, was annulled as that jurisdictional body did not recognize the gravity elements justifying its judgment due to a different crime allegation in the notice of conclusion of the preliminary investigation with respect to the crime allegation presented in the request of trial filed by the Public Prosecutor. Thus the proceeding was returned before the Public Prosecutor. The proceeding is pending.

(viii) Syndial SpA and Versalis SpA - Porto Torres dock – Prosecuting body: Public Prosecutor of Sassari. In July 2012, the Judge for the Preliminary Hearing, following a request of the Public Prosecutor of Sassari, requested the performance of a probationary evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by Syndial SpA) and its capacity to avoid the dispersion of contamination released by the site in the near portion of sea. Syndial SpA and Versalis SpA have been notified that its chief executive officers and other managers are being investigated.

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(ix) Syndial SpA – Public Prosecutor of Gela. An investigation before the Public Prosecutor of Gela is pending regarding a number of former Eni employees. In particular the proceeding involves 17 former managers of the companies ANIC SpA, EniChem SpA, EniChem Anic SpA, Anic Agricoltura SpA, Agip Petroli SpA, and Praoil Aromatici e Raffinazione Srl who were previously in charge of conducting operations and granting security at Clorosoda plant in Gela. The proceeding regards the crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged diseases which those persons may have contracted at the above mentioned plant. Alleged crimes relate to the period from 1969, when operations on Clorosoda plant have commenced, to 1998, when the clean-up activities have terminated. The Public Prosecutor requested the performance of a medico-legal appraisal on over 100 people employed on the above mentioned plant to verify the relation of causality between the deaths occurred and the eventual pathologies affecting these individuals, and the exposures related to the work performed and missing implementation by the relevant company functions of the measures necessary for ensuring the employee health and security in relation to the risks connected with the mentioned working activities.

(x) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria – Prosecuting body: Public Prosecutor of Castrovillari. Certain areas owned by Eni in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria have been seized by the Judicial authority pending an investigation about an alleged improper handling of industrial waste from the processing of zinc ferrites at the industrial site of Pertusola Sud, which was subsequently shut down, and illegal storing in the seized areas. The circumstances under investigation are the same considered in a criminal action for alleged omitted clean-up which was concluded in 2008 without any negative outcome on part of Eni’s employees. Eni’s subsidiary Syndial SpA has removed any waste materials from the landfills Syndial entered a transaction agreement with the Municipality of Cerchiara to settle all damages caused by the unauthorized landfills to the territory of the Municipality. The Municipality of Cerchiara renounced to all claims in relation to the circumstances investigated in the criminal proceeding. Eni’s subsidiary has also arranged a similar transaction with the Municipality of Cassano. The criminal proceeding is still pending.

 

1.2 Civil and administrative proceeding

Syndial SpA (former EniChem SpA)
(i) Claim of environmental damages, allegedly caused by industrial activities in the area of Crotone – Prosecuting Bodies: the Council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region. The Council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region summoned Syndial before the Civil Court of Milan to obtain a sentence condemning the Eni subsidiary to compensate the environmental damage and clean-up and remediation costs caused by the operations of Pertusola Sud SpA (merged in EniChem, now Syndial) at the Crotone site. This first degree proceeding was generated in January 2008, by the unification of two different actions, the first brought by Calabria Region in October 2004, the second one by the Council of Ministers, the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the Calabria Region commenced in February 2006. The environmental claims and clean-up costs amounted to euro 2,720 million which comprised both the Calabria Region claims and the Ministry for the Environment claims. In order to settle the whole matter, in 2008 Syndial decided to take over the remediation activities in the area and on December 5, 2008 filed a comprehensive clean-up project. This project, which was approved in almost its element by the Ministry for the Environment and the Calabria Region, has been considered substantially adequate also by the Court. On February 24, 2012, the Court sentenced Syndial to correctly execute the environmental clean-up of the site and to pay to the Presidency of the Council of Ministers and the Ministry for Environment the sum of euro 56.2 million plus interest charges accrued from the plaintiffs’ claims. Eni accrued an environmental risk provision that is progressively utilized for the clean-up activities.

(ii) Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore – Prosecuting body: Ministry for the Environment. In May 2003, the Ministry for the Environment summoned Syndial to obtain a sentence condemning the Eni subsidiary to compensate an alleged environmental damage caused by the activity of the Pieve Vergonte plant in the years 1990 through 1996. With a temporarily executive sentence dated July 3, 2008, the District Court of Turin sentenced the subsidiary Syndial SpA (former EniChem) to compensate environmental damages amounting to euro 1,833.5 million, plus legal interests that accrue from the filing of the decision. Syndial and Eni technical-legal consultants have considered the decision and the amount of the compensation to be without factual and legal basis and have concluded that a negative outcome of this proceeding is unlikely. Particularly, Eni and its subsidiary deem the amount of the environmental damage to be absolutely wholly groundless as the sentence has been considered to lack sufficient elements to support such a material amount of the liability charged to Eni and its subsidiary with respect to the volume of pollutants ascertained by the Italian Environmental Minister. In July 2009, Syndial filed an appeal against the above mentioned sentence,

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and consequently the proceeding would continue before a Second Degree Court. In the hearing of June 15, 2012 before the Second Degree Court of Turin, the Minister for the Environment, formalized trough the Board of State Lawyers its decision to not execute the sentence until a final verdict on the whole matter is reached. The Second Degree Court requested a technical appraisal of the matter which is due to be filed no later than November 15, 2013. Furthermore an administrative proceeding is ongoing regarding certain environmental works to clean-up and make safe the Pieve Vergonte site. Syndial filed an appeal against certain prescriptions of the Ministry for the Environment relating to the modes of executing the clean-up of soil and groundwater and extension of the scope of work to other nearby areas. The Administrative Court of the Piemonte Region rejected part of the Syndial appeal. A Syndial filed a counterclaim before a higher degree administrative court.

(iii) Action commenced by the Municipality of Carrara for the remediation and reestablishment of previous environmental conditions at the Avenza site and payment of environmental damage. The Municipality of Carrara commenced an action before the Court of Genova requesting Syndial SpA to remediate and restore previous environmental conditions at the Avenza site and the payment of environmental damage (amounting to euro 139 million), further damages of various types (e.g. damage to the natural beauty of this site) amounting to euro 80 million as well as damages relating to loss of profit and property amounting to approximately euro 16 million. This request is related to an accident that occurred in 1984, as a consequence of which EniChem Agricoltura SpA (later merged into Syndial SpA), at the time owner of the site, carried out safety and remediation works. The Ministry for the Environment joined the action and requested environmental damage payment – from a minimum of euro 53.5 million to a maximum of euro 93.3 million – to be broken down among the various companies that ran the plant in the past. With a sentence of March 2008, the Court of Genova rejected all claims made by the Municipality of Carrara and the Ministry for the Environment. The Second Instance Court too confirmed the decision issued in the first judgment and rejected all the claims made by the plaintiffs. The Ministry for the Environment filed an appeal before a third instance court on the belief that Syndial is to be held responsible for the environmental damage as the Eni subsidiary took over the site form the previous owners assuming all existing liabilities; it was responsible for managing the plant and inadequately remediating the site after the occurrence of an incident in 1984 and for omitted clean-up. Syndial established itself as defendant.

(iv) Ministry for the Environment - Augusta harbor. The Italian Ministry for the Environment with various administrative acts prescribed companies running plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Versalis, Syndial and Eni Refining & Marketing Division. Pollution has been detected in this area primarily due to a high mercury concentration which is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above mentioned companies opposed said administrative actions, objecting in particular to the way in which remediation works have been designed and modes whereby information on pollutants concentration has been gathered. A number of administrative proceedings were started on this matter, which were reunified before the Regional Administrative Court of Catania. In October 2012, said Court sentenced in favor of the recourses filed by Eni’s subsidiaries against the Ministry prescriptions about the removal of pollutants and the construction of a physical barrier. The Court ruling was based on a sentence filed by the Court of Justice of the European Community. Specifically, the European Court confirmed the EU principle of the liability associated with the environmental damage, while at the same time reaffirming the necessity to ascertain the relation between cause and effect and identify the entity that is actually liable for polluting. It must be noted that the Public Prosecutor of Siracusa commenced a criminal action against unknown persons in order to verify the effective contamination of the Augusta harbor and the risks relating to the execution of the clean-up project proposed by the Ministry. The technical assessment disposed by the Public Prosecutor generated the following outcomes: (a) no public health risk in the Augusta harbor; (b) absence of any involvement on part of Eni companies in the contamination; and (c) drainages dangerousness. Based on those findings, the Public Prosecutor decided to dismiss the proceeding.

(v) Claim for preventive technical inquiry – Court of Gela. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and Syndial SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified a claim issued by 18 parents of child born malformed in the Municipality of Gela between 1992 and 2007. The claim for preventive technical inquiry aims at verifying the relation of causality between the malformation pathologies suffered by the children of the plantiffs and the environmental pollution caused by the Gela site (pollution deriving from the existence and activities at the industrial plants of the Gela refinery and Syndial SpA), quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. The examination of the claims filed by the plaintiffs confirmed the lack of probatory evidences in the relation of causality. In any case, the same issue was the subject of previous inquiries in a number of proceedings, all resolved without the ascertainment of any illicit behavior on part of Eni or its subsidiaries. A technical appraisal of the matter is pending. Furthermore, 15 more claims were notified to Eni’s subsidiaries on the same matter. Those proceedings are ongoing.

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(vi) Environmental claim relating to the Municipality of Cengio – Plaintiffs: the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio. The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio summoned Eni’s subsidiary Syndial before a Civil Court to obtain a sentence condemning the Eni subsidiary to compensate the environmental damage relating to the site of Cengio. The plaintiffs accused Syndial of negligence in performing the clean-up and remediation of the site. On the contrary, Syndial believes to have executed properly and efficiently the clean-up work in accordance with the framework agreement signed with the involved administrations including the Ministry for the Environment in 2000. On February 6, 2013, a court in Genoa sentenced the resumption of the proceeding and established a technical appraisal to verify the existence of the environmental damage.

(vii) Eni SpA – Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe – Prosecuting body: Delegated Commissioner. In March 2009, Eni and its subsidiary Sofid (now Eni Adfin) were notified of a bankruptcy claw back as part of a reorganization procedure filed by the airlines companies Volare Group, Volare Airlines and Air Europe which commenced under the provisions of Ministry of Production Activities, on November 30, 2004. The request regarded the override of all the payments made by those entities to Eni and Eni Adfin, as Eni agent for the receivables collection, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, for a total estimated amount of euro 46 million plus interest. Eni and Eni Adfin were admitted as defendants. After the conclusion of the investigation, a court ruled against the claims made by the commissioners of the reorganization procedures. The relevant sentence was filed on March 1, 2012. The commissioners filed a counterclaim against the first degree sentence.

(viii) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. On January 23, 2013, the Italian airline company Alitalia undergoing a reorganization procedure summoned before the Court of Rome Eni, Exxon Italia and Kuwait Petroleum Italia SpA to obtain a compensation for alleged damages caused by a presumed anticompetitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a deliberation filed by the Italian Antitrust Authority on June 14, 2006. The antitrust deliberation accused Eni and other five petroleum companies of anticompetitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. The antitrust findings were substantially endorsed by an administrative court. Alitalia has made a claim against the three petroleum companies jointly and severally presenting two alternative ways to assess the alleged damages. A first assessment of the overall damages amounted to euro 908 million. This was based on the presumption that the anticompetitive agreements among the defendants would have prevented Alitalia from autonomously purchasing supplies of jet fuel in the years when the existence of the anticompetitive agreements were ascertained by the Italian Antitrust Authority and in subsequent years until Alitalia ceased to operate airline activity. Alitalia asserts the incurrence of higher supply costs of jet fuel of euro 777 million excluding interest accrued and other items which add to the lower profitability caused by a reduced competitive position in the marketplace estimated at euro 131 million. An alternative assessment of the overall damage made by Alitalia stands at euro 395 million of which euro 334 million of higher purchase costs for jet fuel and euro 61 million of lower profitability due to the reduced competitive position on the marketplace.

 

2. Other judicial or arbitration proceedings

(i) Saipem SpA – CEPAV Uno. Saipem holds an interest in the CEPAV Uno Consortium (50.36%) which in 1991 signed a contract with TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) for the construction of a fast-track railway infrastructure for high speed/high capacity trains from Milan to Bologna. An arbitration proceeding has arisen to define certain amounts claimed by the Consortium against the buyer for alleged changes in the scope of work, as the counterparties failed to reach an amicable settlement of the issues. The Arbitration Committee awarded the Consortium an amount of euro 54.253 million that was disbursed by RFI on February 7, 2013. Then, the Consortium filed three further claims amounting to euro 2,108 million to take into account alleged damages, higher costs incurred for changes in the scope of work and other factors in addition to interest accrued and revaluation. In February 2013, the Court of Rome rejected a recourse filed by RFI against the establishment of the relevant arbitration committees in charge of defining the new claims made by the Consortium.

(ii) Fos Cavaou. An arbitration proceeding before the International Chamber of Commerce of Paris between the client company Société du Terminal Méthanier Fos Cavaou (now FOSMAX LNG) and the contractor STS – a French consortium participated by Saipem SA (50%), Technimont SpA (49%) and Sofregaz SA (1%) – is pending. The memorandum filed by FOSMAX LNG supporting the arbitration proceeding claimed the payment of euro 264 million for damage payment, delay penalties and costs incurred for the termination of the works. Approximately euro 142 million of the total amount requested related to loss of profit, which is an item that cannot be compensated based on the existing contractual provisions with the exception of fraudulent and serious culpable behavior. STS

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filed counterclaim for a total amount of approximately euro 338 million as damage repayment due to the alleged excessive interference of FOSMAX LNG in the execution of the works and payment of extra works not recognized by the client. Both parties filed their memoranda. Management expects the arbitration proceeding to end the review of the issued by end of 2013 with a final arbitration as early as in 2014.

 

3. Antitrust, EU Proceedings, Actions of the Authority for Electricity and Gas and of Other Regulatory Authorities

(i) Inquiries in relation to alleged anticompetitive agreements in the area of elastomers – Prosecuting Body: European Commission. On November 29, 2006, the European Commission ascertaining anticompetitive agreements in the field of BR and ESBR elastomers fined Eni and its subsidiary Polimeri Europa (actually Versalis) for an amount of euro 272.25 million. Eni and its subsidiary filed claims against this decision before the European Court of First Instance in February 2007. The hearings took place in October 2009. On July 13, 2011, the First Instance Court filed the decision to reduce the above mentioned fine to the amount of euro 181.5 million. In particular, the Court annulled the increase of the fine related to the aggravating circumstance of recidivism. The companies involved in the decision and the European Commission filed a claim before the European Court of Justice. In addition the European Commission communicated to the decision to start an inquiry for the determination of a new sanction. The Company filed an appeal against this decision. The Commission communicated to Eni and Versalis the commencement of a new proceeding for a new evaluation of the existence of the requirement for the application of an increased fine based on the aggravating circumstance of recidivism. In August 2007, with respect to the above mentioned decision of the European Commission, Eni submitted a request for a negative ascertainment with the Court of Milan aimed at proving the non-existence of alleged damages suffered by tire BR/SBR manufacturers. The Court of Milan declared the appeal inadmissible. Eni appealed against the Court’s sentence. This appeal is still pending. In December 2012, the First Instance Court of the European Union reduced to euro 106 million the fine imposed to Eni and its subsidiary Polimeri Europa from the original amount of euro 132.16 million sanctioned on December 5, 2007 relating to alleged anticompetitive practices in the in CR elastomers sector, with other chemical companies, in violation of Article 81 of EC Treaty and of Article 53 of SEE agreement. Eni and Versalis have appealed against this decision before the EU Court of Justice in order to obtain the complete annulment of the economic sanction. Also the European Commission has appealed against the decision.

(ii) Inquiry in relation to gas transportation. In March 2012, the Italian Antitrust Authority started an inquiry targeting alleged anticompetitive behavior charged to Eni in connection with the refusal to dispose of secondary transport capacity on the Transitgas and TAG pipelines to third parties. On June 1, 2012, Eni filed a proposal of commitments pursuant to Article 14-ter of Law No. 287/1990, aiming at settling the proceeding without the ascertainment of any illicit behavior. On September 6, 2012, the Authority accepted Eni proposal and stated that the commitments were binding.

(iii) Consob investigation - Saipem SpA. Following the issue by Saipem SpA of its press release of January 29, 2013, in which it revised its 2012 earnings guidance and its outlook for 2013, Saipem received a communication from Consob dated January 31, 2013 asking it to describe the process of evaluation and the considerations that led to the decision to issue the press release in question, to describe the information and data used to arrive at the revision of its guidance for 2012 profits and 2013 revenues and profits and of its forecasts for 2014, and to provide a list of persons included in the register maintained pursuant to Article 115-bis of the Consolidated Finance Act who had access to the data and information referred to in the press release. Subsequently, in a letter dated February 1, 2013, Consob announced the commencement of an inspection of Saipem pursuant to Article 187-octies, paragraph 3 of Legislative Decree No. 58 of February 24, 1998 with the purpose of gathering documents and information regarding the preparation of the press release, the management of privileged information, and compliance with legislation concerning transactions by relevant parties. Subsequently, Consob requested additional information from Saipem in communications of February 8 and 25, 2013, including information concerning the variations between the last business plan approved prior to January 29, 2013 and the new 2013-2016 business plan. Saipem promptly responded to the above communications supplying the documentation and information requested.

 

4. Court inquiries

(i) EniPower SpA. In June 2004, the Milan Public Prosecutor commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. These inquiries were widely covered by the media. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately dismissed. The Court presented EniPower (commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of process in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In accordance with its

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transparency and integrity guidelines, Eni took the necessary steps in acting as plaintiff in the expected legal action in order to recover any damage that could have been caused to Eni by the illicit behavior of its suppliers and of their and Eni employees. In the meantime, preliminary investigations have found that both EniPower and Snamprogetti are not to be considered defendants in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the Preliminary Hearing requested all the parties that have not requested the plea-bargain to stand in trial, excluding certain defendants as a result of the statute of limitations. During the hearing on March 2, 2010, the Court confirmed the admission as plaintiffs of Eni SpA, EniPower SpA and Saipem SpA against the inquired parts under the provisions of Legislative Decree No. 231/2001. Further employees of the companies involved were identified as defendants to account for their civil responsibility. After the filing of the pleadings occurred in the hearing of July 12, 2011, the proceeding was postponed to September 20, 2011. In that date the Court of Milan concluded that nine persons were guilty for the above mentioned crimes. In addition, they were condemned jointly and severally to the payment of all damages to be assessed through a dedicated proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations while the trial ended with an acquittal or 15 individuals. In relation to the companies involved in the proceeding, the Court found that 7 companies are liable based on the provisions of Legislative Decree No. 231/2001, imposing a fine and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower and Saipem which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies. The Court rejected the position as plaintiffs of the Eni Group companies, reversing a prior decision made by the Court. This decision may have been made probably on the basis of a pronouncement made by a Supreme Court which stated the illegitimacy of the constitution as plaintiffs made against any legal entity which is indicted under the provisions of Legislative Decree No. 231/2001. The Court filed the ground of the judgment on December 19, 2011. The condemned parties filed an appeal against the above mentioned decision.

(ii) Trading. An investigation is pending regarding two former Eni managers who were allegedly bribed by third parties in connection with entering into certain transactions with two oil product trading companies. Within such investigation, on March 10, 2005, the Public Prosecutor of Rome notified Eni of two judicial measures for the seizure of documentation concerning Eni’s transactions with the said companies. Eni is acting as plaintiff in this proceeding. The Judge for the Preliminary Hearing rejected most of the dismissal requests issued by the Public Prosecutor. Basing on the decision of the Judge for the Preliminary Hearing, the Public Prosecutor of Rome notified Eni, as injured part, the summon against two former managers of the Company charged of aggravated fraud related to the relevant patrimonial damage caused to the injured part through the abuse of working relations and activities. The First Judge dismissed the accusation for all the other defendants as a result of the statute of limitations.

(iii) TSKJ Consortium Investigations by U.S., Italian, and other Authorities. Snamprogetti Netherlands BV has a 25% participation in the TSKJ Consortium companies. The remaining participations are held in equal shares of 25% by KBR, Technip, and JGC. Beginning in 1994, the TSKJ Consortium was involved in the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti SpA, the holding company of Snamprogetti Netherlands BV, was a wholly owned subsidiary of Eni until February 2006, when an agreement was entered into for the sale of Snamprogetti to Saipem SpA and Snamprogetti was merged into Saipem as of October 1, 2008. Eni holds a 43% participation in Saipem. In connection with the sale of Snamprogetti to Saipem, Eni agreed to indemnify Saipem for a variety of matters, including potential losses and charges resulting from the investigations into the TSKJ matter referred to below, even in relation to Snamprogetti subsidiaries. In recent years the proceeding was settled with the U.S. Authorities and certain Nigerian Authorities, which had been investing into the matter. The proceeding is still pending before Italian judicial Authorities.
The proceedings in the U.S.: following an investigation that lasted several years, in 2010 the Department of Justice and the SEC entered into settlements with each of the TSKJ consortium members. In particular, in July 2010, Snamprogetti Netherlands BV entered into a deferred prosecution agreement with the DoJ, consented to the filing of a criminal information, and agreed to pay a fine of $240 million. In addition, Snamprogetti Netherlands BV and Eni reached an agreement with the SEC to resolve the investigation and jointly agreed to pay disgorgement to the SEC of $125 million. All amounts due to the U.S. Authorities were paid by Eni in accordance with the indemnity granted by Eni in connection with its sale of Snamprogetti to Saipem. Following the two-year period set out in the deferred prosecution agreement, in September 2012 the DoJ dismissed the criminal information filed against Snamprogetti Netherlands BV, thereby dismissing the criminal proceeding against Snamprogetti Netherlands BV.
The proceedings in Italy: beginning in 2004, the TSKJ matter has prompted investigations by the Public Prosecutor’s office of Milan against unknown persons. Since March 10, 2009, the Company has received requests of exhibition of documents from the Public Prosecutor’s office of Milan. The events under investigation cover the

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period since 1994 and also concern the period of time subsequent to the June 8, 2001, enactment of Italian Legislative Decree No. 231 concerning the liability of legal entities. On August 12, 2009, a decree issued by the Judge for the Preliminary Investigations at the Court of Milan was served on Eni (and on July 31, 2009 on Saipem SpA, as legal entity incorporating Snamprogetti SpA). The decree set a hearing in Court in relation to a proceeding ex Legislative Decree No. 231 of June 8, 2001 whereby the Public Prosecutor of Milan is investigating Eni SpA and Saipem SpA for liability of legal entities arising from offences involving international corruption charged to former managers of Snamprogetti SpA. The Public Prosecutor of Milan requested Eni SpA and Saipem SpA to be debarred from activities involving – directly or indirectly – any agreement with the Nigerian National Petroleum Corp and its subsidiaries. The events referred to the request of precautionary measures of the Public Prosecutor of Milan cover TSKJ Consortium practices during the period from 1995 to 2004. In this regard, the Public Prosecutor claimed the inadequacy and violation of the organizational, management and control model adopted to prevent those offences charged to people subject to direction and supervision. On November 17, 2009, the Judge for the Preliminary Investigations rejected the request of precautionary measures of disqualification filed by the Public Prosecutor of Milan against Eni and Saipem. The Public Prosecutor of Milan appealed the above mentioned decision before the Third Instance Court. The Court decided that the request of precautionary measures be admissible according to Legislative Decree No. 231/2001 even in the case of international corruption. The issue would be subsequently examined by the Appeal Court of Milan. On February 18, 2011, the Public Prosecutor of Milan, with respect to the guarantee payment amounting to euro 24,530,580, even in the interest of Saipem SpA, renounced to contest the decision of rejection of precautionary measures of disqualification for Eni SpA and Saipem SpA issued by the Judge for the Preliminary Hearing. In the hearing of February 22, 2011, the Re-examination Court, taking note of the above mentioned renounce, declared inadmissible the appeal of the Public Prosecutor of Milan and closed the proceeding related to the request of precautionary measures of disqualification for Eni SpA and Saipem SpA. On November 3, 2010, the defense of Saipem was notified the conclusion of the investigations relating to the proceeding pending before the Court of Milan trough a deed by which the Court evidenced the alleged violations made by the five former Snamprogetti SpA (now Saipem SpA) and Saipem SpA being the parent company of Snamprogetti. The deed does not involve the Eni Group parent company Eni SpA. The charged crimes involve alleged corruptive events that have occurred in Nigeria after July 31, 2004. It is also stated the aggravating circumstance that Snamprogetti SpA reported a relevant profit (estimated at approximately $65 million). On December 3, 2010, the defense of Saipem was notified the opening of a proceeding with the first hearing scheduled for December 20, 2010. In the hearing of January 26, 2011, the Public Prosecutor requested five former employees of Snamprogetti SpA (now Saipem) and Saipem SpA (as legal entity incorporating Snamprogetti) to stand trial in the hearing scheduled for April 2011. In the hearing of February 2, 2012, although the term for the occurrence of the statute of limitations for the individuals who are acting as plaintiffs was expired, the Public Prosecutor raised an issue of constitutional legitimacy for the incompatibility between the internal and international legislation on the statute of limitation, in particular the OECD convention on the fight against the international corruption. The Court dismissed the case with respect to the position of the individuals who were acting as plaintiffs for the expiration of the statute of limitations while the proceeding continues for Saipem SpA. In the hearing of July 12, 2012, the Judge reviewed the technical consultants of the defendant and the appraiser reports were filed. After a number of postponements at the final hearing held on February 5, 2013 Saipem defense raised an issue of constitutional legitimacy in relation to certain provisions of Legislative Decree No. 231/2001 relating to the alleged crimes under investigation. In the subsequent hearing of March 26, 2013, the Court of Milan rejected the issues of constitutional legitimacy raised by the Company as they were considered groundless. In the same hearing the Public Prosecutor required Saipem SpA to pay a fine amounting to euro 900,000 and the disgorgement of the guarantee payment of euro 24,530,580, made by Snamprogetti Netherlands BV to the Public Prosecutor of Milan in February 2011. The hearing was postponed to May 21, 2013 when the Company will present its defensive memorandum. It is worth mentioning that the Board of Directors of Eni and Saipem in 2009 and 2010, respectively, approved new guidelines and anti-corruption policies regulating Eni and Saipem management of the business. The guidelines integrated anti-corruption policies of the Company, aligning them to the international best practices, optimizing the compliance system and granting the highest respect of Eni, Saipem and their workers of the Code of Ethics, 231 Model and national and international anti-corruption policies.

(iv) Gas metering. In May 2007, a seizure order (in respect to certain documentation) was served upon Eni and other Group companies as part of a proceeding brought by the Public Prosecutor at the Court of Milan. The order was also served upon five top managers of the Group companies in addition to third party companies and their top managers. The investigation alleges behavior which breaches Italian Criminal Law, starting from 2003, regarding the use of instruments for measuring gas, the related payments of excise duties and the billing of clients as well as relations with the Supervisory Authorities. The allegation regards, inter alia, the offense contemplated by Legislative Decree of June 8, 2001, No. 231, which establishes the liability of the legal entity for crimes committed by its employee in the interests of such legal entity, or to its advantage. Accordingly, notice of the commencement of investigations was served upon Eni Group companies (Eni, Snam Rete Gas and Italgas) as well as third party companies. In relation to this proceeding, the Public Prosecutor of Milan requested the dismissal for certain people indicted, including a top manager as the Prosecutor did not find sufficient elements to support the indictment in a

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possible trial. The request was preceded by a request of dismissal from the principal proceeding of the dismissed people. On January 24, 2012, the Judge for the Preliminary Hearing disposed the dismissal of these people.

Croatian gas metering: this was a new proceeding part of the principal proceeding describe above. On November 26, 2009, a notice of conclusion of the preliminary investigation was served to Eni’s Group companies whereby 12 Eni employees, also including former employees, are under investigation. The exceptions filed in the notice include: (i) violations pertaining to recognition and payment of the excise on natural gas amounting to euro 20.2 billion; (ii) violations or failure in submitting the annual statement of gas consumption and/or in the annual declarations to be filed with the Duty Authority or the Authority for Electricity and Gas; and (iii) a related obstacle which has been allegedly posed to the monitoring functions performed by the Authority for Electricity and Gas. In the subsequent hearing of January 24, 2012, the Judge resolved to dismiss the proceeding against all defendants. The Public Prosecutor filed an appeal against this decision before the Third Instance Court. The appeal did not refer to all the defendants but only to some of them. On February 11, 2013, the Court rejected the appeal referred to Eni and its subsidiaries positions in particular: (i) declaring its inadmissibility in relation to one of the defendants; and (ii) dismissing it for all the other alleged crimes. The decision filed by the Judge for Preliminary Hearing is therefore irrevocable.
Gas metering excise: on December 20, 2010, as a result of a further dismissal of judicial position from the main proceeding, the Public Prosecutor of Milan notified to nine employees and former employees of Eni (in particular belonging to the Gas & Power Division) the conclusion of the investigation related to the crime under the provisions of Article 40 (violations pertaining to recognition and payment of the excise on mineral oils) of Legislative Decree No. 504 of October 26, 1995. The deed also disputed certain violations pertaining to subtraction of taxable amounts and missed payments of excise taxes on natural gas amounting to euro 0.47 billion and euro 1.3 billion, respectively. The Duty Authority of Milan, responsible for the collection of dodged taxes, considering the documentation filed by Eni, reduced the amount initially claimed by the Public Prosecutor to euro 114 million of dodged taxes. The Duty Authority also stated that it would reassess that amount considering further evidence arising from the criminal proceeding. The Judge resolved to dismiss the proceeding against all defendants because the fact did not constitute an offence. The Public Prosecutor filed an appeal against this decision before the Third Instance Court.

(v) Algeria – Corruption investigation. Authorities in Italy and in other countries are investigating allegations of corrupt payments that would have occurred in Algeria in connection with the award of certain contracts to Saipem. On February 4, 2011, Eni received from the Public Prosecutor of Milan an information request pursuant to Article 248 of the Italian Code of Criminal Procedure. The notification was then forwarded to Eni’s subsidiary Saipem SpA since this matter is primarily in its area of responsibility. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem and Technip relating to the engineering of the ground section of a gas pipeline). The crime of international corruption is among the offenses contemplated by Legislative Decree of June 8, 2001, No. 231, relating to corporate responsibility for crimes committed by employees. Saipem promptly began to collect documentation in response to the requests of the Public Prosecutor. The documents were produced on February 16, 2011. Eni also filed documentation relating to the MLE project (in which the Eni’s Exploration & Production Division participates), with respect to which investigations in Algeria are ongoing. On November 22, 2012, the Public Prosecutor of Milan served Saipem a notice stating that it had commenced an investigation for alleged liability of the Company for international corruption in accordance to Article 25, second and third paragraph of Legislative Decree No. 231/2001. Furthermore the prosecutor requested the production of certain documents relating to certain activities in Algeria. Subsequently, on November 30, 2012, Saipem was served a notice of seizure, then, on December 18, 2012, a request for documentation and finally, on January 16, 2013, a search warrant was issued, in order to acquire further documentation. On February 7, 2013, on mandate from the Public Prosecutor of Milan, the Italian financial police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced in accordance with Article 25, third and fourth paragraph of Legislative Decree No. 231/2001 with respect to Eni, Eni’s CEO, Eni’s former CFO, and another senior manager. The investigation relates to alleged corruption which, according to the Public Prosecutor, had occurred with regard to certain contracts awarded to Saipem in Algeria up until March 2010. The former CEO and the former COO of the business unit Engineering & Construction of Saipem, as well as other Saipem employees and former employees are under investigation. Saipem has promptly undertaken management and administrative changes, irrespective of any liability that might result from the investigations. Saipem has commenced an internal investigation in relation to the contracts in question with the support of external advisors; such internal investigation is conducted in agreement with the statutory bodies deputed to the Company’s control and the Italian Public Prosecutor has been informed of this internal investigation. In addition, Saipem has commenced a review aiming at verifying the correct application of internal procedures and controls relating to anti-corruption and prevention of illicit activities, with the assistance of external consultants. The evaluation is ongoing. Saipem is cooperating with the Italian Judicial Authority. Eni has commenced its own evaluation which is ongoing.

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The above mentioned proceeding has been unitized in Italy with another proceeding relating to certain Eni’s activities performed in Iraq and Kazakhstan (see below). Investigations are also ongoing in Algeria where the bank accounts of a Saipem’s subsidiary, Saipem Contracting Algérie SpA, have been blocked by the Algerian Authorities. Currently two bank accounts with a balance equivalent to euro 79 million are blocked as of January 25, 2013. In September 2012, a notice of investigation was served to Saipem Contracting Algérie SpA. Saipem Contracting Algérie SpA is alleged to have taken advantage of the authority or influence of representatives of a government owned industrial and trading company in order to inflate prices in relation to contracts awarded by said company. On January 30, 2013, the Judicial Authority in Algeria ordered Saipem’s Algerian subsidiary to stand trial and reaffirmed the blockage of the above mentioned bank accounts. Saipem Contracting Algérie SpA has lodged an appeal against this decision before the Supreme Court. On March 24, 2013, relevant authorities executed searches on Saipem Contracting Algérie SpA headquarters.

(vi) Libya. On June 10, 2011, Eni received by the U.S. SEC a formal judicial request of collection and presentation of documents (subpoena) related to Eni’ s activity in Libya from 2008 until now. The subpoena is related to an ongoing investigation without further clarifications nor specific alleged violations in connection to "certain illicit payments to Libyan officials" possibly violating the U.S. Foreign Corruption Practice Act. At the end of December 2011, Eni received a request for the collection of further documentation aiming at integrating the subpoena previously received. Documentation and information requested have been collected by the relevant company functions and then forwarded to the U.S. SEC. Following a number of contacts with the U.S. SEC, in a meeting on October 16, 2012, Eni legal team provided additional documentations and clarifications.

(vii) Iraq – Kazakhstan. A criminal proceeding is pending before the Public Prosecutor of Milan in relation to alleged crimes of international corruption involving Eni’s activities in Kazakhstan regarding the management of the Karachaganak plant and the Kashagan project, as well as handling of assignment procedures of work contracts by Agip KCO. The crime of "international corruption" is sanctioned, in accordance to the Italian criminal code, by Legislative Decree of June 8, 2001, No. 231, which holds legal entities liable for the crimes committed by their employees on their behalf. The Company has filed the documents collected and is fully collaborating with the Public Prosecutor. A number of managers and a former manager are involved in the investigation. The above mentioned proceeding has been reunified with another (the so-called "Iraq proceeding") regarding a parallel proceeding related to Eni’s activities in Iraq, disclosed in the following paragraphs. On June 21, 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were notified that a search warrant had been issued to search the offices and homes of certain employees of the Group and of certain third parties. In particular the homes and offices of an employee of Eni Zubair and a manager of Saipem were searched by the authorities. The accusation is of criminal conspiracy and corruption in relation with the activity of Eni Zubair in Iraq and of Saipem in the "Jurassic" project in Kuwait. The Public Prosecutor of Milan has associated Eni Zubair, Eni and Saipem with the accusations as a result of the alleged illicit actions of their employees. Eni considers those employees to have breached the Company's Code of Ethics. The Eni Zubair employee resigned and the Company, accepting the resignation, reserved the right to take action against the individual to defend its interests and subsequently commenced a legal action against the other persons mentioned in the seizure act. Notwithstanding that the Eni Group companies appear to be offended parties in respect of the illicit conduct under investigation, Eni SpA and Saipem SpA also received, at the same time the search warrant was issued, a notification pursuant to the Legislative Decree No. 231/2001. Eni SpA was notified by the Public Prosecutor of a request of extension of the preliminary investigations that has led up to the involvement of another employee as well as other suppliers in the proceeding. Eni performed a review of the whole matter also with the support of an external consulting firm which issued its final appraisal report on July 25, 2012. According to the opinion of its legal team, the Company’s watch structure and Internal Control Committee, Saipem too commenced through its Internal Audit department, an internal review about the project with the support of an external consultant. The Public Prosecutor of Milan requested Eni SpA to be debarred for one year and six months from performing any industrial activities involving the production sharing contract of 1997 with the Republic of Kazakhstan and in the subsequent administrative or commercial arrangements, or the prosecution of the mentioned activities under the supervision of a commissioner pursuant to Article 15 of the Legislative Decree No. 231/2001. In the hearing of May 29, 2012, Eni legal team have filed a defensive memorandum; on August 1, 2012, the Public Prosecutor filed further documentation supporting the request of precautionary measures. After the hearing of November 14, 2012, the decision of the Judge for Preliminary Investigation is still pending.

 

5. Tax Proceedings

ITALY

(i) Eni SpA. Dispute for the omitted payment of a municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. With a formal assessment presented in December 1999, the Municipality of Pineto (Teramo) claimed Eni SpA to have omitted payment of a municipal tax on real estate for the period from 1993 to 1998 on four oil platforms located in the Adriatic Sea which constitute municipal waters. Eni was requested to pay a total of approximately euro 17 million including interest and a fine. Eni filed a counterclaim stating that the

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sea where the platforms are located is not part of the municipal territory and the tax application as requested by the municipality lacked objective fundamentals. The claim has been accepted in the first two degrees of judgment at the Provincial and Regional Tax Commissions. However, the Supreme Degree Court overturned both judgments, declaring that a municipality can consider requesting a tax on real estate in the sea facing its territory and with the decision of February 2005 sent the proceeding to another section of the Regional Tax Commission in order to judge on the matters of the proceeding. This commission requested an independent consultant to assessing the tax and technical aspects of the matter. The independent consultant confirmed that Eni’s offshore installations lack any ground to be subject to the municipal tax that was claimed by the local municipality. Those findings were accepted by the Regional Tax Commission with a ruling made on January 19, 2009. On January 25, 2011, the Municipality notified to Eni an appeal to the Supreme Degree Court for the cancellation of the above mentioned sentence. Also on December 28, 2005, the Municipality of Pineto presented similar claims relating to the same Eni platforms for the years 1999 to 2004. The total amount requested was euro 25 million including interest and penalties. Eni filed a claim against this claim which was accepted by the First Degree Judge with a decision of December 4, 2007. Also a second degree court ruled in favor of Eni’s recourses with a sentence filed in June 2012. Terms are pending to file a counterclaim before a third degree court.

Similar formal assessments related to Eni oil and gas offshore platforms were presented by the Municipalities of Falconara Marittima, Tortoreto, Pedaso, and also from 2009 the Gela Municipality. The total amounts of those claims were approximately euro 7.5 million. The Company filed appeal against all those claims. A tax commission in Sicily ruled in favor of Eni accepting the recourse against the tax claims presented by the Municipality of Gela.

 

OUTSIDE ITALY

(i) Eni Angola Production BV. In 2009, the Ministry of the Finance of Angola, following a fiscal audit, filed a notice of tax assessment for fiscal years 2002 to 2007 in which it claimed the improper deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as co-operator of the Cabinda concession. The Company filed an appeal against this decision. The judgment is still pending before the Supreme Court. Eni accrued a provision with respect to this proceeding.

(ii) Eni’s subsidiary in Indonesia. A tax proceeding is pending against Eni’s subsidiary Lasmo Sanga Sanga Ltd as the Tax Administration of Indonesia has questioned the application of a tax rate of 10% on the profit earned by the local branch of Eni’s subsidiary for fiscal years 2002 through 2009. Eni’s subsidiary, which is resident in the UK for tax purposes, believes that the 10% tax rate is warranted by the current treaty for the avoidance of double taxation. On the contrary, the Tax Administration of Indonesia has claimed the application of the local tax rate of 20%. The greater taxes due in accordance to the latter rate have been disbursed amounting to $130 million including interest expense. Eni’s subsidiary has filed an appeal claiming the opening of an amicable procedure to settle the matter and avoid bearing a tax regime not in compliance with the UK/Indonesia treaty.

 

6. Settled legal proceedings

(i) Summon before the Court of Venice for environmental damages allegedly caused to the lagoon of Venice by the Porto Marghera plants. The proceeding was settled due to the transaction agreement incurred between Syndial and the Province of Venice. The amount paid for the settlement of the proceeding is immaterial.

(ii) Syndial SpA (former EniChem SpA). Alleged pollution caused by the activity of the Mantova plant. Following the transaction agreement incurred in July 2012, between the Ministry for the Environment and Syndial for the repayment of the environmental damage related to the contamination caused by the water discharges of the Mantova plant, the proceeding could be considered virtually settled. The amount paid for the settlement of the proceeding is immaterial.

(iii) Karachaganak. On December 14, 2011, the international companies operating the Karachaganak field, including Eni which co-operates the field, and the Republic of Kazakhstan signed a settlement agreement of a contractual claim on cost recovery, including certain tax disputes. In particular, the Kazakh Tax Authorities claimed that Agip Karachaganak BV and Karachaganak Petroleum Operating BV, shareholder and operator of the Karachaganak contract, respectively, omitted payment of income taxes and other tax items for the period 2000-2009. Then, Kazakh Authorities notified a claim on the recovery of expenditures incurred by the operating company in the period 2003-2009. The agreement became effective on June 28, 2012.

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Assets under concession arrangements
Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing segment. In the Exploration & Production segment contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each Country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. As a compensation for mineral concessions, Eni pays royalties and taxes in accordance with local tax legislation. Eni sustains all the operation risks and costs related to the exploration and development activities and it is entitled to the productions realized. In Production Sharing Agreement and in buy-back contracts, realized productions 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 the own portion of the realized productions (profit oil). In the Refining & Marketing segment several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. Such assets are amortized over the length of the concession (generally, 5 years for Italy). In exchange of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties on the basis of quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession. Assets under concessions relating to natural gas storage in Italy and to the gas distribution of the Gas & Power segment pertained to Snam Group that was deconsolidated following the sale of control.

Environmental regulations
Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in "Financial Review", paragraph "Risk factors and uncertainties". In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s consolidated financial statements, taking account of ongoing remedial actions, existing insurance policies and the environmental risk provision accrued in the consolidated financial statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of the ongoing surveys and the other possible effects of statements required by Legislative Decree No. 152/2006 of the Ministry for the Environment; (iii) new developments in environmental regulation; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

Emission trading
Legislative Decree No. 216 of April 4, 2006 implemented the Emission Trading Directive 2003/87/EC concerning greenhouse gas emissions and Directive 2004/101/EC concerning the use of carbon credits deriving from projects for the reduction of emissions based on the flexible mechanisms devised by the Kyoto Protocol. This European emission trading scheme has been in force since January 1, 2005, and on this matter, on November 27, 2008, the National Committee for Emissions Trading Scheme (Ministry for the Environment-Mse) published the Resolution No. 20/2008 defining emission permits for the 2008-2012 period. Eni was assigned permits corresponding to 122.9 mmtonnes of carbon dioxide (of which, 24.9 in 2008, 24.9 in 2009, 24.6 in 2010, 24.4 in 2011, 24.1 in 2012) and in addition to approximately 3.3 million of permits expected to be assigned with respect to new plants in the five-year period 2008-2012. Emission quotas of new plants include only those physically assigned and recorded in the emissions registry. Emissions of carbon dioxide from Eni’s plants were lower than permits assigned in 2012. Against emissions of carbon dioxide amounted to approximately 22.1 mmtonnes, emission permits amounting to 25.0 million tonnes were assigned (including the permits assigned with respect to new plants), determining a 2.9 mmtonnes surplus not recognized as asset in the balance sheet.

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35 Revenues

Net sales from operations

(euro million)		2010		2011		2012

Net sales from operations		96,958			107,248		126,482
Change in contract work in progress		(341	)		442		738
		96,617			107,690		127,220

Net sales from operations were stated net of the following items:

(euro million)		2010		2011		2012

Excise taxes		11,785		11,863		13,308
Exchanges of oil sales (excluding excise taxes)		1,868		2,470		2,177
Services billed to joint venture partners		2,996		3,375		4,422
Sales to service station managers for sales billed to holders of credit cards		2,150		1,810		2,010
Exchanges of other products		79		9
		18,878		19,527		21,917

Net sales from operations of euro 126,482 million included revenues recognized in connection with contract works in the Engineering & Construction segment for euro 10,914 million (euro 8,779 million and euro 10,510 million in 2010 and 2011, respectively).

Net sales from operations by industry segment and geographic area of destination are disclosed in note 41 – Information by industry segment and geographic financial information.

Net sales from operations with related parties are disclosed in note 42 – Transactions with related parties.

Other income and revenues

(euro million)		2010		2011		2012

Gains from sale of assets		262		97		701
Lease and rental income		83		96		94
Contract penalties and other trade revenues		43		21		69
Gains on price adjustments under overlifting/underlifting transactions		50		99		67
Compensation for damages		46		66		56
Other proceeds (*)		483		547		559
		967		926		1,546

(*)		Each individual amount included herein was lower than euro 50 million.

Gains from the sale of assets of euro 701 million included euro 678 million of gains relating to the Exploration & Production segment.

Other income and revenues with related parties are disclosed in note 42 – Transactions with related parties.

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36 Operating expenses

Purchase, services and other

(euro million)		2010		2011		2012

Production costs - raw, ancillary and consumable materials and goods		48,407			60,826			74,767
Production costs - services		14,939			13,551			15,354
Operating leases and other		2,997			3,045			3,434
Net provisions for contingencies		1,401			527			871
Other expenses		1,252			1,140			1,342
		68,996			79,089			95,768
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(159	)		(226	)		(326	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(63	)		(68	)		(79	)
		68,774			78,795			95,363

Services included brokerage fees related to the Engineering & Construction segment for euro 6 million (euro 26 million and euro 12 million in 2010 and 2011, respectively).

Costs incurred in connection with research and development activity recognized in profit and loss amounted to euro 211 million (euro 218 million and euro 190 million in 2010 and 2011, respectively) as they did not meet the requirements to be recognized as long-lived assets.

Operating leases and other comprised operating leases for euro 1,432 million (euro 1,388 million and euro 1,295 million in 2010 and 2011, respectively) and royalties on the extraction of hydrocarbons for euro 1,555 million (euro 1,214 million and euro 1,295 million in 2010 and 2011, respectively).

Other expenses of euro 1,342 million included losses on disposal of tangible and intangible assets for euro 158 million.

Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below:

(euro million)		2010		2011		2012

To be paid within 1 year		1,022		838		722
Between 2 and 5 years		2,276		1,380		1,289
Beyond 5 years		751		254		560
		4,049		2,472		2,571

Operating leases primarily regarded drilling rigs, 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 may limit the ability of Eni to pay dividends, use assets or take on new borrowings.

Risk provisions net of reversal of unused provisions amounted to euro 871 million (euro 1,401 million and euro 527 million in 2010 and 2011, respectively) and mainly related to price revisions at certain gas purchase and sale long-term contracts also subjected to arbitration procedures of euro 496 million (net reversals of euro 182 million in 2010 and net provisions of euro 144 million in 2011) and environmental liabilities amounting to euro 67 million (net provisions of euro 1,344 million and euro 174 million in 2010 and 2011, respectively). More information is provided in note 27 – Provisions for contingencies.

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Payroll and related costs

(euro million)		2010		2011		2012

Wages and salaries		3,299			3,435			3,886
Social security contributions		631			675			674
Cost related to employee benefits plans		154			148			148
Other costs		557			334			187
		4,641			4,592			4,895
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(168	)		(144	)		(182	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(45	)		(44	)		(55	)
		4,428			4,404			4,658

Other costs of euro 187 million (euro 557 million and euro 334 million in 2010 and 2011, respectively) comprised costs for defined contribution plans of euro 100 million (euro 95 million and euro 94 million in 2010 and 2011, respectively) and provisions for redundancy incentives of euro 64 million (euro 400 million and euro 203 million in 2010 and 2011, respectively).

Cost related to employee benefit plans are described in note 28 – Provisions for employee benefits.

Average number of employees
The Group average number and break-down of employees by category is reported below:

(number)		2010		2011		2012

Senior managers		1,446		1,461		1,471
Junior managers		12,616		12,796		12,976
Employees		34,265		35,309		37,258
Workers		24,288		23,605		23,501
		72,615		73,171		75,206

The average number of employees was calculated as average between the number of employees at the beginning and end of the period. The average number of senior managers included managers employed and operating in foreign subsidiaries, whose responsibility and position are comparable to those of a senior manager.

Stock-based compensation
In 2009, Eni terminated any stock-based incentive schemes. Information provided below is about the residual activity of past stock incentive schemes.

Stock options plans outstanding as of December 31, 2012 entitled Eni’s Group companies top managers and managers with strategic responsibilities (excluding Group listed subsidiaries) to no consideration grants to purchase treasury shares with a 1 to 1 ratio. The strike price was determined as arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the grant date or the average carrying amount of treasury shares as of the day preceding the grant, if greater.

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At December 31, 2012, 8,259,520 options were outstanding for the purchase of 8,259,520 Eni ordinary shares (no par value). The break-down of outstanding options was the following:

		Rights outstanding as of Dec. 31, 2012 (number)		Weighted-average strike price of rights outstanding as of Dec. 31, 2012 (euro)

Stock option plan 2005		3,281,500		22.514
Stock option plan 2007		1,707,720		27.451
Stock option plan 2008		3,270,300		22.540
		8,259,520

At December 31, 2012, the residual life of the stock option plans were 7 months for the 2005 plan, 7 months for the 2007 plan and 1 year and 7 months for the 2008 plan.

The scheme evolution is provided below:

		2010		2011		2012

Number of shares

Average strike price (euro)

Market price (a) (euro)

Number of shares

Average strike price (euro)

Market price (a) (euro)

Number of shares

Average strike price (euro)

Market price (a) (euro)

Rights outstanding as of January 1		19,482,330			23.576		17.811		15,737,120			23.005		16.398		11,873,205			23.101		15.941
Rights exercised in the period		(88,500	)		14.941		16.048		(208,900	)		14.333		16.623		(93,000	)		16.576		16.873
Rights cancelled in the period		(3,656,710	)		26.242		16.918		(3,655,015	)		23.187		17.474		(3,520,685	)		22.233		16.637
Rights outstanding as of December 31		15,737,120			23.005		16.398		11,873,205			23.101		15.941		8,259,520			23.545		18.457
of which exercisable as of December 31		8,896,125			23.362		16.398		11,863,335			23.101		15.941		8,243,205			23.544		18.457

The fair value of stock options granted during the year 2005 was euro 3.33 per share. For 2007 and 2008 the average fair value weighted with the number of options granted was euro 2.98 and euro 2.60 per share, respectively.

The fair value was determined by applying the following assumptions:

		2005		2007		2008

Risk-free interest rate	(%)		2.5		4.7		4.9
Expected life	(years)		8		6		6
Expected volatility	(%)		21.0		16.3		19.2
Expected dividends	(%)		4.0		4.9		6.1

Costs of the year related to stock option plans amounted to euro 12 million and euro 3 million in 2010 and 2011, respectively, and no costs in 2012.

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Compensation of key management personnel
Compensation of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office at end of each year amounted (including contributions and ancillary costs) to euro 33 million, euro 34 million and euro 33 million for 2010, 2011 and 2012, respectively, and consisted of the following:

(euro million)		2010		2011		2012

Wages and salaries		20		21		21
Post-employment benefits		1		1		1
Other long-term benefits		10		10		11
Indemnities upon termination of employment				2
Stock options		2
		33		34		33

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 9.7 million, euro 8.4 million and euro 13.2 million for 2010, 2011 and 2012, respectively. Compensation of Statutory Auditors amounted to euro 0.511 million, euro 0.513 million and euro 0.467 million in 2010, 2011 and 2012, respectively.

Compensations included emoluments and social security benefits due for the office as director or statutory auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as cost to the Group, even if not subjected to personal income tax.

 

Other operating income (loss)

(euro million)		2010		2011		2012

Net gains (losses) on non-hedging and trading derivatives		118			188			(153	)
Net gains (losses) on fair value hedging derivatives								(4	)
Net gains (losses) on cash flow hedging derivatives		13			(17	)		(1	)
		131			171			(158	)

Net losses on trading and non-hedging derivatives related to: (i) gains and losses on fair value measurement and settlement of commodity derivatives entered into by the Gas & Power segment to optimize commercial margins and by Eni Trading & Shipping SpA for trading activities (net loss of euro 13 million); (ii) gains and losses on fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk (net loss of euro 141 million); and (iii) fair value evaluation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts in the Exploration & Production segment (net gain of euro 1 million).

Net losses on fair value hedging derivatives related to hedging operations entered into during the 2012 for the pricing of future oil purchase and sale contracts.

Net losses on cash flow hedging derivatives related to the ineffective portion of the hedging relationship which was recognized through profit and loss in the Gas & Power segment.

Operating costs are disclosed in note 42 – Transactions with related parties.

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Depreciation, depletion, amortization and impairments

(euro million)		2010		2011		2012

Depreciation, depletion and amortization:
- tangible assets		6,775			6,178			7,335
- intangible assets		1,572			1,582			2,208
		8,347			7,760			9,543
Impairments:
- tangible assets		257			891			1,609
- intangible assets		431			154			2,417
		688			1,045			4,026
less:
- reversal of impairments - tangible assets					(15	)		(3	)
- capitalized direct costs associated with self-constructed assets - tangible assets		(2	)		(3	)		(1	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(2	)		(2	)		(4	)
		9,031			8,785			13,561

Depreciation, depletion, amortization and impairments by industry segment are disclosed in note 41 – Information by industry segment and geographic financial information.

37 Finance income (expense)

(euro million)		2010		2011		2012

Finance income (expense)
Finance income		6,109			6,376			7,218
Finance expense		(6,727	)		(7,410	)		(8,274	)
		(618	)		(1,034	)		(1,056	)
Gain (loss) on derivative financial instruments		(131	)		(112	)		(251	)
		(749	)		(1,146	)		(1,307	)

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The break-down by lenders or type of net finance gains or losses is provided below:

(euro million)		2010		2011		2012

Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(551	)		(610	)		(729	)
Interest due to banks and other financial institutions		(214	)		(312	)		(251	)
Interest from banks		17			22			27
Interest and other income on financing receivables and securities held for non-operating purposes		18			19			24
		(730	)		(881	)		(929	)
Exchange differences
Positive exchange differences		5,897			6,191			7,010
Negative exchange differences		(5,805	)		(6,302	)		(6,879	)
		92			(111	)		131
Other finance income (expense)
Capitalized finance expense		150			112			150
Interest and other income on financing receivables and securities held for operating purposes		73			75			69
Finance expense due to passage of time (accretion discount) (a)		(236	)		(235	)		(308	)
Other finance income (expense), net		33			6			(169	)
		20			(42	)		(258	)
		(618	)		(1,034	)		(1,056	)

Derivative financial instruments consisted of the following:

(euro million)		2010		2011		2012

Derivatives on exchange rate		(111	)		29			(137	)
Derivatives on interest rate		(39	)		(141	)		(88	)
Options		19						(26	)
		(131	)		(112	)		(251	)

Net losses from derivatives of euro 251 million (a net loss of euro 131 million and euro 112 million in 2010 and 2011, respectively) were recognized in connection with fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. The lack of formal requirements to qualify these derivatives as hedges under IFRS also entailed the recognition in profit or loss of currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments. Loss on options of euro 26 million related to the measurement at fair value of the options embedded in the bonds convertible into ordinary shares of Galp Energia SGPS SA (more information is provided in note 26 – Long-term debt and current maturities of long-term debt).

More information is provided in note 42 – Transactions with related parties.

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38 Income (expense) from investments

Share of profit (loss) of equity-accounted investments

(euro million)		2010		2011		2012

Share of profit of equity-accounted investments		673			634			526
Share of loss of equity-accounted investments		(149	)		(106	)		(233	)
Decreases (increases) in the provision for losses on investments		(31	)		(28	)		(15	)
		493			500			278

More information is provided in note 17 – Equity-accounted investments.

Share of profit (loss) of equity-accounted investments by industry segment is disclosed in note 41 – Information by industry segment and geographic financial information.

 

Other gain (loss) from investments

(euro million)		2010		2011		2012

Dividends		264			659			431
Gains on disposals, net		332			1,121			349
Other income (expense), net		23			(157	)		1,823
		619			1,623			2,603

Dividend income for euro 431 million primarily related to the Nigeria LNG Ltd (euro 331 million).

Net gains on disposals for 2012 amounted to euro 349 million and related for euro 311 million to Galp Energia SGPS SA as Eni divested 5% of the share capital of the investee to Amorim Energia BV and a further 4% through an accelerated book-building procedure to institutional investors. Net gains on disposals for 2011 amounted to euro 1,121 million and pertained to the divestment of the 100% interest in Eni Gas Transport International SA (euro 647 million), the 89% interest (entire stake own) in Trans Austria Gasleitung GmbH (euro 338 million), the 100% interest in Gas Brasiliano Distribuidora SA (euro 50 million) and the 46% interest (entire stake own) in Transitgas AG (euro 34 million). Gains on disposals for 2010 of euro 332 million essentially pertained to the divestment of the 100% interest in Società Padana Energia SpA (euro 169 million), the 25% stake in GreenStream BV (euro 93 million) and the 100% interest in Distri RE SA (euro 47 million).

In 2012, other net income of euro 1,823 million included: (i) an extraordinary income of euro 835 million recognized in connection with a capital increase made by Galp’s subsidiary Petrogal whereby a new shareholder subscribed its share by contributing a cash amount fairly in excess of the net book value of the interest acquired; (ii) a revaluation gain of euro 865 million of the interest in Galp Energia SGPS SA (28.34%) measured at fair value at the price current at the date when Eni ceased to retain a significant influence over the investee and a gain on the re-measurement at market fair value at the balance sheet date of euro 65 million of part of residual interest in Galp Energia SGPS SA (8%) which was underlying a convertible bond based on the fair value option provided by IAS 39; and (iii) the re-measurement at market fair value at the balance sheet date of 288.7 million shares of Snam SpA underlying a convertible bond issued on January 15, 2013 for which was applied the fair value option (income for euro 6 million). In 2011, other net expense of euro 157 million included the full write down of the book value of the Ceska Rafinerska AS due to management’s expectations of incurring future losses driven by a negative outlook in the refining segment (euro 157 million).

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39 Income taxes

(euro million)		2010		2011		2012

Current taxes:
- Italian subsidiaries		696			620			755
- foreign subsidiaries of the Exploration & Production segment		7,893			8,286			10,214
- foreign subsidiaries		521			635			455
		9,110			9,541			11,424
Net deferred taxes:
- Italian subsidiaries		(431	)		(418	)		376
- foreign subsidiaries of the Exploration & Production segment		(97	)		936			127
- foreign subsidiaries		(1	)		(156	)		(268	)
		(529	)		362			235
		8,581			9,903			11,659

Income taxes currently payable by Italian subsidiaries amounted to euro 755 million and were in respect of the Italian corporate taxation (Ires for euro 525 million and Irap for euro 142 million) and foreign taxes on the share of profit earned outside Italy for euro 88 million.

The effective tax rate was 70.2% (54.2% and 55.7% in 2010 and 2011, respectively) compared with a statutory tax rate of 43.9% (39.6% and 43.1% in 2010 and 2011, respectively). This was calculated by applying the Italian statutory tax rate on corporate profit of 38.0%¹⁹ and a 3.9% corporate tax rate applicable to the net value of production as provided for by Italian laws.

The difference between the statutory and effective tax rate was due to the following factors:

(%)		2010		2011		2012

Statutory tax rate		39.6			43.1			43.9
Items increasing (decreasing) statutory tax rate:
- higher foreign subsidiaries tax rate		15.6			12.7			16.9
- impact pursuant to the write down of deferred tax assets of Italian subsidiaries								7.7
- impact pursuant to the Italian Windfall Corporate tax as per Law No. 7/2009		1.5			1.0			1.5
- permanent differences and other adjustments		(2.5	)		(1.1	)		0.2
		14.6			12.6			26.3
		54.2			55.7			70.2

The increased tax rate at foreign subsidiaries primarily related to 17.8 percentage points increase in the Exploration & Production segment (16.8 and 17.2 percentage points in 2010 and 2011, respectively).

A write down of deferred tax assets impacted the Group tax rate by 7.7 percentage points and was recorded by the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes. Such write down reflected a lower likelihood that those deferred tax assets can be recovered in future periods due to an expected reduction in taxable income generated in Italy, and as Eni has lost the availability of Snam taxable profit against which Italian tax assets can be utilized following the deconsolidation of Snam.

In 2012, the increase in permanent differences and other adjustments of 0.2 percentage points comprised an effect of 3.3 percentage points due to a non-deductible impairment of the goodwill allocated to the European gas market CGU and a negative effect of 4.5 percentage points due to non-taxable gains on the sale and revaluation relating to the transactions at Galp Energia SGPS SA. In 2011, the decrease for permanent differences and other adjustments of 1.1 percentage points were due to a non-deductible provision accrued to reflect the expected loss deriving from an antitrust proceeding in the European sector of rubbers (0.2 percentage points). In 2010, the

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decrease for permanent differences and other adjustments of 2.5 percentage points was due to a gain which was excluded from taxable profit relating a favorable outcome of an antitrust proceeding of 0.7 percentage points.

Income tax expense related to discontinued operations, included in the item "Net profit (loss)" of the profit and loss account, consisted of the following:

(euro million)		2010		2011		2012

Current taxes:
- Italian subsidiaries		619			788			489
		619			788			489
Net deferred taxes:
- Italian subsidiaries		(43	)		(17	)		124
		(43	)		(17	)		124
		576			771			613

Discontinued operations are disclosed in note 31 – Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale.

40 Earnings per share

Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.

The average number of ordinary shares used for the calculation of the basic earnings per share outstanding at December 31, 2010, 2011 and 2012, was 3,622,454,738, 3,622,616,182 and 3,622,764,007, respectively.

Diluted earnings per share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of shares fully-diluted including shares outstanding in the year including the number of potential shares outstanding in connection with stock-based compensation plans.

At December 31, 2010, 2011 and 2012 the number of potential shares outstanding related to stock options plans. The average number of fully-diluted shares used in the calculation of diluted earnings was 3,622,469,713, 3,622,616,182 and 3,622,764,007 for the years ending December 31, 2010, 2011 and 2012, respectively.

Reconciliation of the average number of shares used for the calculation for both basic and diluted earning per share was as follows:

		2010		2011		2012

Average number of shares used for the calculation of the basic earnings per share				3,622,454,738		3,622,616,182			3,622,764,007
Number of potential shares following stock options plans				14,975
Average number of shares used for the calculation of the diluted earnings per share				3,622,469,713		3,622,616,182			3,622,764,007
Eni’s net profit		(euro million)		6,318		6,860			7,788
Basic earning per share		(euro per share)		1.74		1.89			2.15
Diluted earning per share		(euro per share)		1.74		1.89			2.15
Eni’s net profit - Continuing operations		(euro million)		6,252		6,902			4,198
Basic earning per share		(euro per share)		1.72		1.90			1.16
Diluted earning per share		(euro per share)		1.72		1.90			1.16
Eni’s net profit - Discontinued operations		(euro million)		66		(42	)		3,590
Basic earning per share		(euro per share)		0.02		(0.01	)		0.99
Diluted earning per share		(euro per share)		0.02		(0.01	)		0.99

 

 

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41 Information by industry segment and geographic financial information

Information by industry segment

		Other activities (d)		Discontinued operations (d)

(euro million)

Exploration & Production

Gas & Power (d)

Refining & Marketing

Chemicals

Engineering & Construction

Corporate and financial companies

Snam

Others

Intragroup profits

Total

Snam

Intragroup eliminations

Continuing operations

2010
Net sales from operations (a)		29,497			27,806			43,190			6,141			10,581			1,386			3,526			105			100
Less: intersegment sales		(16,550	)		(969	)		(1,345	)		(243	)		(1,802	)		(1,255	)		(1,620	)		(25	)
Net sales to customers		12,947			26,837			41,845			5,898			8,779			131			1,906			80			100			98,523			(1,906	)					96,617
Operating profit		13,866			896			149			(86	)		1,302			(361	)		2,000			(1,384	)		(271	)		16,111			(2,000	)		1,371			15,482
Net provisions for contingencies		33			(64	)		199			2			35			50			6			1,146						1,407			(6	)					1,401
Depreciation, depletion, amortization and impairments		7,051			851			409			135			516			79			548			10			(20	)		9,579			(548	)					9,031
Share of profit (loss) of equity-accounted investments		92			344			68			1						(10	)		44			(2	)					537			(44	)					493
Identifiable assets (b)		49,573			18,300			14,356			3,076			12,715			754			16,643			362			(917	)		114,862
Unallocated assets																													16,998
Equity-accounted investments		1,974			1,988			1,058			30			174			8			382			54						5,668
Identifiable liabilities (c)		12,330			7,593			6,197			874			5,760			1,307			2,455			2,898			(101	)		39,313
Unallocated liabilities																													36,819
Capital expenditures		9,690			265			711			251			1,552			109			1,420			22			(150	)		13,870
2011
Net sales from operations (a)		29,121			33,093			51,219			6,491			11,834			1,365			3,591			85			(54	)
Less: intersegment sales		(18,444	)		(1,344	)		(2,791	)		(289	)		(1,324	)		(1,249	)		(1,692	)		(23	)
Net sales to customers		10,677			31,749			48,428			6,202			10,510			116			1,899			62			(54	)		109,589			(1,899	)					107,690
Operating profit		15,887			(326	)		(273	)		(424	)		1,422			(319	)		2,084			(427	)		(189	)		17,435			(2,084	)		1,452			16,803
Net provisions for contingencies		53			113			57			11			79			13			24			201						551			(24	)					527
Depreciation, depletion, amortization and impairments		6,440			567			839			250			631			75			533			6			(23	)		9,318			(533	)					8,785
Share of profit (loss) of equity-accounted investments		119			232			100						95			(1	)		44			(45	)					544			(44	)					500
Identifiable assets (b)		56,139			18,708			15,031			3,066			13,521			810			17,649			378			(1,060	)		124,242
Unallocated assets																													18,703
Equity-accounted investments		2,317			1,990			890			38			179			7			385			37						5,843
Identifiable liabilities (c)		13,844			8,428			5,972			761			5,437			1,095			2,465			3,020			(54	)		40,968
Unallocated liabilities																													41,584
Capital expenditures		9,435			192			866			216			1,090			128			1,529			10			(28	)		13,438
2012
Net sales from operations (a)		35,881			36,200			62,656			6,418			12,771			1,369			2,646			119			(75	)
Less: intersegment sales		(20,322	)		(2,031	)		(2,966	)		(411	)		(1,107	)		(1,242	)		(1,274	)		(40	)
Net sales to customers		15,559			34,169			59,690			6,007			11,664			127			1,372			79			(75	)		128,592			(1,372	)					127,220
Operating profit		18,451			(3,221	)		(1,303	)		(683	)		1,433			(345	)		1,676			(302	)		208			15,914			(1,676	)		788			15,026
Net provisions for contingencies		41			471			93			22			36			140			72			68						943			(72	)					871
Depreciation, depletion, amortization and impairments		8,535			2,899			1,174			202			708			65			284			3			(25	)		13,845			(284	)					13,561
Share of profit (loss) of equity-accounted investments		39			144			40			2			55			(1	)		38			(1	)					316			(38	)					278
Identifiable assets (b)		59,128			19,736			14,818			3,151			14,430			966						474			(776	)		111,927
Unallocated assets																													27,714
Equity-accounted investments		2,162			1,550			274			50			187			6						36						4,265
Identifiable liabilities (c)		15,921			10,195			6,203			733			5,169			1,161						2,946			21			42,349
Unallocated liabilities																													34,579
Capital expenditures		10,307			225			842			172			1,011			152			756			14			38			13,517

Environmental provisions incurred by Eni SpA due to intercompany guarantees on behalf of Syndial have been reported within the segment reporting unit "Other activities".

Intersegment revenues are conducted on arm’s length basis.

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Geographic financial information

Identifiable assets and investments by geographic area of origin

(euro million)

Italy

Other European Union

Rest of Europe

Americas

Asia

Africa

Other areas

Total

2010
Identifiable assets (a)		45,342		16,322		5,091		6,837		12,459		27,322		1,489		114,862
Capital expenditures		3,044		1,710		724		1,156		1,941		5,083		212		13,870
2011
Identifiable assets (a)		47,908		16,196		6,763		7,465		14,077		29,942		1,891		124,242
Capital expenditures		3,587		1,337		1,174		978		1,608		4,369		385		13,438
2012
Identifiable assets (a)		31,406		15,013		10,479		7,167		14,828		31,224		1,810		111,927
Capital expenditures		2,886		1,255		1,630		1,184		1,663		4,725		174		13,517

Sales from operations by geographic area of destination

(euro million)		2010		2011		2012

Italy		45,896		31,906		33,998
Other European Union		21,125		35,536		35,578
Rest of Europe		4,172		7,537		9,940
Americas		6,282		9,612		15,282
Asia		5,785		10,258		16,394
Africa		13,068		11,333		14,681
Other areas		289		1,508		1,347
		96,617		107,690		127,220

42 Transactions with related parties

In the course of 2012, Eni finalized a single transaction of major importance with related parties, as defined by Eni’s internal procedure and in application of the Consob Regulation No. 17221 of March 12, 2010, later modified by Decision No. 17389 of June 2010. Such transaction referred to the sale of 30% less one share of the outstanding shares of Snam SpA to Cassa Depositi e Prestiti SpA formalized on October 15, 2012. Complete information about the transaction is disclosed in the Information Statement, published on June 6, 2012 (and available at the Eni website eni.com) in application of the Consob Regulation No. 11971 of May 14, 1999 and later additions and modifications. More information is disclosed in note 17 – Investments.

In the ordinary course of its business Eni enters into transactions regarding:

(a)		exchanges of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries;
(b)		exchanges of goods and provision of services with entities controlled by the Italian Government; and
(c)		contributions to Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Transactions with Enrico Mattei Foundation were not material.

Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities with the aim to develop solidarity, culture and research initiatives, on an arm’s length basis.

Related-party trade and other transactions
Trade and other transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities controlled by the Italian Government in the 2010, 2011 and 2012, respectively, consisted of the following:

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2010 (euro million)		Dec. 31, 2010		2010

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Other operating (expense) income

Continuing operations
Joint ventures and associates
ACAM Clienti SpA		14		2				1		5				56
Agiba Petroleum Co		2		5						95
Azienda Energia e Servizi Torino SpA		1		65						78
Bayernoil Raffineriegesellschaft mbH				32		1		19		51				2
Blue Stream Pipeline Co BV		13		14		37				152						2
Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG		20												121
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		28		12		6,054				5						37
CEPAV (Consorzio Eni per l’Alta Velocità) Due		6		3		76				3						6
Eni Gas & Power France SA (former Altergaz SA)														262
GasVersorgung Süddeutschland GmbH		3												62
GreenStream BV		4		13						95				1		2
Karachaganak Petroleum Operating BV		39		253				821		346		28		8		7
KWANDA - Suporte Logistico Lda		51		1												17
Mellitah Oil & Gas BV		30		137						225						33
Petrobel Belayim Petroleum Co		8		34						714						3		2
Raffineria di Milazzo ScpA		21		20						266				157		7		1
Rosa GmbH		7												50
Saipon Snc		2				53										29
Super Octanos CA				23				58						2
Supermetanol CA				13				57										1
Trans Austria Gasleitung GmbH		8		69				32		149				1		37
Transitgas AG				8						70
Unión Fenosa Gas SA		11				58								60				1
Other (*)		138		51		11		27		232		50		35		86		11
		406		755		6,290		1,015		2,486		78		817		266		16
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		177		285				2		894		5				917		7
Eni BTC Ltd						152
Other (*)		22		22		3		4		48		2		5		23		4
		199		307		155		6		942		7		5		940		11
		605		1,062		6,445		1,021		3,428		85		822		1,206		27
Entities controlled by the Government
Gruppo Enel		83		44				20		316		1		124		114
Gruppo Finmeccanica		44		44				50		36				22		9
GSE - Gestore Servizi Energetici		94		104				466				81		462		16				3
Gruppo Terna		35		41				115		71		31		55		28		9		38
Other (*)		62		44						74		2		44		3		21
		318		277				651		497		115		707		170		30		41
		923		1,339		6,445		1,672		3,925		200		1,529		1,376		57		41

Discontinued operations
Joint ventures and associates
Azienda Energia e Servizi Torino SpA																1
Other (*)																5		1
																6		1
Entities controlled by the Government
Gruppo Enel										2				4		357
Gruppo Finmeccanica										1
Other (*)												2				2
										3		2		4		359
										3		2		4		365		1
		923		1,339		6,445		1,672		3,928		202		1,533		1,741		58		41

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2011 (euro million)		Dec. 31, 2011		2011

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Other operating (expense) income

Continuing operations
Joint ventures and associates
ACAM Clienti SpA		14				2				6				60
Agiba Petroleum Co		3		5						86
Azienda Energia e Servizi Torino SpA		1		63						43
Bayernoil Raffineriegesellschaft mbH				33		1		25		59				2
Blue Stream Pipeline Co BV		8		12						146						2
Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG		16												147
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		42		10		6,074				4						21
CEPAV (Consorzio Eni per l’Alta Velocità) Due		24		91						84						38
GasVersorgung Süddeutschland GmbH		29												201
Gaz de Bordeaux SAS		11												69
Karachaganak Petroleum Operating BV		38		205				1,108		256		23		8		5
KWANDA - Suporte Logistico Lda		54		2						2						13
Mellitah Oil & Gas BV		28		141						71						3
Petrobel Belayim Petroleum Co		25		46						576						69
Petromar Lda		74		6		57				7						68
Raffineria di Milazzo ScpA		29		31						322				232		16		1
Saipon Snc		21				48										5
Super Octanos CA		6		35				58								7		1
Supermetanol CA				10				72										1
Trans Austria Gasleitung GmbH								33		160				3		54
Unión Fenosa Gas SA						58								130				1
Other (*)		181		100		3		37		310		70		131		89		7
		604		790		6,243		1,333		2,132		93		983		390		11
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		149		238						781		7				1,182		7
Eni BTC Ltd						157
Other (*)		53		68		6		11		51		3		11		11		8
		202		306		163		11		832		10		11		1,193		15
		806		1,096		6,406		1,344		2,964		103		994		1,583		26
Entities controlled by the Government
Gruppo Enel		83		48				5		429		1		33		85
Gruppo Finmeccanica		48		51				14		53				22		12
GSE - Gestore Servizi Energetici		149		158				615				54		607		10
Gruppo Terna		19		52				119		110		23		56		26		11		32
Other (*)		61		41				1		77		1		49				4
		360		350				754		669		79		767		133		15		32
		1,166		1,446		6,406		2,098		3,633		182		1,761		1,716		41		32

Discontinued operations
Joint ventures and associates
Azienda Energia e Servizi Torino SpA																1
Other (*)										1						4		1
										1						5		1
Entities controlled by the Government
Gruppo Enel												1				397		1
Gruppo Finmeccanica										1
Other (*)												4				3
										1		5				400		1
										2		5				405		2
		1,166		1,446		6,406		2,098		3,635		187		1,761		2,121		43		32

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2012 (euro million)		Dec. 31, 2012		2012

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Other operating (expense) income

Continuing operations
Joint ventures and associates
ACAM Clienti SpA		19		1		2								65		1
Agiba Petroleum Co		3		67						96
Azienda Energia e Servizi Torino SpA										86
Bayernoil Raffineriegesellschaft mbH				38		2		30		56				1
Blue Stream Pipeline Co BV		3		11						155						1
Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG		9												84
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		66		19		6,122				5						16
CEPAV (Consorzio Eni per l’Alta Velocità) Due		51		51						51						85
EnBW Eni Verwaltungsgesellschaft mbH		60												287
Gaz de Bordeaux SAS														56
GreenStream BV		9		21						121		1				1
InAgip doo		54		10						24				53		1
Karachaganak Petroleum Operating BV		28		56				1,331		244		14		5		8
KWANDA - Suporte Logistico Lda		54		1						2						7
Mellitah Oil & Gas BV		7		47						166				5		12
Petrobel Belayim Petroleum Co		31		328						585						79
Raffineria di Milazzo ScpA		20		9						365		4		218		7		1
Saipon Snc		112				42										25
Supermetanol CA				16				74										1
Toscana Energia SpA										86								1
Unión Fenosa Gas SA		2		3		57						6		120				1
Other (*)		155		30		47		15		145		8		149		100		5
		683		708		6,272		1,450		2,187		33		1,043		343		9
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		236		172						605		2				1,064		5
Eni BTC Ltd						154
Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation)		54		3												7		7
Other (*)		14		59		6		7		50		4		17		3		7
		304		234		160		7		655		6		17		1,074		19
		987		942		6,432		1,457		2,842		39		1,060		1,417		28
Entities controlled by the Government
Gruppo Enel		16		8				4		554				55		90		1		(7	)
Gruppo Finmeccanica		30		50				14		70				17		1
Gruppo Snam		182		482		46		13		558		2		102		26		1
GSE - Gestore Servizi Energetici		86		66				627				58		777		18		12
Gruppo Terna		47		61				166		126		12		95		67		14		17
Other (*)		42		29						59		24		57		1
		403		696		46		824		1,367		96		1,103		203		28		10
		1,390		1,638		6,478		2,281		4,209		135		2,163		1,620		56		10
Discontinued operations
Joint ventures and associates
Azienda Energia e Servizi Torino SpA																1		1
Toscana Energia SpA																1
Other (*)																1
																3		1
Entities controlled by the Government
Gruppo Enel										87						295
Other (*)												1				3		1
										87		1				298		1
										87		1				301		2
		1,390		1,638		6,478		2,281		4,296		136		2,163		1,921		58		10

 

Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned:

•		sale of natural gas and electricity to ACAM Clienti SpA;
•		sale of natural gas to EnBW Eni Verwaltungsgesellschaft mbH and Gaz de Bordeaux SAS;

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•		provisions of specialized services in upstream activities and Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Agip Kazakhstan North Caspian Operating Co NV, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co and, only for Karachaganak Petroleum Operating BV, purchase of oil products and to Agip Kazakhstan North Caspian Operating Co NV, provisions of services by the Engineering & Construction segment; services charged to Eni’s associates are invoiced on the basis of incurred costs;
•		gas and electricity transportation and distribution services from Azienda Energia e Servizi Torino SpA and Toscana Energia SpA;
•		payments of refining services to Bayernoil Raffineriegesellschaft mbH and Raffineria di Milazzo ScpA in relation to incurred costs;
•		acquisition of natural gas transport services outside Italy from Blue Stream Pipeline Co BV and GreenStream BV;
•		supply of oil products to Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG and Raffineria di Milazzo ScpA on the basis of prices referred to the quotations on international markets of the main oil products, as they would be conducted on an arm’s length basis;
•		transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Bologna with CEPAV (Consorzio Eni per l’Alta Velocità) Uno and related guarantees;
•		transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Verona with CEPAV (Consorzio Eni per l’Alta Velocità) Due;
•		transactions with InAgip doo related to the redetermination of the interest in an offshore field located in the Adriatic Sea;
•		guarantees issued on behalf Saipon Snc in relation to contractual commitments related to the execution of project planning and realization;
•		planning, construction and technical assistance to support by KWANDA - Suporte Logistico Lda;
•		acquisition of petrochemical products from Supermetanol CA on the basis of prices referred to the quotations on international markets of the main products;
•		performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and sales of LNG;
•		guarantees issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd; and
•		services for the environmental restoration to Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation).

The most significant transactions with entities controlled by the Italian Government concerned:

•		sales and transportation services of natural gas, the sale of fuel oil and the sale and purchase of electricity, the acquisition of electricity transmission service and the fair value of derivative financial instruments with Gruppo Enel;
•		a long-term contract for the maintenance at the Group’s combined-cycle power plants with Gruppo Finmeccanica;
•		acquisition of natural gas transportation, distribution and storage services from Gruppo Snam on the basis of tariffs set by the Authority for Electricity and Gas;
•		gas transportation and distribution services from Gruppo Snam on the basis of tariffs set by the Authority for Electricity and Gas;
•		supply of natural gas to Gruppo Snam on the basis of prices referred to the quotations of the main energy commodities, as they would be conducted on an arm’s length basis;
•		sale and purchase of electricity and green certificates with GSE - Gestore Servizi Energetici; and
•		sale and purchase of electricity, the acquisition of domestic electricity transmission service and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with Gruppo Terna.

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Related-party financing transactions
Financing transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities controlled by the Government in the 2010, 2011 and 2012, respectively, consisted of the following:

2010 (euro million)		Dec. 31, 2010		2010

Name

Receivables

Payables

Guarantees

Charges

Gains

Income from equity instruments

Joint ventures and associates
Artic Russia BV		104		3						1
Bayernoil Raffineriegesellschaft mbH		119
Blue Stream Pipeline Co BV				8		648				9
GreenStream BV		459		2						19
Raffineria di Milazzo ScpA						120
Trans Austria Gasleitung GmbH		144								6
Transmediterranean Pipeline Co Ltd		141								5
Other (*)		105		75		24
		1,072		88		792				40
Unconsolidated entities controlled by Eni
Other (*)		53		39		1				1
		53		39		1				1
		1,125		127		793				41

  

2011 (euro million)		Dec. 31, 2011		2011

Name

Receivables

Payables

Guarantees

Charges

Gains

Income from equity instruments

Joint ventures and associates
Artic Russia BV				3		204
Bayernoil Raffineriegesellschaft mbH		107
Blue Stream Pipeline Co BV				291		669				6
CEPAV (Consorzio Eni per l’Alta Velocità) Due						84
GreenStream BV		503		1						26
Raffineria di Milazzo ScpA		60				88				1
Société Centrale Electrique du Congo SA		93				6
Transmediterranean Pipeline Co Ltd		115								4
Unión Fenosa Gas SA				85
Other (*)		104		64				1		9
		982		444		1,051		1		46
Unconsolidated entities controlled by Eni
Other (*)		57		59		1				3
		57		59		1				3
Entities controlled by the Government
Gruppo Cassa Depositi e Prestiti												338
												338
		1,039		503		1,052		1		49		338

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2012 (euro million)		Dec. 31, 2012		2012

Name

Receivables

Payables

Guarantees

Charges

Gains

Income from equity instruments

Continuing operations
Joint ventures and associates
Bayernoil Raffineriegesellschaft mbH		94								1
Blue Stream Pipeline Co BV				291		657		2		3
CARDÓN IV SA		80								3
CEPAV (Consorzio Eni per l’Alta Velocità) Due						84
GreenStream BV		453								29
Raffineria di Milazzo ScpA		40				75				2
Société Centrale Electrique du Congo SA		92
Transmediterranean Pipeline Co Ltd		82								6
Other (*)		94		63		12		1		2
		935		354		828		3		46
Unconsolidated entities controlled by Eni
Other (*)		58		49		1		1
		58		49		1		1
Entities controlled by the Government
Gruppo Cassa Depositi e Prestiti		883								6
Gruppo Snam		141								1
		1,024								7
		2,017		403		829		4		53
Discontinued operations
Entities controlled by the Government
Gruppo Cassa Depositi e Prestiti												2,019
												2,019
		2,017		403		829		4		53		2,019

 

Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned:

•		bank debt guarantee issued on behalf of Blue Stream Pipeline Co BV, CEPAV (Consorzio Eni per l’Alta Velocità) Due and Raffineria di Milazzo ScpA;
•		financing loans granted to Bayernoil Raffineriegesellschaft mbH for capital expenditures in refining plants, to CARDÓN IV SA for the exploration and development activities of an oil field and to Société Electrique Centrale du Congo SA for the construction of an electric plant in Congo;
•		the financing of the construction of natural gas transmission facilities and transport services with GreenStream BV and Transmediterranean Pipeline Co Ltd; and
•		a cash deposit at Eni’s financial companies on behalf of Blue Stream Pipeline Co BV.

Financing receivables and income from investments with Gruppo Cassa Depositi e Prestiti related to the sale of Snam SpA (divestment of a 30% stake) (more information is provided in note 17 – Investments). Financial receivables with Snam SpA related to the settlement of financial derivative transactions.

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Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flow
The impact of transactions and positions with related parties on the balance sheet consisted of the following:

		Dec. 31, 2010		Dec. 31, 2011		Dec. 31, 2012

(euro million)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Trade and other receivables		23,636		1,356		5.74		24,595		1,496		6.08		28,621		2,714		9.48
Other current assets		1,350		9		0.67		2,326		2		0.09		1,624		8		0.49
Other non-current financial assets		1,523		668		43.86		1,578		704		44.61		1,229		642		52.24
Other non-current assets		3,355		16		0.48		4,225		3		0.07		4,400		43		0.98
Current financial liabilities		6,515		127		1.95		4,459		503		11.28		2,223		403		18.13
Trade and other payables		22,575		1,297		5.75		22,912		1,446		6.31		23,581		1,616		6.85
Other current liabilities		1,620		5		0.31		2,237						1,437		6		0.42
Other non-current liabilities		2,194		45		2.05		2,900						1,977		16		0.81

The impact of transactions with related parties on the profit and loss accounts consisted of the following:

		2010		2011		2012

(euro million)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Continuing operations
Net sales from operations		96,617			2,905		3.01		107,690			3,477			3.23			127,220			3,783			2.97
Other income and revenues		967			57		5.89		926			41			4.43			1,546			56			3.62
Purchases, services and other		68,774			5,820		8.46		78,795			5,880			7.46			95,363			6,604			6.93
Payroll and related costs		4,428			28		0.63		4,404			33			0.75			4,658			21			0.45
Other operating income (expense)		131			41		31.30		171			32			18.71			(158	)		10			..
Financial income		6,109			41		0.67		6,376			49			0.77			7,218			53			0.73
Financial expense		(6,727	)						(7,410	)		(1	)		0.01			(8,274	)		(4	)		0.05
Other gain (loss) from investments		619							1,623			338			20.83			2,603
Discontinued operations
Net sales from operations		1,895			370		19.53		1,906			407			21.35			1,886			303			16.07
Operating expenses		1,266			5		0.39		1,274			7			0.55			998			88			8.82
Income (expense) from investments		44							48									3,508			2,019			57.55

Transactions with related parties were part of the ordinary course of Eni’s business and were mainly conducted on arm’s length basis.

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The main cash flows with related parties are provided below:

(euro million)		2010		2011		2012

Revenues and other income		2,962			3,518			3,839
Costs and other expenses		(5,820	)		(4,497	)		(5,375	)
Other operating income (expense)		41			32			10
Net change in trade and other receivables and liabilities		182			(140	)		(280	)
Net interests		41			48			49
Net cash provided from operating activities - Continuing operations		(2,594	)		(1,039	)		(1,757	)
Net cash provided from operating activities - Discontinued operations		365			400			215
Net cash provided from operating activities		(2,229	)		(639	)		(1,542	)
Capital expenditures in tangible and intangible assets		(1,764	)		(1,416	)		(1,250	)
Disposal of investments					533			3,517
Change in accounts payable and receivables in relation to investments		10			(21	)		261
Change in financial receivables		128			104			(993	)
Net cash used in investing activities		(1,626	)		(800	)		1,535
Change in financial liabilities		(23	)		348			(94	)
Net cash used in financing activities		(23	)		348			(94	)
Total financial flows to related parties		(3,878	)		(1,091	)		(101	)

The impact of cash flows with related parties consisted of the following:

		2010		2011		2012

(euro million)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Total

Related parties

Impact (%)

Net cash provided from operating activities		14,694			(2,229	)		..		14,382			(639	)		..		12,371			(1,542	)		..
Net cash used in investing activities		(12,965	)		(1,626	)		12.54		(11,218	)		(800	)		7.13		(8,291	)		1,535			..
Net cash used in financing activities		(1,827	)		(23	)		1.26		(3,223	)		348			..		2,201			(94	)		..

43 Significant non-recurring events and operations

(euro million)		2010		2011		2012

Estimate of the charge from the possible resolution of the TSKJ matter		24
Fines sanctioned by Antitrust Authorities		(270	)		69
		(246	)		69

In 2012, no non-recurring events and operations were reported.

In 2011, a non-recurring provision was made amounting to euro 69 million to reflect the expected liabilities on an antitrust proceeding in the European sector of rubbers taking into account an unfavorable sentence issued by the Court of Justice of the European Community on the matter.

In 2010, a non-recurring gain amounting to euro 270 million related to the favorable settlement of an antitrust proceedings concerning alleged anticompetitive behavior charged to Eni regarding third party access to the import pipeline from Algeria in 2003. This resulted in a significantly lower fine imposed on the Company than the one sanctioned by the Antitrust Authority in 2003 and then accrued to profit and loss. Also in 2010, a charge of euro 24 million related to a fine of $30 million for the TSKJ matter following the agreement with the Federal Government of Nigeria for the settling of the legal proceeding.

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44 Positions or transactions deriving from atypical and/or unusual operations

In 2010, 2011 and 2012 no transactions deriving from atypical and/or unusual operations were reported.

45 Subsequent events

In January 2013, Eni continued the divestment of part of its interest in Snam with the placement of euro 1,250 million aggregate principal amount of senior, unsecured bonds, exchangeable into ordinary shares of Snam. The bonds have maturity of 3 years and pay a coupon of 0.625% per annum. The bonds will be exchangeable into Snam ordinary shares at an exchange price of euro 4.33 per Snam ordinary share, representing approximately a 20% premium to the Snam current reference price. Underlying the bonds are approximately 288.7 million ordinary shares of Snam, corresponding to approximately 8.54% of the currently outstanding share capital of Snam. Changes in fair value of those shares will be reported through profit as opposed to equity based on the fair value option provided by IAS 39 from inception, i.e. the transaction date with CDP. Those changes were immaterial at the balance sheet date. At the maturity date, if the strike price is lower than the exercise price, Eni will be enabled to reimburse the bond holders with Snam ordinary shares at the current market price recognized at the date of the reimbursement.

On March 13, 2013, Eni signed an agreement with CNPC/Petrochina to sell 28.57% of the share capital of the subsidiary Eni East Africa SpA, which currently owns 70% interest in Area 4 for an agreed price equal to $4,210 million. The deal is subject to approval by relevant authorities. Once finalized, CNPC indirectly acquires, through its 28.57% equity investment in Eni East Africa SpA, a 20% interest in Area 4, while Eni will retain the 50% interest through the remaining controlling stake in Eni East Africa SpA.

 

 

 

 

 

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Supplemental oil and gas information (unaudited)

The following information pursuant to "International Financial Reporting Standards" (IFRS) is presented in accordance with FASB Extractive Activities - Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs
Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

December 31, 2011
Consolidated subsidiaries
Proved mineral interests		11,356			11,481			15,519			19,539			2,523			6,136			8,976			1,889			77,419
Unproved mineral interests		31			325			582			2,893			40			1,543			1,409			204			7,027
Support equipment and facilities		285			34			1,442			923			85			41			61			13			2,884
Incomplete wells and other		956			1,778			2,755			898			5,333			136			1,029						12,885
Gross capitalized costs		12,628			13,618			20,298			24,253			7,981			7,856			11,475			2,106			100,215
Accumulated depreciation, depletion and amortization		(8,633	)		(8,582	)		(9,750	)		(13,069	)		(906	)		(5,411	)		(6,806	)		(650	)		(53,807	)
Net capitalized costs consolidated subsidiaries (a) (b)		3,995			5,036			10,548			11,184			7,075			2,445			4,669			1,456			46,408
Equity-accounted entities
Proved mineral interests					2			80			240						698			330						1,350
Unproved mineral interests					44												271									315
Support equipment and facilities								8									6			3						17
Incomplete wells and other					2			1			1,011						185			223						1,422
Gross capitalized costs					48			89			1,251						1,160			556						3,104
Accumulated depreciation, depletion and amortization					(2	)		(74	)		(131	)					(388	)		(89	)					(684	)
Net capitalized costs equity-accounted entities (a) (b)					46			15			1,120						772			467						2,420
December 31, 2010
Consolidated subsidiaries
Proved mineral interests		12,579			12,428			16,240			20,875			2,451			6,477			10,018			1,894			82,962
Unproved mineral interests		31			324			411			3,047			39			1,467			1,249			200			6,768
Support equipment and facilities		267			39			1,421			961			75			78			59			12			2,912
Incomplete wells and other		732			3,347			3,181			974			5,746			358			876			1			15,215
Gross capitalized costs		13,609			16,138			21,253			25,857			8,311			8,380			12,202			2,107			107,857
Accumulated depreciation, depletion and amortization		(9,364	)		(9,346	)		(10,671	)		(14,225	)		(928	)		(6,002	)		(7,879	)		(832	)		(59,247	)
Net capitalized costs consolidated subsidiaries (a) (b)		4,245			6,792			10,582			11,632			7,383			2,378			4,323			1,275			48,610
Equity-accounted entities
Proved mineral interests					1			83			52						964			322						1,422
Unproved mineral interests					54												279									333
Support equipment and facilities								7									6			3						16
Incomplete wells and other					22			1			1,052						114			200						1,389
Gross capitalized costs					77			91			1,104						1,363			525						3,160
Accumulated depreciation, depletion and amortization					(55	)		(72	)								(421	)		(111	)					(659	)
Net capitalized costs equity-accounted entities (a) (b)					22			19			1,104						942			414						2,501

(a)		The amounts include net capitalized financial charges totaling euro 614 million in 2011 and euro 672 million in 2012 for the consolidated subsidiaries and euro 11 million in 2011 and euro 24 million in 2012 for equity-accounted entities.
(b)		The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The "Successful Effort Method" application would have led to an increase in net capitalized costs of euro 3,608 million in 2011 e euro 4,071 million in 2012 for the consolidated subsidiaries and of euro 101 million in 2011 and euro 74 million in 2012 for equity-accounted entities.

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Costs incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2010
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration		34			114			84			406			6			223			119			26			1,012
Development (a)		579			890			2,674			1,909			1,031			359			1,309			160			8,911
Total costs incurred consolidated subsidiaries		613			1,004			2,758			2,315			1,037			582			1,428			186			9,923
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration								4			2						4			35						45
Development (b)								7			200						46			114						367
Total costs incurred equity-accounted entities								11			202						50			149						412
2011
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions								57			697															754
Exploration		38			100			128			482			6			156			60			240			1,210
Development (a)		815			1,921			1,487			1,698			935			385			971			70			8,282
Total costs incurred consolidated subsidiaries		853			2,021			1,672			2,877			941			541			1,031			310			10,246
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration					5						5						8			9						27
Development (b)					2			3			659						68			154						886
Total costs incurred equity-accounted entities					7			3			664						76			163						913
2012
Consolidated subsidiaries
Proved property acquisitions								14			27									2						43
Unproved property acquisitions
Exploration		32			151			153			1,142			3			193			80			96			1,850
Development (a)		1,045			2,485			1,441			2,246			762			702			1,071			16			9,768
Total costs incurred consolidated subsidiaries		1,077			2,636			1,608			3,415			765			895			1,153			112			11,661
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration					13			2			11						4									30
Development (b)					19			7			117						188			154						485
Total costs incurred equity-accounted entities					32			9			128						192			154						515

(a)		Includes the abandonment costs of the assets for euro 269 million in 2010, euro 918 million in 2011 and euro 1,381 million in 2012.
(b)		Includes the abandonment costs of the assets for euro -3 million in 2010, euro 15 million in 2011 and euro 63 million in 2012.

Results of operations from oil and gas producing activities
Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.

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Results of operations from oil and gas producing activities by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2010
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		2,725			3,006			2,094			5,314			324			34			1,139			69			14,705
- sales to third parties					263			6,604			1,696			890			1,429			562			289			11,733
Total revenues		2,725			3,269			8,698			7,010			1,214			1,463			1,701			358			26,438
Operations costs		(278	)		(555	)		(593	)		(902	)		(184	)		(150	)		(292	)		(69	)		(3,023	)
Production taxes		(184	)					(300	)		(700	)					(37	)								(1,221	)
Exploration expenses		(35	)		(116	)		(85	)		(465	)		(6	)		(263	)		(204	)		(25	)		(1,199	)
D.D. & A. and provision for abandonment (a)		(621	)		(615	)		(1,063	)		(1,739	)		(84	)		(696	)		(872	)		(84	)		(5,774	)
Other income (expense)		(560	)		254			(392	)		(219	)		(161	)		(138	)		(45	)		(25	)		(1,286	)
Pretax income from producing activities		1,047			2,237			6,265			2,985			779			179			288			155			13,935
Income taxes		(382	)		(1,296	)		(4,037	)		(1,962	)		(291	)		(119	)		(154	)		(36	)		(8,277	)
Results of operations from E&P activities of consolidated subsidiaries (b)		665			941			2,228			1,023			488			60			134			119			5,658
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties								16			65						69			206						356
Total revenues								16			65						69			206						356
Operations costs								(16	)		(9	)					(7	)		(9	)					(41	)
Production taxes								(3	)											(69	)					(72	)
Exploration expenses								(4	)		(2	)					(4	)		(35	)					(45	)
D.D. & A. and provision for abandonment								(4	)		(26	)					(25	)		(17	)					(72	)
Other income (expense)								6			12						(10	)		(67	)					(59	)
Pretax income from producing activities								(5	)		40						23			9						67
Income taxes								4			(20	)					(17	)		(33	)					(66	)
Results of operations from E&P activities of equity-accounted entities (b)								(1	)		20						6			(24	)					1
2011
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		3,583			3,695			1,956			5,945			411			178			1,634			93			17,495
- sales to third parties					514			5,090			1,937			1,268			1,233			132			344			10,518
Total revenues		3,583			4,209			7,046			7,882			1,679			1,411			1,766			437			28,013
Operations costs		(284	)		(566	)		(483	)		(830	)		(171	)		(183	)		(364	)		(88	)		(2,969	)
Production taxes		(245	)					(165	)		(853	)					(37	)								(1,300	)
Exploration expenses		(38	)		(113	)		(128	)		(509	)		(6	)		(177	)		(136	)		(58	)		(1,165	)
D.D. & A. and provision for abandonment (a)		(606	)		(704	)		(843	)		(1,435	)		(112	)		(486	)		(901	)		(103	)		(5,190	)
Other income (expense)		(562	)		142			(508	)		(314	)		(160	)		(151	)		125			8			(1,420	)
Pretax income from producing activities		1,848			2,968			4,919			3,941			1,230			377			490			196			15,969
Income taxes		(761	)		(2,043	)		(3,013	)		(2,680	)		(413	)		(157	)		(184	)		(120	)		(9,371	)
Results of operations from E&P activities of consolidated subsidiaries (b)		1,087			925			1,906			1,261			817			220			306			76			6,598
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties					2			19			93						89			262						465
Total revenues					2			19			93						89			262						465
Operations costs								(11	)		(10	)					(9	)		(17	)					(47	)
Production taxes					(1	)		(4	)											(113	)					(118	)
Exploration expenses					(6	)					(5	)					(8	)		(9	)					(28	)
D.D. & A. and provision for abandonment								(1	)		(24	)					(23	)		(21	)					(69	)
Other income (expense)					(4	)		6			11						(20	)		(51	)					(58	)
Pretax income from producing activities					(9	)		9			65						29			51						145
Income taxes								(4	)		(35	)					(32	)		(4	)					(75	)
Results of operations from E&P activities of equity-accounted entities (b)					(9	)		5			30						(3	)		47						70

(a)		Includes asset impairments amounting to euro 123 million in 2010 and euro 189 million in 2011.
(b)		The "Successful Effort Method" application would have led to an decrease of result of operations of euro 385 million in 2010 and an increase of euro 118 million in 2011 for the consolidated subsidiaries and a decrease of euro 5 million in 2010 and an increase of euro 20 million in 2011 for equity-accounted entities.

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(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2012
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		3,712			3,177			2,338			6,040			459			425			1,614			425			18,190
- sales to third parties		50			715			9,129			2,243			1,368			1,387			106			333			15,331
Total revenues		3,762			3,892			11,467			8,283			1,827			1,812			1,720			758			33,521
Operations costs		(302	)		(655	)		(606	)		(913	)		(188	)		(209	)		(361	)		(134	)		(3,368	)
Production taxes		(307	)					(390	)		(818	)					(43	)								(1,558	)
Exploration expenses		(32	)		(154	)		(153	)		(993	)		(3	)		(230	)		(147	)		(123	)		(1,835	)
D.D. & A. and provision for abandonment (a)		(779	)		(683	)		(1,137	)		(1,750	)		(120	)		(720	)		(1,256	)		(167	)		(6,612	)
Other income (expense)		(202	)		(120	)		(937	)		(447	)		206			(151	)		74			(42	)		(1,619	)
Pretax income from producing activities		2,140			2,280			8,244			3,362			1,722			459			30			292			18,529
Income taxes		(918	)		(1,524	)		(5,194	)		(2,508	)		(736	)		(176	)		(14	)		(164	)		(11,234	)
Results of operations from E&P activities of consolidated subsidiaries (b)		1,222			756			3,050			854			986			283			16			128			7,295
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties					2			20			44						144			300						510
Total revenues					2			20			44						144			300						510
Operations costs								(10	)		(5	)					(14	)		(20	)					(49	)
Production taxes					(1	)		(3	)								(4	)		(128	)					(136	)
Exploration expenses					(5	)		(2	)		(11	)					(4	)								(22	)
D.D. & A. and provision for abandonment					(50	)		(2	)		(13	)					(41	)		(35	)					(141	)
Other income (expense)					(7	)		2			(48	)					(6	)		(55	)					(114	)
Pretax income from producing activities					(61	)		5			(33	)					75			62						48
Income taxes								(3	)		4						(36	)		(38	)					(73	)
Results of operations from E&P activities of equity-accounted entities (b)					(61	)		2			(29	)					39			24						(25	)

(a)		Includes asset impairments amounting to euro 547 million in 2012.
(b)		The "Successful Effort Method" application would have led to a decrease of result of operations of euro 189 million in 2012 for the consolidated subsidiaries and a decrease of euro 2 million in 2012 for equity-accounted entities.

Oil and natural gas reserves
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2012, the average price for the marker Brent crude oil was $111 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation²⁰ of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report.

In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current cost of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided. In 2012, Ryder Scott Company and DeGolyer and MacNaughton²¹ provided an independent evaluation of almost 33% of Eni’s total proved reserves as of December 31, 2012²², confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three year period from 2010 to 2012, 92% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2012, the principal properties not subjected to independent evaluation in the last three years are Bouri and Bu Attifel (Libya) and M’Boundi (Congo).

Eni operates under Production Sharing Agreements, PSAs, in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 55%, 49% and 47% of total proved reserves as of December 31, 2010, 2011 and 2012, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 3%, 1% and 2% of total proved reserves on an oil-equivalent basis as of December 31, 2010, 2011 and 2012, respectively.

Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the Company serves as producer of reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 0.6%, 0.8% and 1.1% of total proved reserves as of December 31, 2010, 2011 and 2012, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) and the quantities of hydrocarbons related to the Angola LNG plant.

Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.

The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2010, 2011 and 2012.

 

 

 

 

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Crude oil (including condensate and natural gas liquids)

(mmBBL)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2010
Reserves of consolidated subsidiaries at December 31, 2009		233			351			895			770			849			94			153			32			3,377
of which: developed		141			218			659			544			291			45			80			23			2,001
of which: undeveloped		92			133			236			226			558			49			73			9			1,376
Purchase of minerals in place
Revisions of minerals in place		38			17			178			75			(37	)		62			2						335
Improved recovery								1			1															2
Extensions and discoveries					25			13			22									1						61
Production		(23	)		(44	)		(108	)		(116	)		(24	)		(17	)		(22	)		(3	)		(357	)
Sales of minerals in place								(1	)		(2	)														(3	)
Reserves of consolidated subsidiaries at December 31, 2010		248			349			978			750			788			139			134			29			3,415
Reserves of equity-accounted entities at December 31, 2009								13			7						50			16						86
of which: developed								10			4						7			13						34
of which: undeveloped								3			3						43			3						52
Purchase of minerals in place
Revisions of minerals in place								8									(6	)		(2	)
Improved recovery																				12						12
Extensions and discoveries																				117						117
Production								(2	)		(1	)								(4	)					(7	)
Sales of minerals in place
Reserves of equity-accounted entities at December 31, 2010								19			6						44			139						208
Reserves at December 31, 2010		248			349			997			756			788			183			273			29			3,623
Developed		183			207			674			537			251			44			87			20			2,003
Consolidated subsidiaries		183			207			656			533			251			39			62			20			1,951
Equity-accounted entities								18			4						5			25						52
Undeveloped		65			142			323			219			537			139			186			9			1,620
Consolidated subsidiaries		65			142			322			217			537			100			72			9			1,464
Equity-accounted entities								1			2						39			114						156
2011
Reserves of consolidated subsidiaries at December 31, 2010		248			349			978			750			788			139			134			29			3,415
of which: developed		183			207			656			533			251			39			62			20			1,951
of which: undeveloped		65			142			322			217			537			100			72			9			1,464
Purchase of minerals in place
Revisions of minerals in place		34			58			10			14			(112	)		(20	)		1						(15	)
Improved recovery					2			2			2															6
Extensions and discoveries					9			2			11									17						39
Production		(23	)		(44	)		(75	)		(100	)		(23	)		(13	)		(20	)		(4	)		(302	)
Sales of minerals in place					(2	)					(7	)														(9	)
Reserves of consolidated subsidiaries at December 31, 2011		259			372			917			670			653			106			132			25			3,134
Reserves of equity-accounted entities at December 31, 2010								19			6						44			139						208
of which: developed								18			4						5			25						52
of which: undeveloped								1			2						39			114						156
Purchase of minerals in place
Revisions of previous estimates											11						6			11						28
Improved recovery																				1						1
Extensions and discoveries											6						60			4						70
Production								(2	)		(1	)								(4	)					(7	)
Sales of minerals in place
Reserves of equity-accounted entities at December 31, 2011								17			22						110			151						300
Reserves at December 31, 2011		259			372			934			692			653			216			283			25			3,434
Developed		184			195			638			487			215			34			117			25			1,895
Consolidated subsidiaries		184			195			622			483			215			34			92			25			1,850
Equity-accounted entities								16			4									25						45
Undeveloped		75			177			296			205			438			182			166						1,539
Consolidated subsidiaries		75			177			295			187			438			72			40						1,284
Equity-accounted entities								1			18						110			126						255

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(mmBBL)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2012
Reserves of consolidated subsidiaries at December 31, 2011		259			372			917			670			653			106			132			25			3,134
of which: developed		184			195			622			483			215			34			92			25			1,850
of which: undeveloped		75			177			295			187			438			72			40						1,284
Purchase of minerals in place
Revisions of previous estimates		(9	)		10			55			26			62			(9	)		40			6			181
Improved recovery					1			20			7															28
Extensions and discoveries					3			10			65									8						86
Production		(23	)		(35	)		(98	)		(90	)		(22	)		(15	)		(26	)		(7	)		(316	)
Sales of minerals in place											(6	)		(23	)											(29	)
Reserves of consolidated subsidiaries at December 31, 2012		227			351			904			672			670			82			154			24			3,084
Reserves of equity-accounted entities at December 31, 2011								17			22						110			151						300
of which: developed								16			4									25						45
of which: undeveloped								1			18						110			126						255
Purchase of minerals in place
Revisions of previous estimates											(1	)					2									1
Improved recovery
Extensions and discoveries								1									3									4
Production								(1	)		(1	)					(1	)		(4	)					(7	)
Sales of minerals in place											(4	)								(28	)					(32	)
Reserves of equity-accounted entities at December 31, 2012								17			16						114			119						266
Reserves at December 31, 2012		227			351			921			688			670			196			273			24			3,350
Developed		165			180			601			456			203			49			128			24			1,806
Consolidated subsidiaries		165			180			584			456			203			41			109			24			1,762
Equity-accounted entities								17									8			19						44
Undeveloped		62			171			320			232			467			147			145						1,544
Consolidated subsidiaries		62			171			320			216			467			41			45						1,322
Equity-accounted entities											16						106			100						222

Natural gas (a)

(BCF)

Italy (b)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2010
Reserves of consolidated subsidiaries at December 31, 2009		2,704			1,380			5,894			2,127			2,139			814			629			575			16,262
of which: developed		2,001			1,231			3,486			1,463			1,859			539			506			565			11,650
of which: undeveloped		703			149			2,408			664			280			275			123			10			4,612
Purchase of minerals in place
Revisions of previous estimates		234			48			778			161			(179	)		211			41			(18	)		1,276
Improved recovery
Extensions and discoveries					177			146									4			5			22			354
Production		(246	)		(204	)		(609	)		(161	)		(86	)		(158	)		(145	)		(35	)		(1,644	)
Sales of minerals in place		(48	)					(2	)																	(50	)
Reserves of consolidated subsidiaries at December 31, 2010		2,644			1,401			6,207			2,127			1,874			871			530			544			16,198
Reserves of equity-accounted entities at December 31, 2009								14			85						1,487			2						1,588
of which: developed								12			5						217									234
of which: undeveloped								2			80						1,270			2						1,354
Purchase of minerals in place
Revisions of previous estimates								6			(1	)					44			2						51
Improved recovery
Extensions and discoveries								6			34									18						58
Production								(2	)								(11	)								(13	)
Sales of minerals in place
Reserves of equity-accounted entities at December 31, 2010								24			118						1,520			22						1,684
Reserves at December 31, 2010		2,644			1,401			6,231			2,245			1,874			2,391			552			544			17,882
Developed		2,061			1,103			3,122			1,554			1,621			774			437			539			11,211
Consolidated subsidiaries		2,061			1,103			3,100			1,550			1,621			560			431			539			10,965
Equity-accounted entities								22			4						214			6						246
Undeveloped		583			298			3,109			691			253			1,617			115			5			6,671
Consolidated subsidiaries		583			298			3,107			577			253			311			99			5			5,233
Equity-accounted entities								2			114						1,306			16						1,438

(a)		Values lower than 1 BCF are not disclosed in this table.
(b)		Including, approximately 769 and 767 BCF of natural gas held in storage at December 31, 2009 and 2010, respectively.

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(BCF)

Italy (b)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2011
Reserves of consolidated subsidiaries at December 31, 2010		2,644			1,401			6,207			2,127			1,874			871			530			544			16,198
of which: developed		2,061			1,103			3,100			1,550			1,621			560			431			539			10,965
of which: undeveloped		583			298			3,107			577			253			311			99			5			5,233
Purchase of minerals in place		9																								9
Revisions of previous estimates		80			199			436			(11	)		(142	)		(38	)		51			96			671
Improved recovery					3																					3
Extensions and discoveries		4			18			9			18									131						180
Production		(246	)		(196	)		(462	)		(185	)		(84	)		(148	)		(122	)		(36	)		(1,479	)
Sales of minerals in place
Reserves of consolidated subsidiaries at December 31, 2011		2,491			1,425			6,190			1,949			1,648			685			590			604			15,582
Reserves of equity-accounted entities at December 31, 2010								24			118						1,520			22						1,684
of which: developed								22			4						214			6						246
of which: undeveloped								2			114						1,306			16						1,438
Purchase of minerals in place					2																					2
Revisions of previous estimates								(2	)		147						372			11						528
Improved recovery
Extensions and discoveries											74						1,150			1,274						2,498
Production								(2	)		(1	)					(9	)								(12	)
Sales of minerals in place
Reserves of equity-accounted entities at December 31, 2011					2			20			338						3,033			1,307						4,700
Reserves at December 31, 2011		2,491			1,427			6,210			2,287			1,648			3,718			1,897			604			20,282
Developed		1,977			995			3,087			1,441			1,480			552			393			491			10,416
Consolidated subsidiaries		1,977			995			3,070			1,437			1,480			528			385			491			10,363
Equity-accounted entities								17			4						24			8						53
Undeveloped		514			432			3,123			846			168			3,166			1,504			113			9,866
Consolidated subsidiaries		514			430			3,120			512			168			157			205			113			5,219
Equity-accounted entities					2			3			334						3,009			1,299						4,647
2012
Reserves of consolidated subsidiaries at December 31, 2011		2,491			1,425			6,190			1,949			1,648			685			590			604			15,582
of which: developed		1,977			995			3,070			1,437			1,480			528			385			491			10,363
of which: undeveloped		514			430			3,120			512			168			157			205			113			5,219
Purchase of minerals in place
Revisions of previous estimates		154			45						284			141			18			(41	)		5			606
Improved recovery
Extensions and discoveries		24			15			1			113			469			2			4						628
Production		(254	)		(168	)		(633	)		(196	)		(81	)		(143	)		(104	)		(37	)		(1,616	)
Sales of minerals in place		(782	)								(89	)		(139	)											(1,010	)
Reserves of consolidated subsidiaries at December 31, 2012		1,633			1,317			5,558			2,061			2,038			562			449			572			14,190
Reserves of equity-accounted entities at December 31, 2011					2			20			338						3,033			1,307						4,700
of which: developed								17			4						24			8						53
of which: undeveloped					2			3			334						3,009			1,299						4,647
Purchase of minerals in place
Revisions of previous estimates					(2	)		(2	)		3						1			1,340						1,340
Improved recovery
Extensions and discoveries											17						38			739						794
Production								(2	)		(2	)					(29	)								(33	)
Sales of minerals in place											(3	)								(31	)					(34	)
Reserves of equity-accounted entities at December 31, 2012								16			353						3,043			3,355						6,767
Reserves at December 31, 2012		1,633			1,317			5,574			2,414			2,038			3,605			3,804			572			20,957
Developed		1,325			925			2,736			1,429			1,401			774			340			459			9,389
Consolidated subsidiaries		1,325			925			2,720			1,429			1,401			372			334			459			8,965
Equity-accounted entities								16									402			6						424
Undeveloped		308			392			2,838			985			637			2,831			3,464			113			11,568
Consolidated subsidiaries		308			392			2,838			632			637			190			115			113			5,225
Equity-accounted entities											353						2,641			3,349						6,343

(b)		Including, approximately 767 and 767 BCF of natural gas held in storage at December 31, 2010 and 2011, respectively.

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Standardized measure of discounted future net cash flows
Estimated future cash inflows represent the revenues that would be received from production and are determined by applying year end the average prices during the years ended.

Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered.

The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor.

Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the Countries in which Eni operates.

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

The standardized measure of discounted future net cash flows by geographical area consists of the following:

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

December 31, 2010
Consolidated subsidiaries
Future cash inflows		30,047			27,973			86,728			45,790			41,053			9,701			8,546			3,846			253,684
Future production costs		(4,865	)		(7,201	)		(12,896	)		(13,605	)		(6,686	)		(3,201	)		(2,250	)		(611	)		(51,315	)
Future development and abandonment costs		(4,499	)		(6,491	)		(8,827	)		(5,310	)		(5,192	)		(3,489	)		(1,713	)		(221	)		(35,742	)
Future net inflow before income tax		20,683			14,281			65,005			26,875			29,175			3,011			4,583			3,014			166,627
Future income tax		(6,289	)		(9,562	)		(37,108	)		(14,468	)		(7,213	)		(872	)		(910	)		(805	)		(77,227	)
Future net cash flows		14,394			4,719			27,897			12,407			21,962			2,139			3,673			2,209			89,400
10% discount factor		(7,224	)		(1,608	)		(13,117	)		(3,884	)		(14,829	)		(419	)		(1,392	)		(850	)		(43,323	)
Standardized measure of discounted future net cash flows of consolidated subsidiaries at December 31, 2010		7,170			3,111			14,780			8,523			7,133			1,720			2,281			1,359			46,077
Equity-accounted entities
Future cash inflows								498			750						2,893			7,363						11,504
Future production costs								(251	)		(98	)					(972	)		(2,676	)					(3,997	)
Future development and abandonment costs								(35	)		(128	)					(879	)		(1,188	)					(2,230	)
Future net inflow before income tax								212			524						1,042			3,499						5,277
Future income tax								(2	)		(69	)					(338	)		(2,145	)					(2,554	)
Future net cash flows								210			455						704			1,354						2,723
10% discount factor								(113	)		(160	)					(515	)		(852	)					(1,640	)
Standardized measure of discounted future net cash flows of equity-accounted entities at December 31, 2010								97			295						189			502						1,083
Total consolidated subsidiaries and equity-accounted entities at December 31, 2010		7,170			3,111			14,877			8,818			7,133			1,909			2,783			1,359			47,160

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(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

December 31, 2011
Consolidated subsidiaries
Future cash inflows		38,200			37,974			109,825			59,263			50,443			10,403			11,980			5,185			323,273
Future production costs		(5,740	)		(7,666	)		(17,627	)		(15,191	)		(7,845	)		(3,852	)		(2,687	)		(813	)		(61,421	)
Future development and abandonment costs		(4,712	)		(7,059	)		(9,639	)		(5,734	)		(3,705	)		(2,842	)		(1,836	)		(224	)		(35,751	)
Future net inflow before income tax		27,748			23,249			82,559			38,338			38,893			3,709			7,457			4,148			226,101
Future income tax		(9,000	)		(15,912	)		(46,676	)		(23,075	)		(9,866	)		(1,124	)		(2,474	)		(1,254	)		(109,381	)
Future net cash flows		18,748			7,337			35,883			15,263			29,027			2,585			4,983			2,894			116,720
10% discount factor		(9,692	)		(2,572	)		(16,191	)		(4,833	)		(17,599	)		(559	)		(1,914	)		(1,122	)		(54,482	)
Standardized measure of discounted future net cash flows of consolidated subsidiaries at December 31, 2011		9,056			4,765			19,692			10,430			11,428			2,026			3,069			1,772			62,238
Equity-accounted entities
Future cash inflows					21			649			1,866						6,141			15,067						23,744
Future production costs					(5	)		(259	)		(471	)					(1,540	)		(4,598	)					(6,873	)
Future development and abandonment costs					(2	)		(36	)		(147	)					(1,247	)		(1,754	)					(3,186	)
Future net inflow before income tax					14			354			1,248						3,354			8,715						13,685
Future income tax					(3	)		(3	)		(189	)					(824	)		(5,368	)					(6,387	)
Future net cash flows					11			351			1,059						2,530			3,347						7,298
10% discount factor								(183	)		(475	)					(1,825	)		(2,155	)					(4,638	)
Standardized measure of discounted future net cash flows of equity-accounted entities at December 31, 2011					11			168			584						705			1,192						2,660
Total consolidated subsidiaries and equity-accounted entities at December 31, 2011		9,056			4,776			19,860			11,014			11,428			2,731			4,261			1,772			64,898
December 31, 2012
Consolidated subsidiaries
Future cash inflows		30,308			38,912			108,343			56,978			53,504			7,881			11,008			4,957			311,891
Future production costs		(5,900	)		(8,190	)		(18,555	)		(14,844	)		(9,561	)		(2,854	)		(2,520	)		(921	)		(63,345	)
Future development and abandonment costs		(3,652	)		(7,511	)		(8,412	)		(6,873	)		(3,802	)		(1,974	)		(1,502	)		(197	)		(33,923	)
Future net inflow before income tax		20,756			23,211			81,376			35,261			40,141			3,053			6,986			3,839			214,623
Future income tax		(6,911	)		(15,063	)		(44,256	)		(21,348	)		(10,293	)		(903	)		(2,906	)		(1,181	)		(102,861	)
Future net cash flows		13,845			8,148			37,120			13,913			29,848			2,150			4,080			2,658			111,762
10% discount factor		(5,519	)		(2,630	)		(16,539	)		(4,976	)		(17,943	)		(496	)		(1,337	)		(1,030	)		(50,470	)
Standardized measure of discounted future net cash flows of consolidated subsidiaries at December 31, 2012		8,326			5,518			20,581			8,937			11,905			1,654			2,743			1,628			61,292
Equity-accounted entities
Future cash inflows					1			658			3,594						6,689			18,132						29,074
Future production costs								(203	)		(576	)					(2,216	)		(5,003	)					(7,998	)
Future development and abandonment costs					(1	)		(17	)		(101	)					(1,061	)		(2,563	)					(3,743	)
Future net inflow before income tax								438			2,917						3,412			10,566						17,333
Future income tax								(36	)		(1,291	)					(795	)		(5,729	)					(7,851	)
Future net cash flows								402			1,626						2,617			4,837						9,482
10% discount factor								(206	)		(962	)					(1,747	)		(3,621	)					(6,536	)
Standardized measure of discounted future net cash flows of equity-accounted entities at December 31, 2012								196			664						870			1,216						2,946
Total consolidated subsidiaries and equity-accounted entities at December 31, 2012		8,326			5,518			20,777			9,601			11,905			2,524			3,959			1,628			64,238

 

 

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Changes in standardized measure of discounted future net cash flows
Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2010, 2011 and 2012, are as follows:

(euro million)		Consolidated subsidiaries		Equity-accounted entities		Total

Standardized measure of discounted future net cash flows at December 31, 2009		31,500			257			31,757
Increase (Decrease):
- sales, net of production costs		(22,194	)		(243	)		(22,437	)
- net changes in sales and transfer prices, net of production costs		24,415			406			24,821
- extensions, discoveries and improved recovery, net of future production and development costs		1,926			1,409			3,335
- changes in estimated future development and abandonment costs		(6,464	)		(386	)		(6,850	)
- development costs incurred during the period that reduced future development costs		8,520			368			8,888
- revisions of quantity estimates		12,600			143			12,743
- accretion of discount		6,519			53			6,572
- net change in income taxes		(11,802	)		(1,115	)		(12,917	)
- purchase of reserves in-place
- sale of reserves in-place		(177	)					(177	)
- changes in production rates (timing) and other		1,234			191			1,425
Net increase (decrease)		14,577			826			15,403
Standardized measure of discounted future net cash flows at December 31, 2010		46,077			1,083			47,160
Increase (Decrease):
- sales, net of production costs		(23,744	)		(300	)		(24,044	)
- net changes in sales and transfer prices, net of production costs		40,961			442			41,403
- extensions, discoveries and improved recovery, net of future production and development costs		1,580			2,457			4,037
- changes in estimated future development and abandonment costs		(3,890	)		(392	)		(4,282	)
- development costs incurred during the period that reduced future development costs		7,301			866			8,167
- revisions of quantity estimates		1,337			(87	)		1,250
- accretion of discount		8,640			235			8,875
- net change in income taxes		(17,067	)		(1,678	)		(18,745	)
- purchase of reserves in-place		37			10			47
- sale of reserves in-place		(146	)					(146	)
- changes in production rates (timing) and other		1,152			24			1,176
Net increase (decrease)		16,161			1,577			17,738
Standardized measure of discounted future net cash flows at December 31, 2011		62,238			2,660			64,898
Increase (Decrease):
- sales, net of production costs		(28,595	)		(325	)		(28,920	)
- net changes in sales and transfer prices, net of production costs		2,264			(56	)		2,208
- extensions, discoveries and improved recovery, net of future production and development costs		4,868			812			5,680
- changes in estimated future development and abandonment costs		(3,802	)		(357	)		(4,159	)
- development costs incurred during the period that reduced future development costs		8,199			409			8,608
- revisions of quantity estimates		3,725			824			4,549
- accretion of discount		12,527			477			13,004
- net change in income taxes		2,207			(830	)		1,377
- purchase of reserves in-place
- sale of reserves in-place		(1,509	)		(615	)		(2,124	)
- changes in production rates (timing) and other		(830	)		(53	)		(883	)
Net increase (decrease)		(946	)		286			(660	)
Standardized measure of discounted future net cash flows at December 31, 2012		61,292			2,946			64,238

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SIGNATURES

The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: April 9, 2013

 

 

 

 

 

 

 

 

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EXHIBIT 1

By-laws of Eni SpA¹

Part I – Formation – Name – Registered Office and Duration of the Company

ARTICLE 1
1.1		Eni SpA, formed as a result of the transformation of Ente Nazionale Idrocarburi, a public agency, pursuant to Law No. 136 of February 10, 1953, is governed by these By-laws.
1.2		The first letter of the Company’s name may be written in either upper or lower case.
ARTICLE 2
2.1		The Company’s registered office is located in Rome, and it has two branch offices in San Donato Milanese (Milan).
2.2		The Company may establish and/or close offices, representative offices, affiliates and branch offices either in Italy or abroad, in the manner provided for by law.
ARTICLE 3
3.1		The duration of the Company shall expire on December 31, 2100. Its duration may be extended one or more times by resolution of the Shareholders’ Meeting.

Part II – Corporate Purpose

ARTICLE 4
4.1		The corporate purpose is the direct and/or indirect exercise, through equity holdings in companies or other entities of activities in the field of hydrocarbons and natural gases, such as exploration and development of hydrocarbon fields, the construction and operation of pipelines for transporting the same, the processing, transformation, storage, use and sale of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law.
		The corporate purpose also includes the direct and/or indirect exercise, through equity holdings in companies or other enterprises, of activities in the fields of chemicals, nuclear fuels, geothermal energy, other renewable energy sources and energy in general, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The corporate purpose also comprises performing and managing the technical and financial coordination of subsidiaries and associated companies and providing financial assistance to them. The Company may undertake any transactions necessary or useful for the achievement of the corporate purpose; by way of example, it may undertake transactions involving real estate or moveable assets, commercial and industrial transactions, financial and banking transactions of any sort, and any other act that is in any way connected with the corporate purpose with the exception of fundraising on a public basis and the performance of investment services as defined by Legislative Decree No. 58 of February 24, 1998. The Company may, finally, acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

Part III – Share capital – Shares – Bonds

 

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d)

power of appointment of one non-voting director. Should the office of said director be vacated, the Minister of the Economy and Finance, in agreement with the Minister of Economic Development, shall appoint a replacement.

ARTICLE 7
7.1		When shares are fully paid up, and if the law so allows, they may be issued to bearer. Bearer shares may be converted into registered shares and vice-versa. Conversion operations shall be carried out at the shareholder’s expense.
ARTICLE 8
8.1		If for whatever reason a share should belong to more than one person, the rights attaching to said share may be exercised by only one person or by a proxy acting for all co-holders.
ARTICLE 9
9.1		The Shareholders’ Meeting may resolve to increase the Company share capital and set the terms, conditions and means thereof.
9.2		The Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration pursuant to Article 2349 of the Italian Civil Code.
ARTICLE 10
10.1		Payments in respect of shares may be called by the Board of Directors in one or more installments.
10.2		Shareholders who are late in payment shall be charged interest calculated at the official discount rate established by the Bank of Italy, without prejudice to the provisions of Article 2344 of the Italian Civil Code.
ARTICLE 11
11.1		The Company may issue bonds, including convertible bonds and warrants, in compliance with the provisions of law.

Part IV – Shareholders’ Meetings

ARTICLE 12
12.1		Ordinary and extraordinary Shareholders’ Meetings shall normally be held at the Company’s registered office unless otherwise decided by the Board of Directors, provided however they are held in Italy.
12.2		The ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year, to approve the financial statements, since the Company is required to draw up consolidated financial statements.
12.3		The directors shall call a Shareholders’ Meeting without delay when shareholders representing at least one twentieth of the share capital so request. Shareholders’ Meetings may not be called upon the request of the shareholders for matters upon which, according to law, the Shareholders’ Meeting must resolve upon a proposal of the directors or on the basis of a project or report of the directors themselves. The shareholders who request a meeting to be convened shall prepare a report on the proposals relating to the matters to be discussed. The Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the Company’s registered office, on the Company’s website and in any other manner established in Consob regulations at the time the notice calling the meeting is published.
12.4		The Board of Directors shall make a report on each of the items on the agenda available to the public as provided for in the previous paragraph by the deadlines for publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda.
ARTICLE 13
13.1		The Shareholders’ Meeting shall be called by way of a notice published on the Company’s website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. Shareholders who severally or jointly represent at least one fortieth of the Company’s share capital may ask for items to be added to the agenda by submitting a request within ten days of publication of the notice calling the meeting, unless a different term is provided for by law, specifying the additional proposed items in their request or presenting proposed resolutions on items already on the agenda. Requests, together with the certificate attesting ownership of the shares, are submitted in writing, by mail or electronically in the manners provided for in the notice calling the meeting. These proposed resolutions may be presented individually at the Shareholders’ Meeting by persons entitled to vote. Matters upon which, according to law, the Shareholders’ Meeting must resolve upon a proposal of the Board of Directors or on the basis of a project or report of the directors other than the report on the items in the agenda, may not be added to the agenda. The Board of Directors shall give notice of the additions to the agenda or the proposed resolutions approved in the same manner prescribed for the publication of the notice calling the meeting at least fifteen days before the date set for the Shareholders’ Meeting, unless a different term is required by law. The proposed resolutions on items already on the agenda are made available to

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the public as prescribed by Article 12.3 of these By-laws, simultaneous with publication of the announcement of their presentation. The requesting or proposing shareholders shall send, by the final deadline for the submission of requests for additions to the agenda or of proposed resolutions, a report to the Board of Directors, explaining the reasons for the addition or the proposed resolution. The Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the same time as the publication of the notice of the additions to the agenda or of the presentation of proposed resolutions in the manner set out in Article 12.3 of these By-laws.

13.2

Entitlement to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit or debit records entered on the accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement issued by the authorized intermediary must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of this Article, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the meeting; otherwise, the date of each call is deemed the reference date.

ARTICLE 14
14.1		Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current laws. Electronic notification of the proxy may be made through a special section of the Company’s website as indicated in the notice calling the meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders associations that meet applicable statutory requirements, locations for communications and collecting proxies shall be made available to said associations in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.
14.2		The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.
14.3		The right to vote may also be exercised by correspondence in accordance with the applicable provisions of law and regulations. If envisaged in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of law, applicable regulations and the Shareholders’ Meeting Rules.
14.4		The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved with a resolution of the ordinary Shareholders’ Meeting.
14.5		The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by law and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.
ARTICLE 15
15.1		The Shareholders’ Meeting is chaired by the Chairman of the Board of Directors, or in the event of the Chairman’s absence or impediment, by the Chief Executive Officer; in their absence, the Shareholders’ Meeting shall elect its own Chairman.
15.2		The Chairman of the meeting is assisted by a Secretary, who need not be a shareholder, to be designated by the participants in the meeting, and may appoint one or more scrutineers.
ARTICLE 16
16.1		The ordinary Shareholders’ Meeting decides on all matters for which it is legally responsible and authorizes the transfer of the business.
16.2		The ordinary and extraordinary Shareholders’ Meetings are normally held after more than one call, as provided for in these By-laws; their resolutions in first, second or third call must be passed with the majorities required by law in each case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after a single call. In case of a single call, the majorities required by law in this case shall apply.
16.3		The resolutions of the Shareholders’ Meeting, approved in accordance with the law and these By-laws, shall be binding on all shareholders, including those dissenting or not present.
16.4		The minutes of ordinary meetings shall be signed by the Chairman and the Secretary.
16.5		The minutes of extraordinary meetings shall be drawn up by a notary public.

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Part V – The Board of Directors

ARTICLE 17
17.1		The Company is governed by a Board of Directors consisting of no fewer than three and no more than nine members. The Shareholders’ Meeting shall determine the number within these limits. The Minister of the Economy and Finance in agreement with the Minister of Economic Development may appoint an additional non-voting director, pursuant to Article 6.2, letter d), of the By-laws.
17.2		The directors shall be appointed for a period of up to three financial years; this term shall lapse on the date of the Shareholders’ Meeting convened to approve the financial statements for their last year in office. They may be re-elected.

17.3

The Board of Directors, except for the member appointed pursuant to Article 6.2, letter d) of these By-laws, shall be elected by the Shareholders’ Meeting on the basis of slates presented by shareholders and by the Board of Directors. The candidates shall be listed on the slates in numerical order. The slates shall be filed with the Company’s registered office, including remotely in the manner indicated in the notice calling the meeting, by the twenty-fifth day before the date of the Shareholders’ Meeting at first or single call convened to appoint the members of the Board of Directors. They shall be made available to the public as provided for by law and Consob regulations at least twenty-one days before the date set for the Shareholders’ Meeting at first or single call. Each shareholder may, severally or jointly, submit and vote on a single slate only. Controlling persons, subsidiaries and companies under common control may not submit or participate in the submission of other slates, nor can they vote on them, either directly or through nominees or trustees. As used herein, subsidiaries are those companies referred to in Article 93 of Legislative Decree No. 58 of February 24, 1998. Each candidate may stand on a single slate, on penalty of disqualification. Only those shareholders who, severally or jointly, represent at least 1% of share capital or any other threshold established by Consob regulations shall be entitled to submit a slate. Ownership of the minimum holding needed to submit slates shall be determined with regard to the shares registered to the shareholder on the day on which the slates are filed with the Company. Related certification may be submitted after the filing, provided that submission takes place by the deadline set for the publication of the slates by the Company. At least one director, if there are no more than five directors, or at least three directors, if there are more than five, shall satisfy the independence requirements established for the members of the board of statutory auditors of listed companies. The candidates meeting such independence requirements shall be expressly identified in each slate. All candidates shall also satisfy the integrity requirements established by applicable law. Slates that contain three or more candidates shall include candidates of both genders, as specified in the notice calling the Meeting, in order to comply with the applicable gender-balance legislation. When the number of members of the less-represented gender must, by law, be at least three, the slates competing to appoint the majority of the members of the Board of Directors must include at least two candidates of the less-represented gender. Together with the filing of each slate, on penalty of inadmissibility, the following shall also be filed: the curriculum vitae of each candidate, statements of each candidate accepting his/her nomination and affirming, under his/her personal responsibility, the absence of any grounds making him/her ineligible or incompatible for such position and that he/she satisfies the aforementioned requirements of integrity and independence (where applicable). The appointed directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise. The Board of Directors shall periodically evaluate the independence and integrity of its members and whether cause for ineligibility or incompatibility has arisen. If the integrity or independence requirements established by applicable legislation should no longer be met by a director or if cause for ineligibility or incompatibility should have arisen, the Board of Directors shall declare the director disqualified and replace him/her or shall invite him/her to rectify the situation of incompatibility by a deadline set by the Board itself, on penalty of disqualification. Directors shall be elected in the following manner:

			a)		seven-tenths of the directors to be elected shall be drawn from the slate that receives the most votes of the shareholders in the order in which they appear on the slate, rounded off in the event of a decimal number to the next lowest whole number;
			b)		the remaining directors shall be drawn from the other slates. Said slates shall not be connected in any way, directly or indirectly, to the shareholders who have submitted or voted the slate that receives the largest number of votes. For this purpose, the votes received by each slate shall be divided by one or two or three depending upon the number of directors to be elected. The quotients, or points, thus obtained shall be assigned progressively to candidates of each slate in the order given in the slates themselves. The candidates of all the slates shall be ranked by the points assigned in single list in descending order. Those who receive the most points shall be elected. In the event that more than one candidate receives the same number of points, the candidate elected shall be the person from the slate that has not hitherto had a director elected or that has elected the least number of directors. In the event that none of the slates has yet

 

 

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had a director elected or that all of them have had the same number of directors elected, the candidate among all such slates who has received the highest number of votes shall be elected. In the event of equal slate votes and equal points, the entire Shareholders’ Meeting shall vote again and the candidate elected shall be the person who receives a simple majority of the votes;

c)

if the minimum number of independent directors required under these By-laws has not been elected following the above procedure, the points to be assigned to the candidates draw from the slates shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidates who do not meet the requirements of independence with the fewest points from among the candidates drawn from all of the slates shall be replaced, starting from the last, by the independent candidates, from the same slate as the replaced candidate (following the order in which they are listed), otherwise by persons meeting the independence requirements appointed in accordance with the procedure set out in letter d). In cases where candidates from different lists have received the same number of points, the candidate from the slate from which the largest number of directors has been drawn or, subordinately, the candidate drawn from the slate receiving the lowest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders’ Meeting in a run-off election, shall be replaced;

			c-bis)		if the application of the procedure set out in letters a) and b) does not permit compliance with the gender-balance rules, the points to attribute to each candidate drawn from the slate shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidate of the over-represented gender with the fewest points from among the candidates drawn from all of the slates shall be replaced, without prejudice to the compliance with the required minimum number of independent directors, by the member of the less-represented gender who may be listed (with the next highest ordinal number) on the same slate as the candidate to be replaced, otherwise by a person to be appointed following the procedure set out in letter d). In cases where candidates from different lists have received the same minimum number of points, the candidate from the slate from which the largest number of directors has been drawn or, subordinately, the candidate drawn from the slate receiving the fewest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders’ Meeting in a run-off election, shall be replaced;
			d)		to appoint directors who for any reason were not appointed pursuant to the above procedures, the Shareholders’ Meeting shall resolve, with the majorities required by law, to ensure that the composition of the Board of Directors complies with applicable law and the By-laws.

		The slate voting procedure shall apply only to the election of the entire Board of Directors.
17.4		The Shareholders’ Meeting may, during the Board’s term of office, change the number of members of the Board of Directors, within the limits established in the first paragraph of this Article, and make the related appointments. The terms of directors so elected shall expire at the same time as those of the directors already in office.

17.5		If, during the year, the office of one or more directors should be vacated, he/she shall be replaced in accordance with Article 2386 of the Italian Civil Code (with exception of the director appointed pursuant to Article 6.2 letter d) of these By-laws). In any case, compliance with the required minimum number of independent directors and the applicable rules concerning gender balance shall not be affected. If a majority of the directors should vacate their offices, the entire Board shall be considered to have resigned, and the Board shall promptly call a Shareholders’ Meeting to elect a new Board.
17.6		The Board may establish internal committees to provide advice and proposals on specific issues.

ARTICLE 18

18.1		If the Shareholders’ Meeting has not appointed a Chairman, the Board shall elect one from among its members. The director appointed pursuant to Article 6.2, letter d) of the By-laws cannot be appointed as Chairman.
18.2		The Board, acting upon a proposal of the Chairman, shall appoint a Secretary, who need not be affiliated with the Company.

ARTICLE 19

19.1		The Board shall meet in the place indicated in the meeting notice whenever the Chairman or, in the event of his absence or impediment, the Chief Executive Officer deems necessary, or when a written request has been made by the majority of its members. The Board of Directors may also be convened pursuant to Article 28.4 of these By-laws. The meetings of the Board of Directors may be held by video or teleconference on the condition that all of the participants in the meeting can be identified and that all can follow and participate in real time in the discussion of the matters being addressed. The meeting shall be considered duly held in the place where the Chairman and the Secretary are present.
19.2		Notice shall normally be given at least five days in advance of the meeting. In urgent circumstances, the period of notice may be shorter. The Board of Directors shall decide how its meetings are to be convened.
19.3		The Board of Directors shall also be convened when so requested by at least two directors or by one director if the Board consists of three directors, to decide on a specific matter deemed to be of particular importance regarding the management of the Company. Said matter shall be specified in the request.

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ARTICLE 20
20.1		The Chairman of the Board or, in his absence, the eldest director in attendance shall chair the meeting.
ARTICLE 21
21.1		For a Board meeting to be valid, a majority of serving directors with voting rights must be present.
21.2		Resolutions shall be approved by a majority of the votes of the directors with voting rights present; in the event of a tie, the person who chairs the meeting shall have a casting vote.
ARTICLE 22
22.1		The resolutions of the Board of Directors shall be registered in the minutes, which shall be recorded in a book kept for that purpose pursuant to the provisions of law, and said minutes shall signed by the Chairman of the meeting and by the Secretary.
22.2		Copies of the minutes shall be considered bona fide if they are signed by the Chairman or the person acting in place of the Chairman and countersigned by the Secretary.
ARTICLE 23
23.1		The Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or these By-laws reserve to the Shareholders’ Meeting.
23.2		The Board of Directors shall decide the following matters:

-		the merger and proportional demerger of companies in which the Company owns shares or other equity holdings representing at least 90% of the share capital;
-		the establishment and closing of branches;
-		the amendment of the By-laws to comply with the provisions of law.

23.3		The Board of Directors and the Chief Executive Officer shall promptly report to the Board of Statutory Auditors at least every three months and in any event at the time of the meetings of the Board of Directors, on the activity carried out and on the transactions with the most significant impact on performance and the financial position carried out by the Company and its subsidiaries. In particular they shall report to the Board of Statutory Auditors those transactions in which they have an interest, either on their own behalf or on behalf of third parties.
ARTICLE 24
24.1		The Board of Directors may delegate its powers to one of its members with the exception of the director appointed pursuant to Article 6.2, letter d) of these By-laws, within the limits set forth in Article 2381 of the Italian Civil Code. The Board may, in addition, delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may revoke delegated powers at any time, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors with the exception of the director appointed pursuant to Article 6.2, letter d) of these By-laws. The Chairman and the Chief Executive Officer, within the limits of the authority attributed to them, may delegate and empower Company employees or third parties to represent the Company for individual acts or specific categories of acts. Further, acting upon proposal of the Chief Executive Officer and in agreement with the Chairman, the Board of Directors may also appoint one or more General Managers (Chief Operating Officers) and determine the powers to be conferred on them, once it has been ascertained that they fulfill the integrity requirements set by law. The Board of Directors shall periodically check the continuing compliance with integrity requirements of the General Managers (Chief Operating Officers). Failure to satisfy these requirements shall result in disqualification from the position. Acting upon a proposal of the Chief Executive Officer, in agreement with the Chairman and with the approval of the Board of Statutory Auditors, the Board of Directors shall appoint the Officer responsible for preparing financial reporting documents. The Officer responsible for preparing financial reporting documents shall be selected from among those persons who, for at least three years, have performed:

		a)		administration, control or management activities in companies listed on regulated stock exchanges in Italy or other European Union countries or other OECD countries with a share capital of no less than euro 2 million; or
		b)		statutory audit activities in companies indicated in letter a) above; or
		c)		professional activities or university teaching activities in the financial or accounting sectors; or
		d)		management functions in public or private entities with financial, accounting or control expertise.

The Board of Directors shall ensure that the Officer responsible for preparing the financial reporting documents has adequate powers and means to perform the duties of the position and that administrative and accounting procedures are being followed.

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ARTICLE 25
25.1		The Chairman and the Chief Executive Officer are severally vested with powers of legal representation of the Company before any judicial or administrative authority and with respect to third parties and exercise signature powers on behalf of the Company.
ARTICLE 26
26.1		The Chairman and the members of the Board of Directors shall be entitled to compensation to be determined by the ordinary Shareholders’ Meeting. Said resolution, once taken, shall remain valid for subsequent financial years until the Shareholders’ Meeting should decide otherwise.
ARTICLE 27
27.1		The Chairman:

a)		represents the Company pursuant to Article 25.1;
b)		chairs the Shareholders’ Meeting pursuant to Article 15.1;
c)		calls and chairs meetings of the Board of Directors pursuant to Articles 19.1 and 20.1;
d)		verifies that Board resolutions are implemented;
e)		exercises the powers delegated to him by the Board of Directors pursuant to Article 24.1.

Part VI – The Board of Statutory Auditors

ARTICLE 28
28.1		The Board of Statutory Auditors shall consist of five standing members and two alternate members, chosen from among persons who satisfy the professional and integrity requirements established by the Ministry of Justice Decree No. 162 of March 30, 2000. Pursuant to the aforementioned decree, the fields closely connected with the business of the Company are: commercial law, business economics and corporate finance. Similarly, the sectors closely connected with the business of the Company are engineering and geology. The Statutory Auditors may be appointed as members of the administrative and control bodies of other companies within the limits set by Consob regulations.
28.2		The Board of Statutory Auditors shall be appointed by the Shareholders’ Meeting on the basis of slates presented by shareholders. The candidates shall be listed on the slates in numerical order in a number no greater than the number of members of the body to be appointed. The procedures set out in Article 17.3 and the provisions issued in Consob regulations shall apply to the submission, filing and publication of candidate slates. Slates shall be divided into two sections: the first containing candidates for appointment as standing Statutory Auditors and the second containing candidates for appointment as alternate Statutory Auditors. At least the first candidate in each section must be entered in the register of auditors and have carried out statutory audit activities for no less than three years. Slates that, considering both sections together, contain three or more candidates shall include, in the section for standing Statutory Auditors, candidates of both genders, as specified in the notice calling the Shareholders’ Meeting, in order to comply with the applicable gender-balance legislation. If the section for alternate Statutory Auditors on these slates contains two candidates, they must be of different genders. When the number of members of the less-represented gender must, by law, be at least one, such requirement shall apply only to slates competing to appoint the majority of the members of the Board of Statutory Auditors. Three standing Statutory Auditors and one alternate Statutory Auditor shall be drawn from the slate that receives the majority of votes. The other two standing Statutory Auditors and the other alternate Statutory Auditor shall be appointed using the procedures set out in Article 17.3, letter b) of the By-laws. Said procedures shall be applied separately to each section of the other slates. The Shareholders’ Meeting shall appoint the Chairman of the Board of Statutory Auditors from among the standing Statutory Auditors appointed in accordance with Article 17.3 letter b) of these By-laws. Where the application of the procedure set out above does not permit compliance with the gender-balance rules for standing Statutory Auditors, the points to attribute to each candidate drawn from the standing Statutory Auditor sections of the various slates shall be calculated by dividing the number of votes received by each slate by the ordinal number of each of these candidates; the candidate of the over-represented gender with the fewest points from among the candidates drawn from all of the slates shall be replaced by the member of the less-represented gender who may be listed (with the next highest ordinal number) in the standing Statutory Auditor section on the same slate as the candidate to be replaced or, subordinately, in the alternate Statutory Auditor section of the same slate as the candidate to be replaced (in such case, the latter shall take the position of the alternate candidate that replaces him/her). If this does not permit compliance with the gender-balance rules, he/she shall be replaced by a person chosen by the Shareholders’ Meeting with the majority required by law, so as to ensure that the membership of the Board of Statutory Auditors complies with the law and the By-laws. In cases where candidates from different lists have received the same number of points, the candidate from the slate from which the largest number of Statutory Auditors has been drawn or, subordinately, the candidate drawn from the

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slate receiving the fewest number of votes, or, in the event of a tie vote, the candidate that receives the fewest votes of the Shareholders’ Meeting in a run-off election, shall be replaced. For the appointment of Statutory Auditors who, for any reason, are not appointed using the above procedures, the Shareholders’ Meeting shall resolve, with the majorities required by law, in such a manner as to ensure that the membership of the Board of Statutory Auditors complies with the law and the By-laws. The slate voting procedure shall apply only in case of appointment of the entire Board of Statutory Auditors. Should a standing Statutory Auditor from the slate that received a majority of the votes be replaced, the replacement shall be the alternate Statutory Auditor from the same slate; should a standing Statutory Auditor from other slates be replaced, the replacement shall be the alternate Statutory Auditor from those other slates. If the replacement results in non-compliance with gender-balance rules, the Shareholders’ Meeting shall be called as soon as possible to approve the necessary resolutions to ensure compliance.

28.3		Statutory Auditors may be re-elected.
28.4		Subject to prior notification of the Chairman of the Board of Directors, the Board of Statutory Auditors may call Shareholders’ Meetings and meetings of the Board of Directors. The power to call a meeting of the Board of Directors may be exercised individually by each member of the Board of Statutory Auditors; at least two Statutory Auditors are required to call Shareholders’ Meetings. The meetings of the Board of Statutory Auditors may be held by video or teleconference on the condition that all of the participants in the meetings can be identified and that all can follow and participate in real time in the discussion of the matters being addressed. The meeting shall be considered duly held in the place where the Chairman and the Secretary are present.

Part VII – Financial Statements and Profits

ARTICLE 29
29.1		The Company’s financial year ends on December 31 of each year.
29.2		At the end of each financial year, the Board of Directors shall prepare the Company financial statements in compliance with the provisions of law.
29.3		The Board of Directors may distribute interim dividends to the shareholders during the financial year.
ARTICLE 30
30.1		Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.

Part VIII – Winding Up and Liquidation of the Company

ARTICLE 31
31.1		In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration.

Part IX – General Provisions

ARTICLE 32
32.1		For all matters not expressly governed by these By-laws, the Italian Civil Code and applicable special laws shall apply.
32.2		Pursuant to Article 3, paragraph 2, of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994, Article 6.1, sixth paragraph, of these By-laws shall not apply to the shareholdings owned by the Ministry of the Economy and Finance, public entities or entities they control.
ARTICLE 33
33.1		The Company retains all legal relationships in respect of assets and liabilities held by the public agency Ente Nazionale Idrocarburi before its transformation.

ARTICLE 34
34.1		The provisions of Articles 17.3, 17.5 and 28.2 directed to ensure compliance with applicable gender-balance legislation shall apply to the first three elections of the Board of Directors and Board of Statutory Auditors after August 12, 2012.

 

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EXHIBIT 8

List of Eni’s subsidiaries for the 2012

Subsidiary		Country of Incorporation		Eni’s share of net profit (%)

EXPLORATION & PRODUCTION
Eni Angola SpA		Italy		100.00
Eni East Africa SpA		Italy		100.00
Eni Mediterranea Idrocarburi SpA		Italy		100.00
Eni Timor Leste SpA		Italy		100.00
Eni West Africa SpA		Italy		100.00
Eni Zubair SpA		Italy		100.00
Ieoc SpA		Italy		100.00
Società Adriatica Idrocarburi SpA		Italy		100.00
Società Ionica Gas SpA		Italy		100.00
Società Oleodotti Meridionali - SOM SpA		Italy		70.00
Società Petrolifera Italiana SpA		Italy		99.96
Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA		Italy		100.00
Agip Caspian Sea BV		Netherlands		100.00
Agip Energy and Natural Resources (Nigeria) Ltd		Nigeria		100.00
Agip Karachaganak BV		Netherlands		100.00
Agip Oil Ecuador BV		Netherlands		100.00
Burren Energy (Bermuda) Ltd		Bermuda		100.00
Burren Energy Congo Ltd		British Virgin Islands		100.00
Burren Energy India Ltd		United Kingdom		100.00
Burren Energy Ltd		Cyprus		100.00
Burren Energy Plc		United Kingdom		100.00
Burren Energy (Services) Ltd		United Kingdom		100.00
Burren Resources Petroleum Ltd		Bermuda		100.00
Burren Shakti Ltd		Bermuda		100.00
Eni AEP Ltd		United Kingdom		100.00
Eni Algeria Exploration BV		Netherlands		100.00
Eni Algeria Ltd Sàrl		Luxembourg		100.00
Eni Algeria Production BV		Netherlands		100.00
Eni Ambalat Ltd		United Kingdom		100.00
Eni America Ltd		United States of America		100.00
Eni Angola Exploration BV		Netherlands		100.00
Eni Angola Production BV		Netherlands		100.00
Eni Arguni I Ltd		United Kingdom		100.00
Eni Australia BV		Netherlands		100.00
Eni Australia Ltd		United Kingdom		100.00
Eni BB Petroleum Inc		United States of America		100.00
Eni Bukat Ltd		United Kingdom		100.00
Eni Bulungan BV		Netherlands		100.00
Eni Canada Holding Ltd		Canada		100.00
Eni CBM Ltd		United Kingdom		100.00
Eni China BV		Netherlands		100.00
Eni Congo SA		Republic of the Congo		100.00
Eni Croatia BV		Netherlands		100.00
Eni Dación BV		Netherlands		100.00
Eni Denmark BV		Netherlands		100.00
Eni East Sepinggan Ltd		United Kingdom		100.00
Eni Elgin/Franklin Ltd		United Kingdom		100.00
Eni Energy Russia BV		Netherlands		100.00
Eni Exploration & Production Holding BV		Netherlands		100.00
Eni Gabon SA		Gabon		99.96
Eni Ganal Ltd		United Kingdom		100.00
Eni Gas & Power LNG Australia BV		Netherlands		100.00

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Eni Ghana Exploration and Production Ltd		Ghana		100.00
Eni Hewett Ltd		United Kingdom		100.00
Eni India Ltd		United Kingdom		100.00
Eni Indonesia Ltd		United Kingdom		100.00
Eni International NA NV Sàrl		Luxembourg		100.00
Eni International Resources Ltd		United Kingdom		100.00
Eni Investments Plc		United Kingdom		100.00
Eni Iran BV		Netherlands		100.00
Eni Iraq BV		Netherlands		100.00
Eni Ireland BV		Netherlands		100.00
Eni JPDA 03-13 Ltd		United Kingdom		100.00
Eni JPDA 06-105 Pty Ltd		Australia		100.00
Eni JPDA 11-106 BV		Netherlands		100.00
Eni Krueng Mane Ltd		United Kingdom		100.00
Eni Lasmo Plc		United Kingdom		100.00
Eni Liberia BV		Netherlands		100.00
Eni LNS Ltd		United Kingdom		100.00
Eni Mali BV		Netherlands		100.00
Eni Marketing Inc		United States of America		100.00
Eni Middle East BV		Netherlands		100.00
Eni Middle East Ltd		United Kingdom		100.00
Eni MOG Ltd (in liquidation)		United Kingdom		100.00
Eni Muara Bakau BV		Netherlands		100.00
Eni Norge AS		Norway		100.00
Eni North Africa BV		Netherlands		100.00
Eni North Ganal Ltd		United Kingdom		100.00
Eni Oil Algeria Ltd		United Kingdom		100.00
Eni Oil & Gas Inc		United States of America		100.00
Eni Oil Holdings BV		Netherlands		100.00
Eni Pakistan Ltd		United Kingdom		100.00
Eni Pakistan (M) Ltd Sàrl		Luxembourg		100.00
Eni Papalang Ltd		United Kingdom		100.00
Eni Petroleum Co Inc		United States of America		100.00
Eni Petroleum US Llc		United States of America		100.00
Eni Polska spólka z ograniczona odpowiedzialnoscia		Poland		100.00
Eni Popodi Ltd		United Kingdom		100.00
Eni Rapak Ltd		United Kingdom		100.00
Eni RD Congo SPRL		Democratic Republic of the Congo		100.00
Eni South Salawati Ltd		United Kingdom		100.00
Eni TNS Ltd		United Kingdom		100.00
Eni Togo BV		Netherlands		100.00
Eni Transportation Ltd		United Kingdom		100.00
Eni Trinidad and Tobago Ltd		Trinidad & Tobago		100.00
Eni Tunisia BV		Netherlands		100.00
Eni UHL Ltd		United Kingdom		100.00
Eni UKCS Ltd		United Kingdom		100.00
Eni UK Holding Plc		United Kingdom		100.00
Eni UK Ltd		United Kingdom		100.00
Eni Ukraine Holdings BV		Netherlands		100.00
Eni Ukraine Llc		Ukraine		100.00
Eni ULT Ltd		United Kingdom		100.00
Eni ULX Ltd		United Kingdom		100.00
Eni USA Gas Marketing Llc		United States of America		100.00
Eni USA Inc		United States of America		100.00
Eni US Operating Co Inc		United States of America		100.00
Eni Venezuela BV		Netherlands		100.00
Eni West Timor Ltd		United Kingdom		100.00
First Calgary Petroleums LP		United States of America		100.00
First Calgary Petroleums Partner Co ULC		Canada		100.00
Hindustan Oil Exploration Co Ltd		India		47.18
Ieoc Exploration BV		Netherlands		100.00
Ieoc Production BV		Netherlands		100.00
Lasmo Sanga Sanga Ltd		Bermuda		100.00

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Nigerian Agip Exploration Ltd		Nigeria		100.00
Nigerian Agip Oil Co Ltd		Nigeria		100.00
OOO 'Eni Energhia'		Russia		100.00
GAS & POWER
EniPower Mantova SpA		Italy		86.50
EniPower SpA		Italy		100.00
LNG Shipping SpA		Italy		100.00
Società EniPower Ferrara Srl		Italy		51.00
Trans Tunisian Pipeline Co SpA (former Trans Tunisian Pipeline Co Ltd)		Italy		100.00
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana		Slovenia		51.00
Distribuidora de Gas Cuyana SA		Argentina		45.60
Distrigas LNG Shipping SA		Belgium		100.00
Eni G&P France BV		Netherlands		100.00
Eni G&P Trading BV		Netherlands		100.00
Eni Gas & Power France SA (former Altergaz SA)		France		99.74
Eni Gas & Power GmbH		Germany		100.00
Eni Gas & Power NV (former Distrigas NV)		Belgium		100.00
Eni Gas Transport Services SA		Switzerland		100.00
Eni Power Generation NV		Belgium		100.00
Eni Wind Belgium NV		Belgium		100.00
Finpipe GIE		Belgium		63.33
Inversora de Gas Cuyana SA		Argentina		76.00
Société de Service du Gazoduc Transtunisien SA - Sergaz SA		Tunisia		66.67
Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA		Tunisia		100.00
Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság		Hungary		52.77
Tigáz-Dso Földgázelosztó kft		Hungary		52.77
REFINING & MARKETING
Costiero Gas Livorno SpA		Italy		65.00
Ecofuel SpA		Italy		100.00
Eni Fuel Centrosud SpA		Italy		100.00
Eni Fuel Nord SpA		Italy		100.00
Eni Rete oil&nonoil SpA		Italy		100.00
Eni trading&shipping SpA		Italy		100.00
Petrolig Srl		Italy		70.00
Petroven Srl		Italy		68.00
Raffineria di Gela SpA		Italy		100.00
Eni Austria GmbH		Austria		100.00
Eni Benelux BV		Netherlands		100.00
Eni Ceská Republika Sro		Czech Republic		100.00
Eni Deutschland GmbH		Germany		100.00
Eni Ecuador SA		Ecuador		100.00
Eni France Sàrl		France		100.00
Eni Hungaria Zrt		Hungary		100.00
Eni Iberia SLU		Spain		100.00
Eni Marketing Austria GmbH		Austria		100.00
Eni Mineralölhandel GmbH		Austria		100.00
Eni Romania Srl		Romania		100.00
Eni Schmiertechnik GmbH		Germany		100.00
Eni Slovenija doo		Slovenia		100.00
Eni Slovensko Spol Sro		Slovakia		100.00
Eni Suisse SA		Switzerland		100.00
Eni Trading & Shipping BV		Netherlands		100.00
Eni trading&shipping Inc		United States of America		100.00
Eni USA R&M Co Inc		United States of America		100.00
Esain SA		Ecuador		100.00

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CHEMICALS
Versalis SpA (former Polimeri Europa SpA)		Italy		100.00
Dunastyr Polisztirolgyártó Zártkoruen Mukodo Részvénytársaság		Hungary		100.00
Eni Chemicals Trading (Shanghai) Co Ltd		China		100.00
Polimeri Europa France SAS		France		100.00
Polimeri Europa GmbH		Germany		100.00
Polimeri Europa Ibérica SA		Spain		100.00
Polimeri Europa UK Ltd		United Kingdom		100.00
Versalis International SA (former Polimeri Europa Benelux SA)		Belgium		100.00
Versalis Pacific Trading (Shanghai) Co Ltd		China		100.00
ENGINEERING & CONSTRUCTION
Saipem SpA		Italy		43.12
Denuke Scarl		Italy		23.72
Servizi Energia Italia SpA		Italy		43.12
SnamprogettiChiyoda SAS di Saipem SpA		Italy		43.08
Andromeda Consultoria Tecnica e Representações Ltda		Brazil		43.12
Boscongo SA		Republic of the Congo		43.12
Construction Saipem Canada Inc		Canada		43.12
ER SAI Caspian Contractor Llc		Kazakhstan		21.56
ERS - Equipment Rental & Services BV		Netherlands		43.12
ERSAI Marine Llc		Kazakhstan		21.56
Global Petroprojects Services AG		Switzerland		43.12
Moss Maritime AS		Norway		43.12
Moss Maritime Inc		United States of America		43.12
North Caspian Service Co		Kazakhstan		43.12
Petrex SA		Peru		43.12
Professional Training Center Llc		Kazakhstan		21.56
PT Saipem Indonesia		Indonesia		43.12
Saigut SA de Cv		Mexico		43.12
Saimexicana SA de Cv		Mexico		43.12
Saipem (Beijing) Technical Services Co Ltd		China		43.12
Saipem (Malaysia) Sdn Bhd		Malaysia		17.84
Saipem (Nigeria) Ltd		Nigeria		38.55
Saipem (Portugal) Comércio Marítimo, Sociedade Unipessoal Lda		Portugal		43.12
Saipem America Inc		United States of America		43.12
Saipem Asia Sdn Bhd		Malaysia		43.12
Saipem Australia Pty Ltd		Australia		43.12
Saipem Contracting (Nigeria) Ltd		Nigeria		42.23
Saipem Contracting Algérie SpA		Algeria		43.12
Saipem Contracting Netherlands BV		Netherlands		43.12
Saipem do Brasil Serviçõs de Petroleo Ltda		Brazil		43.12
Saipem Drilling Co Private Ltd		India		43.12
Saipem Drilling Norway AS		Norway		43.12
Saipem India Projects Ltd		India		43.12
Saipem International BV		Netherlands		43.12
Saipem Libya Llc - SA.LI.CO. Llc		Libya		43.12
Saipem Ltd		United Kingdom		43.12
Saipem Luxembourg SA		Luxembourg		43.12
Saipem Maritime Asset Management Luxembourg Sàrl		Luxembourg		43.12
Saipem Mediteran Usluge doo (in liquidation)		Croatia		43.12
Saipem Misr for Petroleum Services SAE		Egypt		43.12
Saipem Norge AS		Norway		43.12
Saipem Offshore Norway AS		Norway		43.12
Saipem SA		France		43.12
Saipem Services México SA de Cv		Mexico		43.12
Saipem Services SA		Belgium		43.12
Saipem Singapore Pte Ltd		Singapore		43.12

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Saipem UK Ltd (in liquidation)		United Kingdom		43.12
Saipem Ukraine Llc		Ukraine		43.12
Sajer Iraq Co for Petroleum Services Trading General Contracting & Transport Llc		Iraq		25.87
Saudi Arabian Saipem Ltd		Saudi Arabia		25.87
Sigurd Rück AG		Switzerland		43.12
Snamprogetti Canada Inc		Canada		43.12
Snamprogetti Engineering BV		Netherlands		43.12
Snamprogetti Ltd (in liquidation)		United Kingdom		43.12
Snamprogetti Lummus Gas Ltd		Malta		42.69
Snamprogetti Netherlands BV		Netherlands		43.12
Snamprogetti Romania Srl		Romania		43.12
Snamprogetti Saudi Arabia Co Ltd Llc		Saudi Arabia		43.12
Sofresid Engineering SA		France		43.12
Sofresid SA		France		43.12
Sonsub International Pty Ltd		Australia		43.12
Varisal - Serviços de Consultadoria e Marketing Unipessoal Lda		Portugal		43.12
OTHER ACTIVITIES
Syndial SpA - Attività Diversificate		Italy		100.00
Ing. Luigi Conti Vecchi SpA		Italy		100.00
CORPORATE AND FINANCIAL COMPANIES
Agenzia Giornalistica Italia SpA		Italy		100.00
Eni Adfin SpA (former Eni Administration & Financial Service SpA)		Italy		99.63
Eni Corporate University SpA		Italy		100.00
EniServizi SpA		Italy		100.00
Serfactoring SpA		Italy		48.82
Servizi Aerei SpA		Italy		100.00
Banque Eni SA		Belgium		100.00
Eni Finance International SA		Belgium		100.00
Eni Finance USA Inc		United States of America		100.00
Eni Insurance Ltd		Ireland		100.00
Eni International BV		Netherlands		100.00

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EXHIBIT 11

Code of Ethics

Approved by the Board of Directors of Eni SpA on March 14, 2008
The English text is a translation of the Italian official "Code of Ethics"
For any conflict or discrepancies between the two texts the Italian text shall prevail

 

TABLE OF CONTENTS

Foreword

I. GENERAL PRINCIPLES: SUSTAINABILITY AND CORPORATE RESPONSIBILITY

II. BEHAVIOUR RULES AND RELATIONS WITH STAKEHOLDERS
1. Ethics, transparency, fairness, professionalism
2. Relations with shareholders and with the Market
2.1. Value for shareholders, efficiency, transparency
2.2. Self-Regulatory Code
2.3. Company information
2.4. Privileged information
2.5. Media
3. Relations with institutions, associations, local communities
3.1. Authorities and Public Institutions
3.2. Political organizations and trade unions
3.3. Development of local Communities
3.4. Promotion of "non profit" activities
4. Relations with customers and suppliers
4.1. Customers and consumers
4.2. Suppliers and external collaborators
5. Eni’s management, employees, collaborators
5.1. Development and protection of Human Resources
5.2. Knowledge Management
5.3. Corporate security
5.4. Harassment or mobbing in the workplace
5.5. Abuse of alcohol or drugs and no smoking

III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS
1. System of internal control
1.1. Conflicts of interest
1.2. Transparency of accounting records
2. Health, safety, environment and public safety protection
3. Research, innovation and intellectual property protection
4. Confidentiality
4.1. Protection of business secret
4.2. Protection of privacy
4.3. Membership in associations, participation in initiatives, events or external meetings

IV. CODE OF ETHICS SCOPE OF APPLICATION AND REFERENCE STRUCTURES
1. Obligation to know the Code and to report any possible violation thereof
2. Reference structures and supervision
2.1. Guarantor of the Code of Ethics
2.2. Code Promotion Team
3. Code review
4. Contractual value of the Code

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FOREWORD

Eni¹ is an internationally oriented industrial group which, because of its size and the importance of its activities, plays a significant role in the marketplace and in the economic development and welfare of the individuals who work or collaborate with Eni and of the communities where it is present.

The complexity of the situations in which Eni operates, the challenges of sustainable development and the need to take into consideration the interests of all people having a legitimate interest in the corporate business ("Stakeholders"), strengthen the importance to clearly define the values that Eni accepts, acknowledges and shares as well as the responsibilities it assumes, contributing to a better future for everybody.

For this reason the new Eni’s Code of Ethics ("Code" or "Code of Ethics") has been devised.

Compliance with the Code by Eni’s directors, statutory auditors, management and employees as well as by all those who operate in Italy and abroad for achieving Eni’s objectives ("Eni’s People"), each within their own functions and responsibilities, is of paramount importance – also pursuant to legal and contractual provisions governing the relationship with Eni – for Eni’s efficiency, reliability and reputation, which are all crucial factors for its success and for improving the social situation in which Eni operates.

Eni undertakes to promote knowledge of the Code among Eni’s People and the other Stakeholders, and to accept their constructive contribution to the Code’s principles and contents. Eni undertakes to take into consideration any suggestions and remarks of Stakeholders, with the objective of confirming or integrating the Code.

Eni carefully checks for compliance with the Code by providing suitable information, prevention and control tools and ensuring transparency in all transactions and behaviours by taking corrective measures if and as required.

The Watch Structure of each Eni company performs the functions of guarantor of the Code of Ethics ("Guarantor").

The Code is brought to the attention of every person or body having business relations with Eni.

 

 

 

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(1)

"Eni" means Eni SpA and its direct and indirect subsidiaries, in Italy and abroad.

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I. GENERAL PRINCIPLES: SUSTAINABILITY AND CORPORATE RESPONSIBILITY

Compliance with the law, regulations, statutory provisions, self-regulatory codes, ethical integrity and fairness, is a constant commitment and duty of all Eni’s People, and characterizes the conduct of Eni’s entire organization.
Eni’s business and corporate activities has to be carried out in a transparent, honest and fair way, in good faith, and in full compliance with competition protection rules.
Eni undertakes to maintain and strengthen a governance system in line with international best practice standards, able to deal with the complex situations in which Eni operates, and with the challenges to face for sustainable development.
Systematic methods for involving Stakeholders are adopted, fostering dialogue on sustainability and corporate responsibility.
In conducting both its activities as an international company and those with its partners, Eni stands up for the protection and promotion of human rights – inalienable and fundamental prerogatives of human beings and basis for the establishment of societies founded on principles of equality, solidarity, repudiation of war, and for the protection of civil and political rights, of social, economic and cultural rights and the so-called third generation rights (selfdetermination right, right to peace, right to development and protection of the environment).
Any form of discrimination, corruption, forced or child labor is rejected. Particular attention is paid to the acknowledgement and safeguarding of the dignity, freedom and equality of human beings, to protection of labor and of the freedom of trade union association, of health, safety, the environment and biodiversity, as well as the set of values and principles concerning transparency, energy efficiency and sustainable development, in accordance with International Institutions and Conventions.
In this respect Eni operates within the reference framework of the United Nations Universal Declaration of Human Rights, the Fundamental Conventions of the ILO – International Labor Organization – and the OECD Guidelines on Multinational Enterprises.
All Eni’s People, without any distinction or exception whatsoever, respect the principles and contents of the Code in their actions and behaviours while performing their functions and according to their responsibilities, because compliance with the Code is fundamental for the quality of their working and professional performance. Relationships among Eni’s People, at all levels, must be characterized by honesty, fairness, cooperation, loyalty and mutual respect.
The belief that one is acting in favor or to the advantage of Eni can never, in any way, justify – not even in part – any behaviours that conflict with the principles and contents of the Code.

 

II. BEHAVIOUR RULES AND RELATIONS WITH STAKEHOLDERS

1. ETHICS, TRANSPARENCY, FAIRNESS, PROFESSIONALISM

In conducting its business, Eni is inspired by and complies with the principles of loyalty, fairness, transparency, efficiency and an open market, regardless of the importance level of the transaction in question.
Any action, transaction and negotiation performed and, generally, the conduct of Eni’s People in the performance of their duties is inspired by the highest principles of fairness, completeness and transparency of information and legitimacy, both in form and substance, as well as clarity and truthfulness of all accounting documents, in compliance with the applicable laws in force and internal regulations.
All Eni’s activities have to be performed with the utmost care and professional skill, with the duty to provide skills and expertise adequate to the tasks assigned, and to act in a way capable to protect Eni’s image and reputation. Corporate objectives, as well as the proposal and implementation of projects, investments and actions, have to be aimed at improving the company’s assets, management, technological and information level in the long term, and at creating value and welfare for all Stakeholders.
Bribes, illegitimate favours, collusion, requests for personal benefits for oneself or others, either directly or through third parties, are prohibited without any exception.
It is prohibited to pay or offer, directly or indirectly, money and material benefits and other advantages of any kind to third parties, whether representatives of governments, public officers and public servants or private employees, in order to influence or remunerate the actions of their office.
Commercial courtesy, such as small gifts or forms of hospitality, is only allowed when its value is small and it does not compromise the integrity and reputation of either party, and cannot be construed by an impartial observer as aimed at obtaining undue advantages. In any case, these expenses must always be authorized by the designated managers as per existing internal rules, and be accompanied by appropriate documentation.
It is forbidden to accept money from individuals or companies that have or intend to have business relations with Eni. Anyone who receives proposals of gifts or special or hospitality treatment that cannot be considered as commercial courtesy of small value, or requests therefore by third parties, shall reject them and immediately inform their superior, or the body they belong to, as well as the Guarantor.
Eni shall properly inform all third parties about the commitments and obligations provided for in the Code, require third parties to respect the principles of the Code relevant to their activities and take proper internal actions and, if the matter is within its own competence, external actions in the event that any third party should fail to comply with the Code.

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2. RELATIONS WITH SHAREHOLDERS AND WITH THE MARKET

2.1. Value for shareholders, efficiency, transparency
The internal structure of Eni and the relations with the parties directly and indirectly taking part in its activities are organized according to rules able to ensure management reliability and a fair balance between the management’s powers and the interests of shareholders and of the other Stakeholders in general as well as transparency and market traceability of management decisions and general corporate events which may considerably influence the market value of the financial instruments issued.
Within the framework of the initiatives aimed at maximizing the value for shareholders and at guaranteeing transparency of the management’s work, Eni defines, implements and progressively adjusts a coordinated and homogeneous set of behaviour rules concerning both its internal organizational structure and relations with shareholders and third parties, in compliance with the highest corporate governance standards at national and international level, based on the awareness that the company’s capacity to impose efficient and effective functioning rules upon itself is a fundamental tool for strengthening its reputation in terms of reliability and transparency as well as Stakeholders’ trust.
Eni deems it necessary that shareholders are enabled to participate in decisions which come within the limits of their competence and make informed choices. Therefore, Eni undertakes to ensure maximum transparency and timeliness of information communicated to shareholders and to the market – by means of the corporate internet site, too – in compliance with the laws and regulations applicable to listed companies. Moreover, Eni undertakes to keep in due consideration the legitimate remarks expressed by shareholders whenever they are entitled to do so.

2.2. Self-Regulatory Code
The main corporate governance rules of Eni are contained in the Self-Regulatory Code of Eni SpA, adopted in compliance with the Code promoted by Borsa Italiana SpA, which is referred to herein as far as applicable.

2.3. Company information
Eni ensures the correct management of company information, by means of suitable procedures for in-house management and communication to the outside.

2.4. Privileged information
All Eni’s People are required, while performing the tasks entrusted to them, to properly manage privileged information such as to know and comply with corporate procedures referring to market abuse. Insider trading and any behaviour that may promote insider trading are expressly forbidden. In any case, the purchase or sale of shares of Eni or of companies outside Eni shall always be based on absolute and transparent fairness.

2.5. Media
Eni undertakes to provide outside parties with true, prompt, transparent and accurate information.
Relations with the media are exclusively dealt with by the departments and managers specifically appointed to do so; information to be supplied to media representatives, as well as the undertaking to provide such information, have to be agreed upon beforehand by Eni’s People with the relevant Eni Corporate structure.

3. RELATIONS WITH INSTITUTIONS, ASSOCIATIONS, LOCAL COMMUNITIES

Eni encourages dialogue with Institutions and with organized associations of civil society in all the countries where it operates.

3.1. Authorities and Public Institutions
Eni, through its People, actively and fully cooperates with Authorities.
Eni’s People, as well as external collaborators whose actions may somehow be referred to Eni, must have behaviours towards the Public Administration characterized by fairness, transparency and traceability. These relations have to be exclusively dealt with by the departments and individuals specifically appointed to do so, in compliance with approved plans and corporate procedures.
The departments of the subsidiaries concerned shall coordinate with the relevant Eni Corporate structure for assessing the quality of the interventions to be carried out and for the sharing, implementing and monitoring of their actions.
It is forbidden to make, induce or encourage false statements to Authorities.

3.2. Political organizations and trade unions
Eni does not make any direct or indirect contributions in whatever form to political parties, movements, committees, political organizations and trade unions, nor to their representatives and candidates, except those specifically contemplated by applicable laws and regulations.

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3.3. Development of local Communities
Eni is committed to actively contribute to promoting the quality of life, the socio-economic development of the communities where Eni operates and to the development of their human resources and capabilities, while conducting its business activities according to standards that are compatible with fair commercial practices.
Eni’s activities are carried out in the awareness of the social responsibility that Eni has towards all of its Stakeholders and in particular the local communities in which it operates, in the belief that the capacity for dialogue and interaction with civil society constitutes an important asset for the company. Eni respects the cultural, economic and social rights of the local communities in which it operates and undertakes to contribute, as far as possible, to their exercise, with particular reference to the right to adequate nutrition, drinking water, the highest achievable level of physical and mental health, decent dwellings, education, abstaining from actions that may hinder or prevent the exercise of such rights.
Eni promotes transparency of the information addressed to local communities, with particular reference to the topics that they are most interested in. Forms of continuous and informed consultancy are either promoted, through the relevant Eni structures, in order to take into due consideration the legitimate expectations of local communities in conceiving and conducting corporate activities and in order to promote a proper redistribution of the profits deriving from such activities.
Eni, therefore, undertakes to promote the knowledge of its corporate values and principles, at every level of its organization, also through adequate control procedures, and to protect the rights of local communities, with particular reference to their culture, institutions, ties and life styles.
Within the framework of their respective responsibilities, Eni’s People are required to participate in the definition of single initiatives in compliance with Eni’s policies and intervention programs, to implement them according to criteria of absolute transparency and support them as an integral part of Eni’s objectives.

3.4. Promotion of "non profit" activities
The philanthropic activity of Eni is in line with its vision and attention to sustainable development.
Therefore, Eni undertakes to foster and support, as well as to promote among its People, its "non profit" activities which demonstrate the company’s commitment to help meet the needs of those communities where it operates.

4. RELATIONS WITH CUSTOMERS AND SUPPLIERS

4.1 Customers and consumers
Eni pursues its business success on markets by offering quality products and services under competitive conditions while respecting the rules protecting fair competition.
Eni undertakes to respect the right of consumers not to receive products harmful to their health and physical integrity and to get complete information on the products offered to them.
Eni acknowledges that the esteem of those requesting products or services is of primary importance for success in business. Business policies are aimed at ensuring the quality of goods and services, safety and compliance with the precautionary principle. Therefore, Eni’s People shall:

4.2. Suppliers and external collaborators
Eni undertakes to look for suppliers and external collaborators with suitable professionalism and committed to sharing the principles and contents of the Code and promotes the establishment of long-lasting relations for the progressive improvement of performances while protecting and promoting the principles and contents of the Code.
In relationships regarding tenders, procurement and, generally, the supply of goods and/or services and of external collaborations (including consultants, agents, etc.), Eni’s People shall:

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The remuneration to be paid shall be exclusively proportionate to the services to be rendered and described in the contract and payments shall not be allowed to any party different from the contract party nor in a third Country different from the one of the parties or where the contract has to be performed.

5. ENI’S MANAGEMENT, EMPLOYEES, COLLABORATORS

5.1. Development and protection of Human Resources
People are basic components in the company’s life. The dedication and professionalism of management and employees represent fundamental values and conditions for achieving Eni’s objectives.
Eni is committed to developing the abilities and skills of management and employees so that their energy and creativity can have full expression for the fulfilment of their potential in their working performance, such as to protect working conditions as regards both mental and physical health and dignity. Undue pressure or discomfort is not allowed, while appropriate working conditions promoting development of personality and professionalism are fostered.
Eni undertakes to offer, in full compliance with applicable legal and contractual provisions, equal opportunities to all its employees, making sure that each of them receives a fair statutory and wage treatment exclusively based on merit and expertise, without discrimination of any kind. Competent departments shall:

Eni wishes that Eni’s People, at every level, cooperate in maintaining a climate of common respect for a person’s dignity, honour and reputation. Eni shall do its best to prevent attitudes that can be considered as offensive, discriminatory or abusive. In this regard, any behaviours outside the working place which are particularly offensive to public sensitivity are also deemed relevant.
In any case, any behaviours constituting physical or moral violence are forbidden without any exception.

5.2. Knowledge Management
Eni promotes culture and the initiatives aimed at disseminating knowledge within its structures, and at pointing out the values, principles, behaviours and contributions in terms of innovation of professional families in connection with the development of business activities and to the company’s sustainable growth.
Eni undertakes to offer tools for interaction among the members of professional families, working groups and communities of practice, as well as for coordination and access to know-how, and shall promote initiatives for the growth, dissemination and systematization of knowledge relating to the core competences of its structures and aimed at defining a reference framework suitable for guaranteeing operating consistency.
All Eni’s People shall actively contribute to Knowledge Management as regards the activities that they are in charge of, in order to optimize the system for knowledge sharing and distribution among individuals.

5.3. Corporate security
Eni engages in the study, development and implementation of strategies, policies and operational plans aimed at preventing and overcoming any intentional or non-intentional behaviour which may cause direct or indirect damage to Eni’s People and/or to the tangible and intangible resources of the company. Preventive and defensive measures, aimed at minimizing the need for an active response – always in proportion to the attack – to threats to people and assets, are favored.
All Eni’s People shall actively contribute to maintaining an optimal corporate security standard, abstaining from unlawful or dangerous behaviours, and reporting any possible activities carried out by third parties to the detriment of Eni’s assets or human resources to superiors or to the body they belong to, as well as to the relevant Eni Corporate structure.
In any case requiring particular attention to personal safety, it is compulsory to strictly follow the indications in this regard supplied by Eni, abstaining from behaviours which may endanger one’s own safety or the safety of others, promptly reporting any danger for one’s own safety, or the safety of third parties, to one’s superior.

5.4. Harassment or mobbing in the workplace
Eni supports any initiatives aimed at implementing working methods for the achievement of a better organization.
Eni demands that there shall be no harassment or mobbing behaviours in personal working relationships either inside or outside the company. Such behaviours are all forbidden, without exceptions, and are:

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Any form of violence or harassment, either sexual harassment or harassment based on personal and cultural diversity, is forbidden. Such harassment is for instance:

5.5. Abuse of alcohol or drugs and no smoking
All Eni’s People shall personally contribute to promoting and maintaining a climate of common respect in the workplace; particular attention is paid to respect of the feelings of others.
Eni will therefore consider individuals who work under the effect of alcohol or drugs, or substances with similar effect, during the performance of their work activities and in the workplace, as being aware of the risk they cause. Chronic addiction to such substances, when it affects work performance, shall be considered similar to the above mentioned events in terms of contractual consequences; Eni is committed to favour social action in this field as provided for by employment contracts.
It is forbidden to:

 

III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS

1. SYSTEM OF INTERNAL CONTROL

Eni undertakes to promote and maintain an adequate system of internal control, i.e. all the necessary or useful tools for addressing, managing and checking activities in the company, aimed at ensuring compliance with corporate laws and procedures, at protecting corporate assets, efficiently managing activities and providing precise and complete accounting and financial information.
The responsibility for implementing an effective system of internal control is shared at every level of Eni’s organizational structure; therefore, all Eni’s People, according to their functions and responsibilities, shall define and actively participate in the correct functioning of the system of internal control.
Eni promotes the dissemination, at every level of its organization, of policies and procedures characterized by awareness of the existence of controls and by an informed and voluntary control oriented mentality; consequently, Eni’s management in the first place and all Eni’s People in any case shall contribute to and participate in Eni’s system of internal control and, with a positive attitude, involve its collaborators in this respect.
Each employee shall be held responsible for the corporate tangible and intangible assets relevant to his/her job. No employee can make, or let others make, improper use of assets and equipment belonging to Eni.
Any practices and attitudes linked to the perpetration or to the participation in the perpetration of frauds are forbidden without any exception.
Control and supervisory bodies, Eni Internal Audit department and appointed auditing companies shall have full access to all data, documents and information necessary to perform their own relevant activities.

1.1. Conflicts of interest
Eni acknowledges and respects the right of its People to take part in investments, business and other kinds of activities other than the activity performed in the interest of Eni, provided that such activities are permitted by law and are compatible with the obligations assumed towards Eni. The Self-Regulatory Code of Eni SpA governs any possible conflict of interest of directors and statutory auditors of Eni SpA.
Eni’s management and employees shall avoid and report any conflicts of interest between personal and family economic activities and their tasks within the company. In particular, everyone shall point out any specific situations and activities of economic or financial interest (owner or member) to them or, as far as they know, of economic or financial interest to relatives of theirs or relatives by marriage within the 2^nd degree of kinship, or to persons actually living with them, also involving suppliers, customers, competitors, third parties, or the relevant controlling companies or subsidiaries, and shall point whether they perform corporate administration or control or management functions therein.
Moreover, conflicts of interest are determined by the following situations:

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In any case, Eni’s management and employees shall avoid any situation and activity where a conflict with the Company’s interests may arise, or which can interfere with their ability to make impartial decisions in the best interests of Eni and in full accordance with the principles and contents of the Code, or in general with their ability to fully comply with their functions and responsibilities. Any situation that may constitute or give rise to a conflict of interest shall be immediately reported to one’s superior within management, or to the body one belongs to, and to the Guarantor. Furthermore, the party concerned shall abstain from taking part in the operational/decision-making process, and the relevant superior within management, or the relevant body, shall:

1.2.Transparency of accounting records
Accounting transparency is grounded on the use of true, accurate and complete information which form the basis for the entries in the books of accounts. Each member of company bodies, of management or employee shall cooperate, within their own field of competence, in order to have operational events properly and timely registered in the books of accounts.
It is forbidden to behave in a way that may adversely affect transparency and traceability of the information within financial statements.
For each transaction, the proper supporting evidence has to be maintained in order to allow:

Each record shall reflect exactly what is shown by the supporting evidence. All Eni’s People shall cause that the documentation can be easily traced and filed according to logical criteria.
Eni’s People who become aware of any omissions, forgery, negligence in accounting or in the documents on which accounting is based, shall bring the facts to the attention of their superior, or to the body they belong to, and to the Guarantor.

2. HEALTH, SAFETY, ENVIRONMENT AND PUBLIC SAFETY PROTECTION

Eni’s activities shall be carried out in compliance with applicable worker health and safety, environmental and public safety protection agreements, international standards and laws, regulations, administrative practices and national policies of the Countries where it operates.
Eni actively contributes as appropriate to the promotion of scientific and technological development aimed at protecting the environment and natural resources. The operative management of such activities shall be carried out according to advanced criteria for the protection of the environment and energy efficiency, with the aim of creating better working conditions and protecting the health and safety of employees as well as the environment.
Eni’s People shall, within their areas of responsibility, actively participate in the process of risk prevention as well as environmental, public safety and health protection for themselves, their colleagues and third parties.

3. RESEARCH, INNOVATION AND INTELLECTUAL PROPERTY PROTECTION

Eni promotes research and innovation activities by management and employees, within their functions and responsibilities. Any intellectual assets generated by such activities are an important and fundamental heritage of Eni.
Research and innovation focus in particular on the promotion of products, tools, processes and behaviours supporting energy efficiency, reduction of environmental impact, attention to health and safety of employees, of customers and of the local communities where Eni operates, and in general sustainability of business activities.
Eni’s People shall actively contribute, within their functions and responsibilities, to managing intellectual property in order to allow its development, protection and enhancement.

4. CONFIDENTIALITY

4.1. Protection of business secret
Eni’s activities constantly require the acquisition, storing, processing, communication and dissemination of information, documents and other data regarding negotiations, administrative proceedings, financial transactions, and know-how (contracts, deeds, reports, notes, studies, drawings, pictures, software, etc.) that may not be disclosed to the

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outside pursuant to contractual agreements, or whose inopportune or untimely disclosure may be detrimental to corporate interest.
Without prejudice to the transparency of the activities carried out and to the information obligations imposed by the provisions in force, Eni’s People shall ensure the confidentiality required by the circumstances for each piece of news they have got to know of because of their working function.
Any information, knowledge and data acquired or processed during one’s work or because of one’s tasks at Eni, belong to Eni and may not be used, communicated or disclosed without specific authorization of one’s superior within management in compliance with specific procedures.

4.2. Protection of privacy
Eni is committed to protecting information concerning its People and third parties, whether generated or obtained inside Eni or in the conduct of Eni’s business, and to avoiding improper use of any such information.
Eni intends to guarantee that processing of personal data within its structures respects fundamental rights and freedoms, as well as the dignity of the parties concerned, as contemplated by the legal provisions in force.
Personal data must be processed in a lawful and fair way and, in any case, the data collected and stored is only that which is necessary for certain, explicit and lawful purposes. Data shall be stored for a period of time no longer than necessary for the purposes of collection.
Eni undertakes moreover to adopt suitable preventive safety measures for all databases storing and keeping personal data, in order to avoid any risks of destruction and losses or of unauthorized access or unallowed processing.
Eni’s People shall:

4.3. Membership in associations, participation in initiatives, events or external meetings
Membership in associations, participation in initiatives, events or external meetings is supported by Eni if compatible with the working or professional activity provided. Membership and participation considered as such are:

In this regard, Eni’s management and employees in charge of illustrating, or providing to the outside data or news concerning Eni’s objectives, aims, results and points of view, shall not only comply with corporate procedures relating to market abuse, but also obtain the necessary authorization from their superior within management for the lines of action to follow and the texts as well as reports drawn up, such as to agree on contents with the relevant Eni Corporate structure.

 

IV. CODE OF ETHICS SCOPE OF APPLICATION AND REFERENCE STRUCTURES

The principles and contents of the Code apply to Eni’s People and activities.
Any listed subsidiaries and power & gas sector subsidiaries subject to unbundling shall receive the Code and adopt it, adjusting it – if necessary – to the characteristics of their company, consistently with their management independence.
The representatives indicated by Eni in the company bodies of partially owned companies, in consortia and in joint ventures shall promote the principles and contents of the Code within their own respective areas of competence.
Directors and management must be the first to give concrete form to the principles and contents of the Code, by assuming responsibility for them both towards the inside and the outside and by enhancing trust, cohesion and a sense of team-work, as well as providing a behaviour model for their collaborators in order to have them comply with the Code and make questions and suggestions on specific provisions.
To achieve full compliance with the Code, each of Eni’s People may even apply directly to the Guarantor.

1. OBLIGATION TO KNOW THE CODE AND TO REPORT ANY POSSIBLE VIOLATION THEREOF

Each of Eni’s People is expected to know the principles and contents of the Code as well as the reference procedures governing own functions and responsibilities.
Each of Eni’s People shall:

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Eni’s People are not allowed to conduct personal investigations, nor to exchange information, except to their superiors, or to the body that they belong to, and to the Guarantor. If, after notifying a supposed violation any of Eni’s People feels that he or she has been subject to retaliation, then he or she may directly apply to the Guarantor.

2. REFERENCE STRUCTURES AND SUPERVISION

Eni is committed to ensuring, even through the Guarantor’s appointment:

2.1. Guarantor of the Code of Ethics
The Code of Ethics is, among other things, a compulsory general principle of the Organizational, Management and Control Model adopted by Eni SpA according to the Italian provision on the "administrative liability of legal entities deriving from offences" contained in Legislative Decree No. 231 of June 8, 2001.
Eni SpA assigns the functions of Guarantor to the Watch Structure established pursuant to the above mentioned Model. Each direct or indirect subsidiary, in Italy and abroad, entrusts the function of Guarantor to its own Watch Structure by formal deed of the relevant corporate body.
The Guarantor is entrusted with the task of:

Moreover, the Guarantor of Eni SpA submits to the Internal Control Committee and to the Board of Statutory Auditors as well as to the Chairman and to the Chief Executive Officer, which report about it to the Board of Directors, a six-monthly report on the implementation and possible need for updating the Code.
For the performance of its tasks, the Guarantor of Eni SpA avails itself of "Technical Secretariat of the Watch Structure 231 of Eni SpA" that reports thereto and is supported by the relevant Structures of Eni SpA. The Technical Secretariat is responsible for starting and maintaining an adequate reporting and communication flow to and from the Guarantors of subsidiaries.
Each information flow is to be sent to the following email address:
organismo_di_vigilanza@eni.it

2.2. Code Promotion Team
The Code is made available to Eni’s People in compliance with applicable standards, and is also available on the internet and intranet sites of Eni SpA and of subsidiaries.
In order to promote the knowledge and facilitate the implementation of the Code, a Code Promotion Team reporting to the Guarantor of Eni SpA has been established. The Team makes available within Eni all possible tools for understanding and clarifying the interpretation and the implementation of the Code.
The members of the Team are chosen by the Chief Executive Officer of Eni SpA upon proposal of the Guarantor of Eni SpA.

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3. CODE REVIEW

The Code review is approved by the Board of Directors of Eni SpA, upon proposal of the Chief Executive Officer with the agreement of the Chairman, after hearing the opinion of the Board of Statutory Auditors.
The proposal is made taking into consideration the Stakeholders’ evaluation with reference to the principles and contents of the Code, promoting active contribution and notification of possible deficiencies by Stakeholders themselves.

4. CONTRACTUAL VALUE OF THE CODE

Respect of the Code’s rules is an essential part of the contractual obligations of all Eni’s People pursuant to and in accordance with applicable law.
Any violation of the Code’s principles and contents may be considered as a violation of primary obligations under labour relations or of the rules of discipline and can entail the consequences provided for by law, including termination of the work contract and compensation for damages arising out of any violation.

 

 

 

 

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Certifications as separate documents filed as exhibits

EXHIBIT 12.1

Certification

 

I, Paolo Scaroni, certify that:

1.

I have reviewed this annual report on Form 20-F of Eni SpA;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.

The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting;

5.

The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Date: April 9, 2013

 

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EXHIBIT 12.2

Certification

 

I, Massimo Mondazzi, certify that:

1.

I have reviewed this annual report on Form 20-F of Eni SpA;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.

The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting;

5.

The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Date: April 9, 2013

 

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EXHIBIT 13.1

 

Certification Pursuant to 18 U.S.C. Section 1350

 

For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the "Company"), hereby certifies, to such officer’s knowledge, that:

(i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2012 (the "Report") fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 9, 2013

 

 

The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act.

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EXHIBIT 13.2

 

Certification Pursuant to 18 U.S.C. Section 1350

 

For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the "Company"), hereby certifies, to such officer’s knowledge, that:

(i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2012 (the "Report") fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 9, 2013

 

 

The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act.

 

 

 

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EXHIBIT 15.a(i)

 

 

DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

 

February 28, 2013

 

 

 

Eni S.p.A.
E&P Division
Ms. Manuela Feudaroli
Vice President, Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

 

Dear Ms. Feudaroli:

Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved crude oil, condensate, liquefied petroleum gas (LPG), and natural gas reserves, as of December 31, 2012, of certain properties in Africa, Asia, and Europe owned by Eni S.p.A. (Eni). This evaluation was completed on February 28, 2013. Eni has represented that these properties account for 11.7 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2012, and that Eni’s net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Eni that it represents to be Eni’s estimates of the net reserves, as of December 31, 2012, for the same properties as those which we have independently evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Eni.

Reserves included herein are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2012. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Eni after deducting interests owned by others.

 

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Estimates of oil, condensate, LPG, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Eni personnel, from Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

 

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

 

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Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate.

Eni has represented that its estimates of condensate and LPG are reported only in combination, since there is no material economic effect in separating the quantities.

 

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Reserves classifications used for our estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Eni has represented that its estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using known production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and

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engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in

 

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the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12 month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

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(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

 

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, and LPG Prices

Eni has represented that the oil, LPG, and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A Brent oil price of 111 United States dollars (U.S.$) per barrel (U.S.$/bbl) was the resulting reference price. Where appropriate, Eni supplied differentials by field to the relevant reference price, and the prices were held constant thereafter. Eni has represented that LPG and condensate are not separately considered. The volume-weighted average prices in this report were as follows:

 

 

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		Oil (U.S.$/bbl)		Condensate and LPG (U.S.$/bbl)

Africa		106.66		93.21
Asia		116.44		-
Europe		-		60.54
Average for Total		106.72		92.71

Natural Gas Prices

Eni has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A significant quantity of the gas sold by Eni is subject to contract prices, and the range of such prices is varied. A reference price is the United Kingdom National Balancing Point Index, which was U.S.$9.50 per million British thermal units. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices in this report were as follows, expressed in United States dollars per thousand cubic feet (U.S.$/Mcf):

		Gas (U.S.$/Mcf)

Africa		4.03
Asia		-
Europe		10.52
Average for Total		6.73

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Eni, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used

 

 

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DEGOLYER AND MACNAUGHTON

8

 

 

 

because of anticipated changes in operating conditions. These costs were not escalated for inflation.

 

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil, condensate, LPG, and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the oil, condensate, LPG, and gas reserves as of December 31, 2012, estimated herein. The reserves estimated in this report can be produced under current regulatory guidelines.

Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Africa, Asia, and Europe are based on the definitions of proved reserves of the SEC. Eni represents that its estimates of the net proved reserves attributable to these properties, which represent 11.7 percent of Eni’s reserves on a net equivalent basis, are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

 

		Estimated by Eni Net Proved Reserves as of December 31, 2012

		Oil (MMbbl)		Condensate and LPG (MMbbl)		Marketable Gas (Bcf)		Oil Equivalent (MMboe)
Properties reviewed by DeGolyer and MacNaughton
Total Proved		428		20		2,163		841

Note: Gas is converted to oil equivalent using a factor of 5,492 cubic feet of gas per 1 barrel of oil equivalent.

 

In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

 

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DEGOLYER AND MACNAUGHTON

9

 

 

 

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative, resulting in an aggregate difference of less than 5 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

	Submitted,
	/s/ DEGOLYER AND MACNAUGHTON
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

 

	/s/ LLOYD W. CADE, P.E.
	Lloyd W. Cade, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

 

 

 

 

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DEGOLYER AND MACNAUGHTON

 

 

 

 

CERTIFICATE of QUALIFICATION

I, Lloyd W. Cade Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.		That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Eni dated February 28, 2013, and that I, as Senior Vice President, was responsible for the preparation of this report.
2.		That I attended Kansas State University, and that I graduated with a Bachelor of Science degree in Mechanical Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have approximately 30 years of experience in oil and gas reservoir studies and reserves evaluations.

 

 

 

SIGNED: February 28, 2013

 

 

 

	/s/ LLOYD W. CADE, P.E.
	Lloyd W. Cade, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

 

 

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EXHIBIT 15.a(ii)

 

Eni S.p.A.

 

 

 

 

Estimated

Future Reserves and Income

Attributable to Certain

Interests

 

 

 

SEC Parameters

 

 

As of

December 31, 2012

\s\ Herman Acuña		\s\ Gabrielle Guerre
Herman G. Acuña, P.E.		Gabrielle Guerre, P.E.
TBPE License No. 92254		TBPE License No. 109935
Managing Senior Vice President – International		Petroleum Engineer

 

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580

 

[SEAL]

[SEAL]

 

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

 

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February 15, 2013

 

Eni S.p.A
E&P Division
Ms. Manuela Feudaroli
Vice President Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

Dear Ms. Feudaroli:

At the request of Eni S.p.A. (Eni), Ryder Scott Company, L.P (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni’s engineering and geological staff as of December 31, 2012 based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on February 14, 2013 and presented herein, was prepared for public disclosure by Eni in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Eni has indicated that the proved net reserves attributable to the properties that we reviewed account for 22 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations:

• Africa
• Asia
• Americas

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as "the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities."

Based on our review, including the data, technical processes and interpretations presented by Eni, it is our opinion that the overall procedures and methodologies utilized by Eni in preparing their estimates of the proved reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott’s estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

 

 

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Eni S.p.A. – Third Party
February 15, 2013
Page 2

 

The conclusions discussed in this report, as of December 31, 2012, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott.

 

Reserves Included in This Report

In our opinion, the proved reserves discussed herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled "Petroleum Reserves Status Definitions and Guidelines" in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein.

Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are "those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward." The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered."

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 15, 2013
Page 3

 

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

 

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 15, 2013
Page 4

 

identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely than not to be achieved." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy methods, the volumetric method, or a combination of performance and volumetric methods. These performance methods include, but may not be limited to, decline curve analysis and analogy which utilized extrapolations of historical production and pressure data available through December 2012 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Eni and were considered sufficient for the purpose thereof. The volumetric method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Eni that were available through December 2012. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 15, 2013
Page 5

 

prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Eni. We consider the factual data used in this report appropriate and sufficient for the purpose of our investigations.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to conduct the audit of reserves of the properties described herein. The proved reserves discussed herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves reviewed in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

 

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Eni. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 15, 2013
Page 6

 

Eni furnished us with the above mentioned average prices in effect on December 31, 2012. Eni has assured us that these initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. The average dated Brent oil price of $111/bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. All gas prices shown below are in dollars per thousand cubic meters ($/kmc). The average realized prices provided by Eni and used in our evaluation are as follows:

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Eni. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Eni to determine these differentials.

 

Costs

Operating costs used in our evaluation were based on the operating expense reports of Eni and include only those costs directly applicable to the evaluated assets. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Eni. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets.

Development costs were furnished to us by Eni and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Eni were accepted without independent verification.

The proved developed and undeveloped reserves in this report have been incorporated herein in accordance with Eni’s plans to develop these reserves as of December 31, 2012. The implementation of Eni’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Eni’s management. As the result of our inquires during the course of

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 15, 2013
Page 7

 

preparing this report, Eni has informed us that the development activities included herein have been subjected to and received the internal approvals required by Eni’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Eni. Additionally, Eni has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Eni were held constant throughout the life of the properties.

 

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Eni. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

 

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Eni.

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Eni S.p.A. – Third Party
February 15, 2013
Page 8

 

We have provided Eni with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Eni and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

 

	Very truly yours,
	RYDER SCOTT COMPANY, L. P.
	TBPE Firm Registration No. F-1580
	/s/ HERMAN G. ACUÑA, P.E.
	Herman G. Acuna, P.E.
	Texas P.E. License No. 92254
[SEAL]	Managing Senior Vice President – International
	\s\ GABRIELLE GUERRE
	Gabrielle Guerre, P.E.
	TBPE License No. 109935
	Petroleum Engineer
	[SEAL]
HGA(DPR)/pl

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the independent estimation of the reserves, future production and income to render the audit conclusions of the report.

Mr. Acuña, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1997, is a Managing Senior International Vice President and Board Member. He serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas, a member of the Association of International Petroleum Negotiators (AIPN) and the Society of Petroleum Engineers (SPE).

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. Mr. Acuña has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Acuña has recently taught various company reserves evaluation schools in Argentina, China, Denmark, Spain and the U.S.A. Mr. Acuña has participated in various capacities in reserves conferences such as being a panelist at Trinidad and Tobago’s Petroleum Conference, delivering the reserves evaluation seminar during IAPG convention in Mendoza, Argentina and chairing the first Reserves Evaluation Conference in the Middle East in Dubai, U.A.E.

Based on his educational background, professional training and over 20 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

 

 

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the "Modernization of Oil and Gas Reporting; Final Rule" in the Federal Register of National Archives and Records Administration (NARA). The "Modernization of Oil and Gas Reporting; Final Rule" includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The "Modernization of Oil and Gas Reporting; Final Rule", including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the "SEC Regulations". The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.

 

 

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These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

 

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

 

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

 

 

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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

 

 

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

 

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 

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Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In
Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing;
(2) wells which were shut-in for market conditions or pipeline connections; or
(3) wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

 

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

 

 

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