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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, 2008
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)
Alessandro Bernini
Eni SpA
1, piazza Ezio Vanoni
San Donato Milanese
20097 Milano
Italy
Tel +39 02 52041730
Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
————————————————————
Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
                                        Ordinary shares of euro 1.00 each                                                                                                                                                                 4,005,358,876

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 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			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	i	i
PART I		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	3
i	i	Exchange Rates	i	5
i	i	Risk Factors	i	5
Item 4.	i	INFORMATION ON THE COMPANY	i	17
i	i	History and Development of the Company	i	17
i	i	Business Overview	i	21
i	i	Exploration & Production	i	21
i	i	Gas & Power	i	50
i	i	Refining & Marketing	i	62
i	i	Engineering & Construction	i	69
i	i	Petrochemicals	i	71
i	i	Corporate and Other activities	i	73
i	i	Research and Development	i	74
i	i	Insurance	i	74
i	i	Environmental Matters	i	74
i	i	Regulation of Eni’s Businesses	i	79
i	i	Property, Plant and Equipment	i	88
i	i	Organizational Structure	i	88
Item 4A.	i	UNRESOLVED STAFF COMMENTS	i	88
Item 5.	i	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	i	88
i	i	Executive Summary	i	89
i	i	Critical Accounting Estimates	i	91
i	i	2006-2008 Group Results of Operations	i	95
i	i	Liquidity and Capital Resources	i	105
i	i	Recent Developments	i	111
i	i	Management’s Expectations of Operations	i	113
Item 6.	i	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	i	118
i	i	Directors and Senior Management	i	118
i	i	Board Practices	i	122
i	i	Compensation	i	130
i	i	Employees	i	137
iii	i	Share Ownership	i	138
Item 7.	i	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	i	139
i	i	Major Shareholders	i	139
i	i	Related Party Transactions	i	139
Item 8.	i	FINANCIAL INFORMATION	i	139
i	i	Consolidated Statements and Other Financial Information	i	139
i	i	Significant Changes	i	148
Item 9.	i	THE OFFER AND THE LISTING	i	148
i	i	Offer and Listing Details	i	148
i	i	Markets	i	149
Item 10.	i	ADDITIONAL INFORMATION	i	150
i	i	Memorandum and Articles of Association	i	150
i	i	Material Contracts	i	156
i	i	Documents on Display	i	157
i	i	Exchange Controls	i	157
i	i	Taxation	i	157

Item 11.	i	QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK	i	161
Item 12.	i	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	i	161
i	i	i	i	i
PART II	i	i	i	i
Item 13.	i	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	i	162
Item 14.	i	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	i	162
Item 15.	i	CONTROLS AND PROCEDURES	i	162
Item 16.	i		i
16A.	i	Board of Statutory Auditors Financial Expert	i	163
16B.	i	Code of Ethics	i	163
16C.	i	Principal Accountant Fees and Services	i	163
16D.	i	Exemptions from the Listing Standards for Audit Committees	i	164
16E.	i	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	i	164
16G	i	Corporate Governance Practices	i	165
i	ii	i	i	i
PART III	i	i	i	i
Item 17.	i	FINANCIAL STATEMENTS	i	168
Item 18.	i	FINANCIAL STATEMENTS	i	168
Item 19.	i	EXHIBITS	i	168

i

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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 – Qualitative and Quantitative 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.

 

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 www.eni.it. 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
Associated gas		Natural gas, occurring in the form of a gas cap, overlying an oil zone, contained in the reservoir’s crude oil 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		These are light hydrocarbons produced along with gas that condense to a liquid state at surface temperature and pressure.
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.
Conversion index		Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
Deep waters		Waters deeper than 200 meters.
Development		Drilling and other post-exploration activities aimed at the production of oil and gas.

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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 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.
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 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.

 

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Proved reserves		Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of the impact of changes in existing prices on existing contractual arrangements, but not on escalations based upon future conditions. Proved reserves include: (i) proved developed reserves: amounts of hydrocarbons that are expected to be retrieved through existing wells, facilities and operating methods; and (ii) non-developed proved reserves: amounts of hydrocarbons that are expected to be retrieved following new drilling, facilities and operating methods. Based on these amounts the company has already defined a clear development expenditure program which is an expression of the company’s determination to develop existing reserves.
Reserve life index		Ratio between the amount of proved reserves at the end of the year and total production for the year.
Reserve replacement ratio		Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.
Ship-or-pay		Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
Strategic Storage		According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
Take-or-pay		Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
Upstream/Downstream		The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.

 

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ABBREVIATIONS

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

 

CONVERSION TABLE

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

 

 

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

 

 

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB). The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2004, 2005, 2006, 2007 and 2008. The selected historical financial data for the years ended December 31, 2004, 2005, 2006, 2007 and 2008 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.

	Year ended December 31,

	2004		2005		2006		2007		2008

CONSOLIDATED PROFIT STATEMENT DATA
Net sales from operations		57,545			73,728			86,105			87,256			108,148
Operating profit by segment
Exploration & Production		8,185			12,592			15,580			13,788			16,415
Gas & Power		3,428			3,321			3,802			4,127			3,933
Refining & Marketing		1,080			1,857			319			729			(1,023	)
Petrochemicals		320			202			172			74			(822	)
Engineering & Construction		203			307			505			837			1,045
Other activities		(395	)		(934	)		(622	)		(444	)		(346	)
Corporate and financial companies		(363	)		(377	)		(296	)		(217	)		(686	)
Impact of unrealized intragroup profit elimination (1)		(59	)		(141	)		(133	)		(26	)		125
Operating profit		12,399			16,827			19,327			18,868			18,641
Net profit attributable to Eni		7,059			8,788			9,217			10,011			8,825
Data per ordinary share (euro) (2)
Operating profit:
- basic		3.29			4.48			5.23			5.14			5.12
- diluted		3.28			4.47			5.22			5.14			5.12
Net profit attributable to Eni basic and diluted		1.87			2.34			2.49			2.73			2.43
Data per ADR ($) (2) (3)
Operating profit:
- basic		8.18			11.14			13.13			14.10			15.07
- diluted		8.17			11.12			13.12			14.10			15.07
Net profit attributable to Eni basic and diluted		4.66			5.82			6.26			7.48			7.14

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Table of Contents

	As of December 31,

	2004		2005		2006		2007		2008

CONSOLIDATED BALANCE SHEET DATA
Total assets		72,853		83,850		88,312		101,460		116,590
Short-term and long-term debt		12,684		12,998		11,699		19,830		20,837
Capital stock issued		4,004		4,005		4,005		4,005		4,005
Minority interest		3,166		2,349		2,170		2,439		4,074
Shareholders’ equity - Eni share		32,374		36,868		39,029		40,428		44,436
Capital expenditures		7,499		7,414		7,833		10,593		14,562
Weighted average number of ordinary shares outstanding (fully diluted - shares million)		3,775		3,763		3,701		3,669		3,639
Dividend per share (euro)		0.90		1.10		1.25		1.30		1.30
Dividend per ADR ($) (2)		2.17		2.73		3.24		3.74		3.72

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(1)	i	This item concerned mainly intra-group sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end of the period.
(2)	i	Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. From 2006, one ADR represents two Eni shares. Previously, one ADR was equivalent to five Eni shares. Data per ADR for the years 2004-2005 have been recalculated accordingly.
(3)	i	Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S. $ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2004 through 2007 have been 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. Eni started to pay an interim dividend in 2005. The dividend for 2008 was converted at the Noon Buying Rate recorded on the payment date of the interim dividend (euro 0.65 per share) which occurred on September 25, 2008. The balance of euro 0.65 per share payable on May 21 and May 29, 2009 for the holders of the Eni share and the ADR respectively was translated at the Noon Buying Rate as recorded on December 31, 2008. On May 4, 2009, the Noon Buying Rate was $1.34 per euro 1.00.

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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, 2004, 2005, 2006, 2007 and 2008. 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 or cost method of accounting.

	Year ended December 31,

	2004		2005		2006		2007		2008

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)		3,972		3,748		3,457		3,127		3,243
of which developed		2,471		2,331		2,126		1,953		2,009
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)		36		25		24		142		142
of which developed				19		18		26		33
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF)		18,278		17,501		16,897		16,549		17,214
of which developed		10,501		11,159		10,949		10,967		11,138
Proved reserves of natural gas of equity-accounted entities at period end (BCF)		157		90		68		3,022		3,015
of which developed				70		48		428		420
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)		7,154		6,796		6,400		6,010		6,242
of which developed		4,300		4,275		4,032		3,862		3,948
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end (a)		64		41		36		668		666
of which developed				31		27		101		107
Reserve replacement ratio (2)		91		43		38		38		136
Average daily production of liquids (KBBL/d)		1,034		1,111		1,079		1,020		1,026
Average daily production of natural gas available for sale (mmCF/d) (3)		3,171		3,344		3,679		3,819		4,143
Average daily production of hydrocarbons available for sale (KBOE/d) (3)		1,586		1,693		1,720		1,684		1,748
Hydrocarbon production sold (mmBOE)		576.5		614.9		625.1		611.4		632.0
Oil and gas production costs per BOE (4)				5.59		5.79		6.90		7.77
Profit per barrel of oil equivalent (5)				12.20		14.97		14.03		15.80

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(a)		Mainly refers to Eni’s share of proved reserves relating to three Russian companies purchased in 2007 by Eni as part of a bid procedure for assets of bankrupt Yukos (Eni’s share was 60%). Gazprom was granted an option to acquire a 51% interest in these three entities. Considering that Gazprom has exercised its call option, Eni’s interest will be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition will be reduced by approximately 50%.
(1)		Includes approximately 737, 760, 754, 749 and 746 BCF of natural gas held in storage in Italy at December 31, 2004, 2005, 2006, 2007 and 2008, respectively. See "Item 4 – Information on the Company – Exploration & Production – Storage".
(2)		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 SFAS 69. See the unaudited supplemental oil and gas information in Item 18 – Notes to the Consolidated Financial Statements. Expressed as a percentage.
(3)		Natural gas production volumes exclude gas consumed in operations (220, 251, 286, 296 and 281 mmCF/d in 2004, 2005, 2006, 2007 and 2008, respectively).
(4)		Expressed in U.S. dollars. Consists of production costs (costs incurred to operate and maintain wells and field equipment including also royalties) prepared in accordance with IFRS divided by actual production net of production volumes of natural gas consumed in operations. See the unaudited supplemental oil and gas information in Item 18 – Notes to the Consolidated Financial Statements. Data for the years prior to 2005 are not available as they were prepared in accordance with U.S. GAAP.
(5)		Expressed in U.S. dollars. Results of operations from oil and gas producing activities, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations. 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. Data for the years prior to 2005 are not available as they were in accordance with U.S. GAAP. Includes results of operations of joint ventures and other equity-accounted entities which results were immaterial.

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Selected Operating Information continued

	Year ended December 31,

	2004		2005		2006		2007		2008

Sales of natural gas to third parties (6)		72.79		77.08		79.63		78.75		83.69
Natural gas consumed by Eni (6)		3.70		5.54		6.13		6.08		5.63
Sales of natural gas of affiliates (Eni’s share) (6)		5.84		7.08		7.65		8.74		8.91
Total sales and own consumption of natural gas of the Gas & Power segment (6)		82.33		89.70		93.41		93.57		98.23
E&P natural gas sales in Europe and in the Gulf of Mexico (6) (7)		4.70		4.51		4.69		5.39		6.00
Worldwide natural gas sales (6)		87.03		94.21		98.10		98.96		104.23
Transport of natural gas for third parties in Italy (6)		28.26		30.22		30.90		30.89		33.84
Length of natural gas transport network in Italy at period end (8)		30.2		30.7		30.9		31.1		31.5
Electricity sold (9)		16.95		27.56		31.03		33.19		29.93
Refinery throughputs (10)		35.75		36.68		36.27		35.21		33.98
Balanced capacity of wholly-owned refineries (11)		504		524		534		544		544
Retail sales (in Italy and rest of Europe) (10)		14.40		13.72		12.48		12.65		12.67
Number of service stations at period end (in Italy and rest of Europe)		9,140		6,282		6,294		6,440		5,956
Average throughput per service station (in Italy and rest of Europe) (12)		2,488		2,479		2,470		2,486		2,502
Petrochemical production (10)		7.12		7.28		7.07		8.80		7.37
Engineering & Construction order backlog at period end (13)		8,521		10,122		13,191		15,390		19,105
Employees at period end (units)		70,348		72,258		73,572		75,862		78,880

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(6)		Expressed in BCM.
(7)		From 2006, also includes E&P sales of volumes of natural gas produced in the Gulf of Mexico.
(8)		Expressed in thousand kilometers.
(9)		Expressed in TWh.
(10)		Expressed in mmtonnes.
(11)		Expressed in KBBL/d.
(12)		Expressed in thousand liters per day. Refers to the Agip branded network only, as in years up to 2005 Eni also sold refined products on the "IP" branded network of service stations in Italy.
(13)		The sum of the order backlog of Saipem SpA and Snamprogetti SpA, expressed in million euro.

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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,
2004		1.36		1.18		1.24		1.35
2005		1.35		1.17		1.24		1.18
2006		1.33		1.19		1.26		1.32
2007		1.49		1.29		1.37		1.46
2008		1.60		1.24		1.47		1.39

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(1)

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

 

	High		Low		At period end

(U.S. dollars per euro)

November 2008		1.30		1.25		1.27
December 2008		1.44		1.26		1.39
January 2009		1.39		1.28		1.28
February 2009		1.31		1.25		1.27
March 2009		1.37		1.25		1.31
April 2009		1.35		1.30		1.32
May 2009 (through May 4, 2009)		1.34		1.33		1.34

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 May 4, 2009 was $1.34 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 encounters competition from other oil and natural gas companies in all areas of its operations.

•		In the Exploration & Production business, Eni faces competition from both international oil companies and state run oil companies in a number of geographic markets for obtaining exploration and development rights, and developing and applying new technology to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage in many of these markets 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 Eni fails to obtain new exploration and development acreage or to apply and develop new technology, its growth prospects and future results of operations and cash flows may be adversely affected.
•		Eni is increasingly in competition with state run oil companies who are partners of Eni in a number of oil and gas projects and titles in the host countries where Eni conducts its upstream operations. These state run 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, by this way reducing Eni’s profit share. For example, Sonatrach, the Algeria national oil company, is seeking to modify the contractual terms of certain PSAs in which Eni is party to achieve a redistribution of the tax burden of such PSAs. Sonatrach alleges that it is currently bearing part of the tax burden attributable to Eni following the enactment of certain modifications to the

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		country’s tax regime. If this negotiation results in a negative outcome for Eni, the future profitability of certain of Eni’s PSAs in Algeria will be reduced. For more information on this matter see "Item 4 – Exploration & Production – Algeria".
•		In its domestic natural gas business, Eni faces increasingly strong competition from both national and international natural gas suppliers, particularly following the liberalization of the Italian natural gas market introduced by Legislative Decree No. 164/2000 which provides for, among other things, the opening of the Italian market to competition, limitations to the size of gas companies relatively to the market and third party access to infrastructures. Increasingly high levels of competition in the Italian natural gas market could possibly entail reduced natural gas selling margins (see below). In addition, Legislative Decree No. 164/2000 grants the Italian Authority for Electricity and Gas certain regulatory powers in matters of natural gas pricing and access to infrastructures. Outside of Italy, particularly in Europe, Eni 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. Furthermore, a number of large clients, particularly electricity producers, in both the domestic market and other European markets are planning to enter the supply market of natural gas. 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 national and other European markets for natural gas and reduce Eni’s operating profit. Risks of increasing competition in the natural gas sector are exacerbated by the current economic downturn. Due to the commoditized nature of natural gas, lowering gas demand could result in a situation where suppliers compete more aggressively on pricing thus leading to lower gas margins for the whole sector.

•

In its domestic electricity business, Eni competes with other producers and traders from Italy or outside of Italy who sell electricity in the Italian market. The Company expects in the near future increasing competition from suppliers outside Italy due to the current economic downturn.

•		In retail marketing of refined products both in and outside Italy, 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. Once established, Eni’s service stations compete primarily on the basis of pricing, services and availability of non-petroleum products. In Italy, political and institutional forces are urging greater levels of competition in the retail marketing of fuels. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels.
•		Competition in the oilfield 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 low demand for volumes of 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.

 

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 entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil and natural gas fields. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, the imposition of specific drilling and other work obligations, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. 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.

Exploratory drilling efforts may not be successful

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 are often uncertain, and drilling operations may be unsuccessful as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or fires, blow-outs and various forms of accidents, marine risks such as collisions and adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, particularly in deep waters, is generally more complex and riskier than onshore areas; the same is true for exploratory activity in remote areas or in challenging environmental conditions such as those we are experiencing in the Caspian region or Alaska. 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 invest significant capital expenditures in executing high risk exploration projects, it is likely that Eni will incur significant exploration and dry hole expenses in future years. High risk exploration projects include projects executed in deep and ultra-deep offshore and in new areas where the Company lacks installed production facilities. In particular Eni plans to explore for oil and gas offshore, frequently in deep water or at deep drilling depths, where

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operations are more difficult and costly than on land or at shallower depths and in shallower waters. Deep water operations generally require a significant amount of time between a discovery and the time that Eni can produce and market the oil or gas, increasing both the operational and financial risks associated with these activities. In the case of the Company, risky exploration projects are conducted in the deep offshore of the Gulf of Mexico, Australia, Brazil, the Barents Sea, India, and offshore Ireland. In 2009, management plans to spend significant amounts of exploration expenditures in these areas that may result in significant dry hole expenses.

Furthermore, shortage of deep water rigs 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.

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

Eni is involved in a number of development projects for the production of hydrocarbon reserves, principally offshore. Eni’s future results of operations rely upon its ability to 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, suppliers, customers or others including, for example, Eni’s ability to negotiate favorable long-term contracts with customers; 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. Furthermore, projects executed with partners and co-venturers reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations, behaviors and performance of its partners;
•		timely issuance of permits and licenses by government agencies;
•		the Company’s relative size compared to its main competitors which may prevent it from affording opportunities to participate 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 supplier 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;
•		changes in operating conditions and costs, including the sharp rise in procurement costs and costs for leasing third party equipment or purchase services such as drilling rigs and shipping that we have experienced in recent years as a result of industry-wide cost inflation, resulting in cost overruns;
•		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.

Furthermore, deep waters and other hostile environments, where the majority of Eni’s planned and existing development projects are located, can exacerbate these problems. Delays and differences between scheduled and actual timing of critical events, as well as cost overruns may adversely affect completion, the total amount of expenditures to be incurred and start up of production from such projects and, consequently, actual returns. 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 which may be substantially lower with respect to prices assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced increased budgeted expenditures and a substantial delay in the scheduling of production start up at the Kashagan field, where development is ongoing. Moreover, in July 2007 these matters triggered a dispute with the relevant Kazakh authorities. On October 31, 2008, all the international partners of the project and the Kazakh authorities agreed upon a new contractual and governance framework of the Kashagan project, settling the dispute. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the agreement. In conjunction with the finalization of the agreements, parties also sanctioned the revised expenditure budget of phase-one, amounting to U.S. $32.2 billion (excluding general and administrative expenses) of which U.S. $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities. First oil is expected late in 2012. Eni will fund those investments in proportion to its participating interest of 16.81%. The original development plan that was filed with Kazakh Authorities in 2004 forecast expenditures of U.S. $10.3 billion (Eni’s interest being at the time 18.52%) to execute tranches 1&2 (to be adjusted to take into account cost inflation up to 2007) and first oil in 2008. The change in production start-up and the relevant cost increase over the original budget were driven by: depreciation of the U.S. dollar versus the euro and other currencies; cost price 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.

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See "Item 4 – Business Overview – Exploration & Production". If the Company is unable to develop and operate major projects as planned, it may have a material adverse effect on our results of operations and liquidity.

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. The Company’s reserve replacement is affected by the entitlement mechanism in its Production Sharing Agreements and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of a field’s reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The Company’s reserve replacement was negatively affected by reduced entitlements in its PSAs in the years 2006 and 2007 when Eni’s reserve replacement ratio was 38% in both years, meaning that the Company replaced less reserves than those produced. Eni’s proved reserves of subsidiaries declined by 6.1% in 2007 and by 5.8% in 2006. See "Item 4 – Business Overview – Exploration & Production". 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. An inability to replace reserves could adversely impact future production levels and growth prospects, thus negatively affecting Eni’s future results of operations and financial condition.

We forecast a significant reduction in costs to develop and operate oil and gas fields. If we fail to benefit from this expected trend, our oil and gas margins will deteriorate due to falling hydrocarbons prices

Due to the current oil downturn, we expect that prices for oilfield services and materials will trend lower in the future. We intend to benefit from this reduction by implementing the needed cost initiatives to preserve our profitability in an environment of low oil prices. Cost initiatives include rescheduling of certain field developments to obtain cost saving and renegotiating contracts for oilfield services with our supplies on more favorable terms. If we fail to achieve the targeted levels of cost reductions, our profits per BOE in the Exploration & Production segment will be adversely affected.

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. Eni generally does not hedge its exposure to variability 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 OPEC member countries which control a significant portion of the worldwide 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; in the current economic downturn we have experienced a significant reduction in worldwide demand for crude oil and in the European gas demand which have negatively impacted crude oil and natural gas prices;
(iv)		prices and availability of alternative sources of energy;
(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. Such factors can also affect the prices of natural gas because natural gas prices for the major part of our supplies are typically indexed to the prices of crude oil and certain refined petroleum products. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flows from operations.

Furthermore, 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; (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 impairments charges.

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Uncertainties in Estimates of Oil and Natural Gas Reserves

Numerous 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;
•		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 because the estimates of reserves are based on prices and costs existing as of the date when those estimates are made. In particular the reserves 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 ultimately will 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.

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

In recent years, Eni has experienced adverse changes in tax regimes applicable to oil and gas operations in Italy and in a number of countries where the Company conducts its upstream operations. Management believes that adverse changes are always possible in the tax regimes of any country in which Eni conducts its oil and gas operations, regardless of the level of stability of the political and legislative framework in each country. In recent years, developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America. In 2008, Italy enacted new tax rules that increased the statutory tax rate applicable to energy companies with annual turnover in excess of euro 25 million by 5.5 percentage points, thus reversing a reduction in the statutory tax rate of the same amount that was enacted the previous year. Early in 2009, the Italian Parliament enacted a supplemental tax rate of 4% that has to be applied to profit before income taxes reported by the parent company Eni SpA associated with the Treaty between Italy and Libya. This supplemental tax rate will entail increased tax payables amounting to approximately euro 300 million for the full year 2009.

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

 

Political Considerations

A substantial portion of our oil and gas reserves and gas supplies are located in politically, socially and economically unstable countries where we are exposed to material disruptions to our operations

Substantial portions of Eni’s hydrocarbon reserves are located in countries outside the EU and North America, some of which may be politically or economically less stable than EU or North American countries. At December 31, 2008, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2007, approximately 70% of Eni’s supplies of natural gas came from such countries. See "Item 4 – Gas & Power – Natural Gas Supplies". Adverse political, social and economic developments in any of those countries may 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. Particularly 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. For example, in conjunction with the rescheduling of the Kashagan project in 2007, the Kazakh authorities opened a dispute against the international partners of the consortium operating the Kashagan development claiming failure on part of the consortium to fulfill certain contractual obligations. Subsequently, the Kazakh authorities and the international partners of the consortium have agreed on a new contractual framework of the project. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the agreement; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases (including retroactive claims); and (v) civil and social unrest leading to sabotages, acts of violence and incidents. For example, we have been

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experiencing continuing social unrest in Nigeria leading to a number of disruptions at certain Eni oil producing facilities in the country. As a consequence, our oil and gas production in the country has yet to return to normal production levels. In the first quarter of 2009, security problems have continued to impact our operations.

In 2008 we incurred significant asset impairments in our Exploration & Production business amounting to euro 989 million mainly driven by changes in contractual arrangements and regulatory provisions and environmental obligations leading the Company to reassess the recoverable amounts of a number of its oil and gas properties.

See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves"; and "Item 5 – Recent Developments". While the occurrence of these 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.

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 of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties.

Under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 9 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country.

Adding to Eni’s risks arising from this matter, a bill to amend and extend the extra-territorial reach of the economic sanctions imposed by the United States with respect to Iran has been passed by the U.S. House of Representatives and may lead to the passage of new laws in this area. Iran continues to be designated by the U.S. State Department as a State sponsoring terrorism. For a description of Eni’s operations in Iran see "Item 4 – Information on the Company – Exploration & Production – North Africa and Rest of World". It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation.

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. These policies could adversely impact investment by certain investors in our securities.

 

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand, with consequential effects on prices and profitability exacerbated by the highly competitive environment of this industry. Eni’s petrochemical operations have been in the past and may be adversely affected in the future by worldwide economic slowdowns and excess installed production capacity. Furthermore, Eni’s petrochemical operations face increasing competition from Asiatic companies and national oil companies’ petrochemical divisions which can leverage on certain long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. In particular, Eni’s petrochemical operations are located mainly in Italy and Western Europe where regulatory framework and public environmental sensitivity are generally more stringent than in other countries, especially Far East countries, resulting in higher operating costs of our petrochemical operation compared to the Company’s Asiatic competitors due to the need to comply with applicable laws and regulations in environmental and other related matters. In 2008 our petrochemicals operations posted operating losses of euro 822 million due to sharply higher feed-stock costs in the first half of the year and lower product volumes and margins in the second half due to the current economic downturn and related asset impairments. Impairment losses were recorded amounting to euro 278 million as the recoverable amounts of certain petrochemicals plants were lower than their carrying amounts due to deteriorating profitability prospects on the back of lowered expectations for industry fundamentals and unfavorable trends in the trading environment. As

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the downturn is expected to continue for the full year 2009, we do not project any significant improvement in our petrochemicals business profitability.

 

Liberalization of the Italian Natural Gas Market

Legislative Decree No. 164/2000 opened up the Italian natural gas market to competition as from January 1, 2003. As a result, all customers in Italy are free to choose their supplier of natural gas. The decree, among other things, introduced rules which have a significant impact on Eni’s activity, as the Company is present in all the phases of the natural gas chain:

•		until December 31, 2010, antitrust thresholds are in place for gas operators in Italy as follows: (i) effective January 1, 2002, operators are prohibited to transmit into the national transport network imported or domestically produced gas volumes higher than a preset share of Italian final consumption. This share was 75% of total final consumption in the first year of regulation, decreasing by 2 percentage points per year to achieve a 61% threshold in terms of final consumption by 2009 (this share amounted to 63% in 2008); and (ii) effective January 1, 2003, operators are forbidden from marketing gas volumes to final customers in excess of 50% of overall volumes marketed to final customers. Compliance with these ceilings is verified annually by comparing actual average shares reached by any operator in a given three-year period for both volumes input and volumes marketed to customers to average shares permitted by the law for the same period. Actual shares are computed net of losses (in the case of sales) and volumes of natural gas consumed in own operations. Based on a bill passed by the Italian upper house, Eni expects that these antitrust thresholds will be renewed when they expire in 2010; and
•		access to natural gas infrastructures is guaranteed to any natural gas operator on the basis of certain procedures that must be transparent and non discriminatory. Natural gas infrastructures comprise high pressure, high sized pipelines for transporting natural gas over long distances, certain depleted fields to store natural gas, re-gasification facilities and low pressure, small sized pipelines for distributing natural gas to residential and commercial clients located in urban centers. Tariffs to use these infrastructures are set by the Authority for Electricity and Gas, an independent governmental body.

Furthermore, on June 30, 2008 provisions came into effect on the unbundling of regulated entities in the Italian gas sector on the basis of a Code that was adopted by the Authority for Electricity and Gas in 2007. According to unbundling rules, controlling entities as in the case of the parent company Eni SpA are forbidden from interfering in the decision-making process of its subsidiaries running gas transport, storage and distribution infrastructures.

Eni expects that a combination of regulatory effects and increasing competition will limit growth prospects and profitability of our natural gas business in Italy as discussed below.

Eni has been experiencing significant pressure on its natural gas margins¹ since the inception of the liberalization process in Italy. In the current economic downturn, margin pressures could worsen also considering an expected increase in supplies of natural gas to the Italian market in light of new import capacity that has been completed or is expected to come on stream in the next one to three years

Since the inception of the liberalization process in the Italian natural gas market, Eni has been experiencing rising competition in its natural gas business leading to lower selling margins due to the entry of new competitors into the market. Certain competitors of Eni are supplied by the Company itself, generally on the basis of long-term contracts. In fact, in order to comply with the above mentioned regulatory thresholds relating to volumes supplied through the national transport network and sales volumes in Italy, Eni sold part of its gas availability under its take-or-pay supply contracts to third parties importing said volumes to Italy and marketing them to Italian customers. For more information on Eni’s take-or-pay contracts, see "Item 4 – Gas & Power – Natural gas purchases".

Management expects Eni’s gas selling margins in Italy to remain under pressure in the foreseeable future considering deteriorating demand fundamentals in the current economic downturn, Eni’s gas availability under its take-or-pay supply contracts, build-up of Eni’s supplies to the above mentioned competitors and new competitors entering the Italian market also in light of ongoing or already implemented capital projects designed to expand the transport capacity of import pipelines to Italy and to build new import infrastructures, particularly LNG terminals. In fact, Eni is currently implementing its plans to upgrade its natural gas import pipelines mainly from Algeria and Russia to Italy to achieve an increase of 13 BCM/y in import capacity reaching full operation in 2010. Specifically, the upgrading of the TTPC pipeline from Algeria was completed in 2008 and is expected to be fully operational in 2009. The upgrade of the Russian pipeline is ongoing. Further 3 BCM/y of new import capacity will be added by upgrading the GreenStream gasline from Libya with expected start up in 2012. A large portion of the new capacity deriving from Eni’s upgrading projects has been or is planned to be sold to third parties. In addition, a third party project has been implemented to build a new LNG terminal with an 8 BCM/y capacity in the Adriatic Sea and is expected to commence operations by late 2009. These new or upgraded gas infrastructures will considerably increase supplies to the Italian natural gas market at a time when demand is falling due to the economic downturn.

 

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Despite the fact that an increasing portion of natural gas volumes purchased by Eni under its take-or-pay contracts is planned to be marketed outside Italy, management believes that unfavorable trends in the Italian demand and supply for natural gas on both the short and the longer-term, also due to the reaching of full operation at new supply infrastructures, and the evolution of Italian regulations of the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts and may result in a downward pressure on the Company’s gas selling margins. Based on the foregoing, Eni’s future results of operations and cash flows might be adversely affected.

Eni is committed to increasing natural gas sales in Europe. If Eni fails to achieve this target, future growth prospects may be adversely affected. Furthermore, Eni may be unable to fulfill its minimum take obligations under its take-or-pay purchase contracts and this could adversely impact 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 it has entered into with major natural gas producing countries (namely Russia, Algeria, Libya, Norway and the Netherlands) and synergies from the acquisition of the Belgian gas operator Distrigas that was completed in 2008. 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.

Due to the regulated access to natural gas transport infrastructures in Italy, Eni may not be able to sell in Italy all the natural gas volumes it planned to import and, as a consequence, the Company may be unable to sell all the natural gas volumes which it is committed to purchase under take-or-pay contract obligations

Over the medium-term, Eni has scheduled its import volumes of natural gas to Italy based on the assumption to use the purchase flexibility contractually provided by its take-or-pay purchase contracts during periods in which demand is expected to peak. These import programs are also based on the assumption that Eni will obtain the necessary transport capacity entitlements on the Italian transport network. However, Eni’s planning assumptions may be considered to be not fully in line with current rules regulating the access to the Italian transport infrastructures as provided for by the Network Code currently in force which has been drafted in accordance with Decision No. 137 of July 17, 2002 of the Authority for Electricity and Gas. Such rules establish certain priority criteria for transport capacity entitlements at points where the Italian transport infrastructure connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, Eni’s gas volumes purchased under take-or-pay contracts are entitled to a priority in the allocation of available transport capacity for amounts not exceeding average daily contractual volumes. Accordingly, Eni’s purchase volumes exceeding average daily contractual volumes are not entitled to any priority in gaining access to the Italian transport infrastructures. The contractual flexibility represented by Eni’s right to uplift daily volumes larger than average daily contractual volumes under its take-or-pay purchase contracts is used when demand peaks, usually during the wintertime. In the event congestion occurs at entry points to the Italian transport network, under current regulation available transport capacity would be entitled firstly to operators having a priority right, i.e. holders of take-or-pay contracts within the limits of average daily contractual volumes. Then any residual available transport capacity would be allocated in proportion to all pending capacity requests. Eni considers Decision No. 137/2002 to be inconsistent with the overall rationale of the European natural gas regulatory framework, especially with reference to Directive 98/30/CE (superseded and replaced by Directive 03/55/CE) and Legislative Decree No. 164/2000, and has opened an administrative procedure to repeal Decision No. 137/2002 before an administrative court. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". Eni cannot rule out a negative outcome for this matter. However, management believes that Eni’s results of operations and cash flows could be adversely affected should market conditions in light of current regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill its minimum take contract obligations (e.g. in case a congestion occurs at the entry points of the Italian transport infrastructure, Eni would be forced to uplift a smaller volume of gas than the minimum contractual take). See "Item 5 – Management Expectations of Operations".

The Italian Government, Parliament and the regulatory authorities in Italy and in Europe may take further steps to increase competition in the Italian natural gas market and such regulatory developments may adversely affect Eni’s results of operations and cash flows

Italian institutional and political forces are urging a higher degree of competition in the Italian natural gas market and this may produce significant developments in this area. A brief description follows of certain recently enacted laws and certain proceedings before the Authority for Electricity and Gas and the Italian Antitrust Authority in order to allow investors to gain some insight into the complexity of this matter. For a full discussion of laws and procedures described herein see "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power".

In 2003, Law No. 290 was enacted which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 50.04% interest in Snam Rete Gas, which owns and manages approximately 97% of the Italian natural gas transport infrastructure). A decree is expected to be enacted by the Italian Prime Minister to establish the relevant provisions to implement this mandatory disposal. The deadline for the disposal, which was initially scheduled for December 31, 2008, is to be re-

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scheduled in a 24-month term starting from the date in which this decree from the Italian Prime Minister becomes effective. Currently, Eni is unable to foresee a deadline for this disposal.

On the basis of a joint inquiry conducted from 2003 through June 2004 on the Italian natural gas market, the Authority for Electricity and Gas and the Italian Antitrust Authority (the "Antitrust Authority") concluded that the overall level of competition of the Italian natural gas market is unsatisfactory due to the dominant position held by Eni in many phases of the natural gas chain. According to both the Authority for Electricity and Gas and the Antitrust Authority, the vertical integration of Eni in the supply, transport and storage of gas has restricted the development of competition in Italy notwithstanding the antitrust ceilings introduced by Legislative Decree No. 164/2000. It was further stated that the price of natural gas in Italy (in particular for the industrial sector) is higher than in other European countries. In order to implement a Law Decree defined by the Italian Government to face the economic downturn, in March 2009 the Authority for Electricity and Gas proposed certain rules on the Italian gas market designed to increase competition. These rules provide that Eni supplies to the market preset amounts of natural gas at fixed prices. Implementation of these rules could materially and adversely affect the Company’s results of operations and cash flow.

In November 2006, the Authority for Electricity and Gas concluded an inquiry concerning the competitive behavior of operators selling natural gas to residential and commercial customers. This inquiry found that the retailing market for natural gas in Italy lacked a sufficient degree of competition due to current commercial practices and the existence of both entry and exit barriers.

In November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority opened an inquiry to gain insight into the functioning of the natural gas storage activity in Italy, particularly with regard to lack of investments by operators directed to expand capacity to store natural gas in Italy. Eni through its wholly-owned subsidiary Stogit Italia owns almost the entire storage capacity currently existing in Italy.

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

Decisions of the Authority for Electricity and Gas on the matter of natural gas tariffs may diminish Eni’s ability to determine the price at which it sells natural gas to customers

On the basis of certain legislative provisions, the Authority for Electricity and Gas ("the Authority") holds a general monitoring power on pricing in the natural gas market in Italy and the power to establish selling tariffs for supplying natural gas to residential and commercial users consuming less than 200,000 CM/y (qualified as non eligible customers at December 31, 2002 as defined by Legislative Decree No. 164/2000) taking into account, among other things, the public interest of containing inflationary pressure due to rising energy costs. The decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the purchase cost of natural gas on to the final consumers. Following a complex and lengthy administrative procedure started in 2004 and finalized in March 2007 with Resolution No. 79/2007, the Authority established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 CM/y, establishing, among other things: (i) that an increase in the international price of Brent crude oil is only partially transferred to residential and commercial users of natural gas in case international prices of Brent crude oil exceed the 35 dollars per barrel threshold; and (ii) that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account of this new indexation mechanism. Management cannot exclude the possibility that in the future the Authority could implement similar measures that may negatively affect Eni results of operations and liquidity.

Certain provisions of law may also limit the Company’s ability to set commercial margins. Specifically, Law Decree No. 112 enacted in June 2008 forbids energy companies such as Eni to transfer on to customers, through higher prices, the higher income taxes incurred in connection with a supplemental tax rate of 5.5 percentage points introduced by the same decree on energy companies with a yearly turnover in excess of euro 25 million. The Authority for Electricity and Gas is in charge of monitoring compliance with the rule. The Authority has subsequently that energy companies have to adopt effective operational and monitoring systems in order to prevent the transfer to customers by means of unlawful variations of final prices of gas.

For more information on these issues (particularly the Authority’s Decisions No. 248/2004, 134/2006 and 79/2007) see "Item 4 – Regulation – 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. In the years prior to 2008, Eni recorded significant loss provisions due to unfavorable developments in certain antitrust proceedings before the Italian Antitrust Authority, and the European

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Commission. It is possible that the Group may incur significant loss provisions in future years relative to ongoing antitrust proceedings or possible new proceedings. The Group is particularly exposed to this risk in its natural gas and refining and marketing activities due to its large presence in these markets in Italy and in Europe. See Note 29 to the Consolidated Financial Statements for a full description of Eni’s main pending antitrust proceedings. Particularly, as a result of an inquiry on the level of competition in the European natural gas market, on March 9, 2009 the European Commission sent Eni a Statement of Objections related to a proceeding under Article No. 82 of the EU Treaty and Article No. 54 of the SEE agreement with reference to an alleged unjustifiable refusal of access to the TAG and TENP/Transitgas gas pipelines, that are interconnected with the Italian gas transport system through actions intended to "capacity hoarding, capacity degradation and strategic limitation of investment" with the effect of "hindering the development of a real competition in the downstream market and […] harming the consumers". The European Commission envisages the possible imposition of a fine and of structural remedies. Based on available information and its knowledge of the proceeding, the Company is currently unable to determine the outcome of the matter.

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 may incur material operating expenses and expenditures in relation to compliance with applicable environmental, health and safety regulations

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. 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, as well as refining, petrochemicals and other Group operations, limit or prohibit drilling activities in certain protected areas, 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 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 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 environment health or safety damage. Additionally, in the case of violation of certain rules regarding safety in the workplace, the Company can be liable as provided for by a general EU rule on businesses liability due to negligent or willful conduct on part of their employees as adopted in Italy with 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 environmental, health and safety laws and regulations, also taking into account possible future developments in environmental regulations in Italy and in other countries where Eni operates, particularly the implementation of increasingly strict measures decided at both international and country level to reduce greenhouse gas emissions.

Eni’s results of operations and financial condition are exposed to risks deriving from environmental, health and safety accidents and liabilities

Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management believes 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 always possible that incidents like blow-outs, spillovers, contaminations and similar events could occur that would result in damage to the environment, employees and communities. In particular, Eni is performing a number of remedial actions to restore and clean-up certain industrial sites that were contaminated by the Group’s industrial activities in previous years, mainly in Italy. Management expects further remedial actions to be implemented in future years. 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 amount represents the management’s best estimates of future environmental expenses to be incurred. Notwithstanding this, 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 chance of as yet

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unknown contamination; (ii) the results of on-going 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 site; (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 environment act as plaintiffs; (iv) the possibility that new litigation might arise; and (v) the probability that new and stricter environmental laws might be implemented.

 

Legal Proceedings

Eni is party to a number of civil actions and administrative proceedings arising in the ordinary course of the 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.

 

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 Petrochemical segments are affected by changes in the price of crude oil and by 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 by different 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 Petrochemical businesses, depends upon the speed at which the prices of gas and products adjust to reflect these changes. Wholesale margins in the Gas & Power business are substantially independent from fluctuations in crude oil prices as purchase and selling prices of natural gas are contractually indexed to prices of crude oil and certain refined products according to similar pricing schemes. However, quarterly performance and year-to-year comparability of results of Eni’s natural gas business may be somewhat affected by the indexation mechanism of the raw material component in gas supplies to residential customers and certain resellers to residentials in Italy in accordance with applicable regulations from the Italian Authority for Electricity and Gas as outlined above in the risk factor describing the "Liberalization of the Italian Natural Gas Market". Specifically, this indexation mechanism provides a certain time lag between movements in the price of crude oil and the related adjustment to the selling price of natural gas. For a detailed discussion of this indexation mechanism in Italy see "Item 4 – Regulation – Gas & Power – Natural gas prices".

In the Refining & Marketing and Petrochemical 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

The results of operations of 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 as outlined above. The prices of refined products in turn 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 crude qualities vs. light 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 2009, Eni expects that weak demand for products and narrowing price differentials between heavy and light crudes ones will negatively affect the performance of Eni’s refining operations.

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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 changes in oil prices which influence changes in purchase costs of petroleum-based feedstock. 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 2008, the profitability of Eni’s petrochemical segment was significantly affected by lower selling margins for commodity petrochemical products due to higher purchase costs for oil-based feedstock that were not fully transferred to selling prices of products in the first half of the year and, subsequently by weak demand for petrochemical products. These negative factors also triggered asset impairments. Management’s outlook for 2009 is also challenging, and management does not expect any significant improvement in the trading environment from 2008 and possibly a further contraction in margins on petrochemical products.

 

Risks from Acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or corporations in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. We also 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 may be adversely affected.

 

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. Credit risks arise from both commercial partners and financial ones. Although the Group has never experienced material non-performance from its counterparties, due to the severity of the current economic and financial crisis it is possible that we may experience a higher than normal level of counterparty failure. In our consolidated financial statements for the year 2008, we accrued an allowance against doubtful accounts amounting to euro 251 million more than doubling the allowance made a year earlier.

 

Exchange Rates

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 Petrochemical 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 results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in dollar-denominated expenses. The Exploration & Production segment is particularly affected by movements in the U.S. dollar vs. the euro exchange rates. In 2008, Eni’s operating profit in this business segment has been impacted by an estimated amount of euro 1.2 billion due to a 7.3% depreciation of the U.S. dollar versus the euro.

 

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.

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.

 

Interest Rates

Interest on Eni’s finance debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, "Euribor", and the London Interbank Offered Rate, "Libor". As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its finance debt.

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Critical Accounting Estimates

The preparation of financial statements requires management to make certain accounting estimates that are characterized by a high degree of uncertainty, complexity and judgment. These estimates affect the reported amount of the Company’s assets and liabilities, as well as the reported amount of the Company’s income and expenses for a given period. 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; the availability of new informative elements, variations in economic conditions such as prices, significant factors (e.g. removal technologies and costs) and the final outcome of legal, environmental or regulatory proceedings. See "Item 5 – Critical Accounting Estimates".

 

 

Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricity generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 70 countries and 78,880 employees as of December 31, 2008.

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

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

• San Donato Milanese (Milan), Via Emilia, 1; and

• San Donato Milanese (Milan), Piazza Ezio Vanoni, 1.

Internet address: www.eni.it.

The name of the agent of Eni in the United States is De Luca Vincenzo, 485 Madison Ave., 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 39 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the U.S., Kazakhstan, Russia, Algeria, Pakistan and Australia. In 2008, Eni’s production of oil and natural gas amounted to 1,748 KBOE/d on an available-for-sale basis. As of December 31, 2008, Eni’s proved reserves of subsidiaries stood at 6,242 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 666 mmBOE. In 2008, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 33,318 million and operating profit of euro 16,415 million.

Eni’s Gas & Power segment engages in supply, transport, distribution and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets. In 2008, Eni’s worldwide sales of natural gas amounted to 104.23 BCM, including 6.00 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S. Sales in Italy amounted to 52.87 BCM, while sales in European markets were 43.03 BCM that included 11.25 BCM of gas sold to certain importers to Italy. Sales to markets outside Europe amounted to 2.33 BCM. Through its 50.03 per cent-owned subsidiary Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,474-kilometer long, while outside Italy Eni holds capacity entitlements on a network of European pipelines extending for approximately 4,400 kilometers made up of high pressure pipelines to import gas from Russia, Algeria, Libya and North Europe production basins to European markets. Eni, through its 100 percent-owned subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,320 municipalities through a low pressure network consisting of approximately 49,400 kilometers of pipelines as of December 31, 2008. Eni produces electricity and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of 4.9 GW as of December 31, 2008. In 2008, sales of electricity totaled 29.93 TWh. Eni operates a re-gasification terminal in Italy and holds indirect interest or capacity entitlements in a number of LNG facilities in

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Europe, Egypt and in certain projects under construction in the U.S. In 2008, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 36,936 million and operating profit of euro 3,933 million. Eni’s Refining & Marketing segment engages in refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2008, processed volumes of crude oil and other feedstock amounted to 35.84 mmtonnes and sales of refined products were 50.68 mmtonnes, of which 28.92 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.67 mmtonnes including Italy and the rest of Europe. In 2008, Eni’s retail market share in Italy through its Agip-branded network of service stations was 30.6%. In 2008, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 45,083 million and operating net loss of euro 1,023 million.

Eni’s petrochemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and Western Europe. In 2008, Eni sold 4.7 mmtonnes of petrochemical products. In 2008, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,303 million and an operating net loss of euro 822 million.

Eni’s oilfield services, construction and engineering activities are conducted through its 42.91 per cent-owned subsidiary Saipem and Saipem’s controlled entities. Activities involve offshore construction, particularly fixed platform installation, sub-sea pipe laying and floating production systems and onshore construction. Offshore and onshore drilling services and engineering and project management services are also provided to the oil and gas, refining and petrochemical industries. In 2008, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 9,176 million and operating profit of euro 1,045 million.

A list of subsidiaries of Eni 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. This strategy has remained unchanged in spite of the current economic downturn and an uncertain outlook for the global energy demand. In executing this strategy, management intends to preserve a solid capital structure targeting an optimal mix between net borrowings and shareholders’ equity. By this means, management expects to maintain the Company’s current credit rating. Over the next four-years, Eni plans to execute a capital expenditure program amounting to euro 48.8 billion to support organic growth. Eni plans to fund this capital expenditure program mostly by means of cash flows provided by operating activities. Capital projects will be assessed and implemented in accordance with tight financial criteria. The Company intends to remunerate its shareholders through significant dividend distributions so as to ensure to its shareholders competitive dividend yields (measured as the ratio of dividend to the share price recorded on average in the month of December on the Italian stock exchange). Management intends to support the Company’s profitability by focusing on cost reduction initiatives, including a number of actions that will be implemented in order to benefit from the expected reduction in purchase costs for oilfield materials, equipment and services in the Exploration and Production segment. For a description of risks and uncertainties associated with the Company’s outlook and the capital expenditure program See "Item 5 – Management’s Expectations of Operations".

Eni’s strategy in its Exploration & Production operations is to grow production leveraging on the development of the Company’s asset portfolio. Eni targets to achieve a production growth rate of 3.5% on average over the 2009-2012 period, assuming Eni’s Brent price scenario of 55 U.S. dollar per barrel in 2012. For a discussion of Eni’s production volume sensitivity to oil prices see "Item 5 – Management’s Expectations of Operations". Management will continue to assess opportunities to increase production through acquisitions. Eni intends to pay special attention to reserve replacement in order to secure the medium to long-term sustainability of its business.

In its Gas & Power activities, Eni intends to grow natural gas sales in the international market, preserve the profitability of the Italian marketing business, effectively manage regulated businesses, and develop a global LNG business. Due to the current economic downturn, the Company has revised down its long-term growth expectations for the European gas demand from 3% to 2% per annum until 2020. For a description of trends in the natural gas markets see "Gas & Power" below. The impact of a worsening demand outlook and increasing competitive pressure on Eni’s results of operations on the domestic market is expected to be offset by the contribution of regulated businesses and continuing growth in European markets, mainly driven by the integration of the recently acquired Belgian company Distrigas. Eni targets worldwide gas sales of 124 BCM in 2012, including E&P sales in Europe and the U.S. In particular, Eni targets to achieve an annual average growth rate of 7% in international sales in the four-year period 2009 to 2012. The Company’s strategy contemplates a further strengthening of Eni’s presence in the European market, leveraging on the synergies expected from the acquisition of Distrigas (for further details see below – "Significant business and portfolio developments"). The integration with upstream activities will provide the Gas & Power business with opportunities to monetize the equity gas reserves and develop LNG sales.

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In its Refining & Marketing activities, the Company’s strategy focuses on improving the business profitability and reducing the cash requirements of the business by means of strict capital discipline also in light of a weak outlook for refined products demand. The Company intends to selectively upgrade its refinery system and improve quality standards in marketing activities as well as increase operating efficiency. In refining Eni plans to increase the conversion index and flexibility of plants in order to achieve a higher yield of middle distillates and increase the ability of its refineries to process less valuable crudes. In marketing, Eni intends to strengthen its leadership position in the Italian retail market trough plant upgrading, loyalty programs and enhanced non-oil service formats. In Europe, Eni’s growth strategy will continue to be selective, focusing on those markets where it can leverage on scale, supply and logistic synergies and brand awareness.

In its Engineering & Construction activities, Eni aims at developing and expanding its geographical reach and technical characteristics of its world class fleet in order to maintain its strong competitive position and reduce its exposure to the cyclicality of the oil industry.

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.1 billion in the next four years to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crude (in particular the EST project), monetizing natural gas through projects such as high pressure high distance gas transmission (TAP) and Gas to Liquids (GTL), and protecting the environment by investing in the fields of renewable sources of energy and reduction of GHG emissions.

 

Significant business and Portfolio Developments

The significant business and portfolio developments that occurred in 2008 and to date in 2009 were the following:

•		In January 2008, Eni completed the acquisition of the entire issued share capital of the UK-based oil company Burren Energy Plc, for a total cash consideration amounting to approximately euro 2.4 billion (including Burren’s shares purchased in 2007, for a total amount of euro 0.6 billion). In 2008 production of Burren assets averaged 25 KBBL/d in Congo and Turkmenistan.
•		In October 2008, all the international parties to the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium and the Kazakh authorities signed the final agreement implementing the new contractual and governance framework of the Kashagan project, based on the Memorandum of Understanding signed on January 14, 2008. Eni’s management expects to achieve first oil at the Kashagan field by the end of 2012.
•		In October 2008, following authorization from the European Commission, Eni closed the acquisition of a 57.243% majority stake in the Belgian company Distrigas NV from the French company Suez-Tractebel. The deal entailed cash consideration of euro 2.75 billion. On December 30, 2008, Eni was granted authorization from the Belgian market authorities to execute a mandatory tender offer on the minority shareholders of Distrigas. On March 19, 2009, the mandatory tender offer on the minority shareholders of Distrigas was finalized. Shareholders representing 41.61% of the share capital of Distrigas tendered 292,390 shares on Eni’s offer. Publigaz Scrl tendered its entire interest (31.25%). On April 8, 2009 Eni paid to those shareholders cash consideration amounting to euro 1,991 million. Following the tender offer, Eni owned 98.86% of the share capital of Distrigas. The squeeze-out on the residual 1.14% was completed in early May. Consequently Eni now holds all the shares of Distrigas except for one share belonging to the Belgian State with special powers. Distrigas shares have been delisted from Euronext Brussels.
•		In October 2008, Eni signed an agreement with Suez related to the sale of a number of Eni’s assets as well as long-term gas and electricity supply contracts. As of end of December 2008 the following agreements have been finalized: (i) the Virtual Power Plant agreement that grants Suez the right to off-take volumes of electricity corresponding to capacity of up to 1,100 MW for a period of 20 years, with proceeds of euro 1.21 billion; (ii) gas supply contracts up to 4 BCM/y to be delivered in Italy for a period of 20 years and an option to purchase up to 2.5 BCM/y to be delivered in Germany for a period of 11 years, with proceeds amounting to euro 255 million; (iii) supply contracts for 0.9 BCM/y of LNG for a period of 20 years at a price of euro 87 million; (iv) on October 30, 2008 the Eni fully-owned subsidiary Italgas and the partner Suez signed a purchase and sale contract regarding an asset identified as the gas distribution network of the city of Rome and certain nearby municipalities owned by Italgas. The contract is a final one which validity is conditional upon approval by the Municipal body of the city of Rome to be granted not later than August 31, 2009 regarding the change in the entity who will act as operator of the service concession arrangement in place as a consequence of the closing of the contract; and (v) a number of contracts were also signed for the divestment of a number of upstream exploration and production concessions in the UK, the Gulf of Mexico, Egypt and Indonesia entailing cash consideration up to euro 273 million. Closing of the contracts regarding properties in Egypt and Indonesia is conditional upon approval from relevant local Authorities, while contracts have been closed regarding the sale of properties in the UK and the Gulf of Mexico.
•		In November 2008, Eni finalized an agreement to acquire all the common shares of First Calgary Petroleums Ltd, a Canadian oil and gas company with exploration and development activities in Algeria.

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The acquisition values the fully diluted share capital of First Calgary at approximately euro 605 million. Production start-up is expected in 2011 with a projected plateau of approximately 30 KBOE/d net to Eni by 2012.

In addition, in 2008 Eni completed the following transactions:

•

In February 2008, Eni signed a strategic agreement with the Venezuelan State oil company PDVSA for the definition of a plan to develop a field located in the Orinoco oil belt, with a gross acreage of 670 square kilometers.

•		In February 2008, as part of the announced plan to dispose of non core assets, Eni sold its 30% interest in Gaztransport & Technigaz SA (GTT), a company owning a patent for the construction of tanks for LNG transport, to Hellman & Friedman for a total value of euro 310 million.
•		In June 2008, Eni finalized a strategic oil transaction with the Libyan national oil company based on the framework agreement of October 2007. This transaction effective from January 1, 2008, extends the duration of Eni’s oil and gas properties in Libya until 2042 and 2047 respectively and lays the foundations for a number of projects targeting development of the significant gas potential in the country.

•		In April 2008, Eni signed a Memorandum of Understanding with the state-owned company Qatar Petroleum International to target joint investment opportunities in the exploration and production of oil and gas.
•		In May 2008, Eni defined a cooperation agreement with the Republic of Congo for the extraction of unconventional oil from the Tchikatanga and Tchikatanga-Makola oil sands deposits with over extension of 1,790 square kilometers. Eni plans to monetize the heavy oil by applying its EST (Eni Slurry Technology) proprietary technology intended to convert entirely the heavy barrel into high-quality light products. The agreement also comprises the construction of a new 450 MW electricity generation plant (Eni’s share 20%) to be fired by 2009 with the associated natural gas from the operated M’Boundi field and a partnership for the production of bio-diesel.
•		In July 2008, Eni renewed the Memorandum of Understanding with Brazilian oil company Petrobras for the evaluation of joint initiatives in the upstream and downstream sectors, to produce and market renewable fuels and the possible options for the valorization of the natural gas reserves discovered by Eni offshore Brazil.
•		In September 2008, Eni finalized the purchase of a 17% stake in the share capital of Gaz de Bordeaux SAS active in the marketing of natural gas in the Bordeaux area. Eni’s associate Altergaz (Eni’s interest being 38.91%) also entered the transaction with an equal stake. The two partners signed also a long-term agreement for the supply of 250 mmCM/y of gas for ten years to Gas de Bordeaux.
•		In September 2008, Eni signed a strategic agreement with Petroleos de Venezuela, SA (PDVSA) for the exploration and development of two offshore Venezuelan areas and the subsequent development of gas resources via an LNG project.
•		In October 2008, Eni completed the divestment of the entire share capital of the subsidiary Eni Agip España to Galp Energia SGPS SA following the exercise of a call option in October 2007, pursuant to agreements among Galp’s shareholders. The divested asset includes 371 service stations as well as wholesale marketing activities of oil products located in the Iberian Peninsula.
•		In October 2008, Eni signed a partnership agreement with Papua New Guinea for the exploration of oil and gas and identification of opportunities to develop the Country’s resources. Eni is also interested to joint opportunities related to power generation projects and the development of alternative and existing renewable energies.
•		In November 2008, Eni finalized an agreement with the British company Tullow Oil Ltd to purchase a 52% stake and the operatorship of fields in the Hewett Unit and relevant facilities in the North Sea in close proximity to the Interconnector pipeline. Eni plans to upgrade certain depleted fields in the area so as to achieve a gas storage facility with a 177 BCF capacity to support seasonal upswings in gas demand in the UK.
•		In November 2008, Eni finalized a Memorandum of Understanding with Colombia’s state oil company Ecopetrol to evaluate joint exploration opportunities.

Recent developments are described below.

•		On April 7, 2009 Gazprom exercised its call option to purchase the 20% interest in OAO Gazprom Neft held by Eni following agreements between the two partners. The 20% interest in Gazprom Neft was acquired by Eni on April 4, 2007 as part of a bid procedure for the assets of bankrupt Russian company Yukos. The exercise price of the call option is equal to the bid price (U.S. $3.7 billion) as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and financing collateral expenses. At the same time, Eni and Gazprom signed new cooperation agreements targeting certain development projects to be conducted jointly in Russia and other countries of interest. Terms of the call option granted to Gazprom to purchase a 51% interest in the share capital of OOO SeverEnergia (Eni’s interest being 60%), which owns 100% of three Russian companies engaging in the development of gas reserves, are currently under review by Eni, Enel and Gazprom.
•		On February 12, 2009, Eni’s Board of Directors approved the divestment of 100% of Italgas SpA and Stoccaggi Gas Italia SpA (Stogit) to Snam Rete Gas (50.03% owned by Eni) for total cash consideration of euro 4,720 million (euro 3,070 million and euro 1,650 million, respectively). The transaction will be

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financed by Snam Rete Gas through: (i) a rights issue up to a maximum of euro 3.5 billion (Eni has already committed to subscribe its relative share of the rights issue); and (ii) new medium to long-term financing for euro 1.3 billion. The main impacts expected on Eni’s consolidated financial statements when the transaction closes will be: (i) a decrease of euro 1.5 billion in net borrowings and a corresponding increase in total equity as a consequence of the pro-quota subscription of the Snam Rete Gas capital increase by the minoritiy shareholders; and (ii) a decrease in Eni’s net profit equal to 45% of the aggregate net profit of Italgas and Stogit, with a corresponding increase in net profit attributable to minoritiy shareholders. From an industrial perspective the transaction, expected to close in July 2009, will create significant synergies in the regulated businesses segment and maximize the value of Italgas and Stogit due to the higher visibility of regulated businesses as a part of Snam Rete Gas.

In 2008 capital expenditures amounted to euro 14,562 million, of which 84% related to the Exploration & Production, Gas & Power and Refining & Marketing segments and mainly related to: (i) the development of oil and gas reserves (euro 6,429 million) deployed mainly in Kazakhstan, Egypt, Angola, Congo and Italy and exploration projects (euro 1,918 million), primarily in the United States, Egypt, Nigeria, Angola and Libya; (ii) the purchase of proved and unproved property for euro 836 million related mainly to the extension of mineral rights in Libya following an agreement signed in October 2007 with the state company NOC and the purchase of a 34.81% interest in the ABO project in Nigeria; (iii) the development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 1,130 million and euro 233 million, respectively) and upgrading of natural gas import pipelines to Italy (euro 233 million); (iv) the ongoing construction of combined cycle power plants (euro 107 million); (v) projects designed to upgrade the conversion capacity and flexibility of Eni’s refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, and to build of new service stations and upgrade of existing ones in Italy and outside Italy (totaling euro 965 million); and (vi) the upgrading of the fleet used in the Engineering & Construction division (euro 2,027 million).

In 2008, Eni’s acquisitions amounted to euro 5.85 billion (euro 4.3 billion net of acquired cash of euro 1.54 billion) and mainly related to: (i) the acquisition of the 57.243% majority stake in Distrigas NV; (ii) the completion of the acquisition of Burren Energy Plc; (iii) the purchases of certain upstream properties and gas storage assets, related to the entire share capital of the Canadian company First Calgary operating in Algeria, a 52% stake in the Hewett Unit in the North Sea, a 20% stake in the Indian company Hindustan Oil Exploration Co; and (iv) other investments in non-consolidated entities mainly related to funding requirements for an LNG project in Angola.

In 2007, capital expenditures amounted to euro 10,593 million, of which 84.7% related to the Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 4,788 million) deployed predominantly in Kazakhstan, Egypt, Angola, Italy and Congo, and exploration projects (euro 1,659 million) particularly in the Gulf of Mexico, Egypt, Norway, Nigeria and Brazil; (ii) development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 886 million) as well as upgrading of natural gas import pipelines to Italy (euro 253 million); (iii) the ongoing construction of combined cycle power plants (euro 175 million); (iv) projects designed to upgrade the conversion capacity and flexibility of Eni’s refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, and to build and upgrade service stations (totaling euro 979 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,410 million).

In 2007, Eni’s acquisitions amounted to euro 9.7 billion and mainly related to: (i) a 60% interest in three Russian gas companies as part of the liquidation procedure of bankrupt Russian company Yukos. Through the same transaction Eni also purchased a 20% stake in the oil and gas company OAO Gazprom Neft. Gazprom was granted a call option to purchase a 51% interest in those three gas companies and the 20% stake in OAO Gazprom Neft; (ii) the purchase of upstream assets in the Gulf of Mexico; (iii) the purchase of upstream assets onshore Congo; (iv) the purchase of a 24.9% interest in Burren Energy; (v) the acquisition of a further 16.11% stake in the Ceska Rafinerska in the Czech Republic increasing Eni’s ownership interest to 32.4%; (vi) the purchase of 102 retail fuel stations and related marketing assets located in the Czech Republic, Slovakia and Hungary; and (vii) the purchase of a 13.6% stake in the Angola LNG consortium.

 

 

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 39 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the U.S., Kazakhstan, Russia, Algeria, Pakistan and Australia. In 2008, Eni produced 1,748 KBOE/d on an available for-sale basis. As of December 31, 2008, Eni’s proved reserves of subsidiaries stood at 6,242 mmBOE; Eni’ share of reserves of equity-accounted entities amounted to 666 mmBOE.

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Eni’s strategy in its Exploration & Production operations is to increase production leveraging on the development of its asset portfolio. Eni plans to achieve a production growth rate of 3.5% on average over the 2009-2012 period, under certain trading environment assumptions (See "Item 5 – Management’s Expectations of Operations"). A description of Eni’s production volume sensitivity to oil prices is disclosed under "Item 5 – Management’s Expectations of Operations".

Future growth will be driven by the development of new projects located in a number of strategic oil and gas basins in the world, namely the Caspian Region, North and West Africa and the Gulf of Mexico. A high-quality portfolio geographically focused and resilient, with one of the lowest breakeven prices in the industry, high exposure to the most competitive giant projects and long-standing relationships with key host countries will enable any to deliver industry-leading growth even in current market conditions. Management will continue to evaluate opportunities to increase production through focused acquisitions. Eni intends to pay special attention to reserve replacement in order to guarantee the medium-to long-term sustainability of its business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, seeking new opportunities and divesting marginal assets. Eni also intends to develop its LNG business in order to monetize its large base of gas reserves mainly in North and West Africa.

In exploration activities, Eni intends to concentrate resources in well established areas of presence where availability of production facilities, existing competencies and long-term relationships with host countries will enable Eni to readily put in production discovered reserves, reducing the time-to-market and capturing synergies. Approximately 80% of planned capital expenditures will be directed to such core areas (located mainly in the United States, Egypt, Libya, Nigeria, Angola, Italy, Norway and Congo). Eni also plans to selectively pursue high risk/high reward opportunities arising from expansion in areas with high mineral potential. Eni expects to purchase new exploration permits and to divest or exit marginal or non strategic ones.

In order to execute these strategies, Eni intends to invest approximately euro 32.6 billion on reserve development and field optimization as well as exploration projects over the next four-year period; euro 1.8 billion of which will be spent to build transportation infrastructures and execute LNG projects through equity-accounted entities.

In 2009, oil and gas prices are expected to be significantly lower than 2008. In response Eni plans to improve profitability of its operations by implementing a number of initiatives designed to reduce costs to develop and operate oil and gas fields by leveraging on the expected reduction in purchase costs of oilfield services, materials and equipment due to the economic downturn. Management has yet to commit a large amount of future development expenditures and plans to be able to benefit from ongoing downward trends in rates of oilfield services and purchase costs of goods and equipment. Additional cost control measures will address ongoing operations. The amount of planned capital expenditures for the years 2009-2012 already factors in the benefits associated with cost control. See "Item 3 – Risk Factors".

 

Oil and Natural Gas Reserves

Eni has always exercised rigorous control over the booking of proved reserves. The Reserve Department of the Exploration & Production segment is entrusted with the task of continuously updating the Company’s guidelines regarding reserves evaluation. The department monitors the periodic estimation process. Company guidelines follow Regulation S-X Rule 4-10 of the U.S. Securities and Exchange Commission (SEC) as well as on specific issues not regulated by the SEC rules, the established practice endorsed by qualified institutions on the marketplace. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has certified their compliance with applicable SEC rules. D&M has also stated that the Company guidelines regulate situations for which the SEC rules are less precise, providing a reasonable interpretation in line with the generally accepted practices in international markets. When participating in exploration and production activities operated by other entities, Eni also estimates its proved reserves on the basis of the above guidelines.

The process for evaluating reserves involves: (i) business unit managers (geographic units) and Local Reserve Evaluators (LRE) who perform the evaluation and classification of reserves including estimates of production profiles, capital expenditures, operating costs and costs related to asset retirement obligations; (ii) geographic area managers at head offices checking evaluations carried out by business unit managers; and (iii) the Reserve Department, which provides independent reviews of the fairness and correctness of classifications carried out by business units, aggregates worldwide reserve data and performs an economic assessment of reserves to calculate equity volumes. Moreover, the Reserve Department has the responsibility to ensure the periodic certification process of reserves and to update continuously the Company guidelines on reserves evaluation and classification.

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation² of its proved reserves on a rotational basis. Eni believes those independent evaluators to be experienced

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and qualified in the marketplace. In the preparation of their reports, those independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information was used by Eni in determining its proved reserves and included log, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir, and field, reservoir studies; technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of reserves net present value (NPV), actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information are provided. Accordingly, Eni believes that the work performed by the independent evaluators is to be considered an evaluation of Eni’s proved reserves carried out in parallel with the internal evaluation. The circumstance that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support management’s confidence that the company’s booked reserves meet the regulatory definition of proved reserves which are reasonably certain to be produced in the future. When the assessment of independent engineers is lower than internal evaluations, Eni revises its estimates based on information provided by independent evaluators. In any case, those differences were not significant.

In 2008, a total of 1.5 BBOE of proved reserves of subsidiaries have been evaluated, representing approximately 25% of Eni’s total proved reserves of subsidiaries at December 31, 2008. In the 2006-2008 three-year period, 76% of Eni’s total proved reserves of subsidiaries were subject to independent evaluations. As at December 31, 2008 the most important of Eni’s properties which were not subject to an independent evaluation were: Bouri and Bu Attifel (Libya), Barbara (Italy), M’Boundi (Congo) and Elgin-Franklin (United Kingdom).

Eni’s proved reserves of subsidiaries at December 31, 2008 totaled 6,242 mmBOE (oil and condensates 3,243 mmBBL; natural gas 17,214 BCF) representing an increase of 232 mmBOE, or 3.9%, from December 31, 2007. Additions to proved reserves booked by Eni’s subsidiaries in 2008 were 850 mmBOE deriving from: (i) revisions of previous estimates of 746 mmBOE, partly related to higher entitlements reported in certain PSAs (up 340 mmBOE) resulting from lower year end oil prices from a year ago (Brent price was $36.55 per barrel at December 31, 2008 compared to $96.02 per barrel at December 31, 2007), net of downward revisions associated with marginal productions in certain mature fields such as Angola, Kazakhstan and Libya; (ii) extensions and discoveries (71 mmBOE) with major increases booked in Angola, Egypt, Nigeria, Norway and United States; and (iii) improved recovery (33 mmBOE) mainly reported in Algeria, Angola, Congo and Libya. Acquisitions amounted to 91 mmBOE reflecting the contribution of the acquired Burren assets in Congo, Turkmenistan and India. Sales of reserves (59 mmBOE) related to the divestment of a 1.71% stake in the Kashagan project following the finalization of the agreements implementing the new contractual and governance framework of the project effective January 1, 2008 (information on the Kashagan agreements is provided below under the section "Caspian Area" on page 39). Due to risks inherent in the exploration and production business, a degree of uncertainty still exists as to whether these additions will actually be produced. See "Item 3 – Risks associated with exploration and production of oil and natural gas" and – "Uncertainties in estimates of oil and natural gas reserves".

As of December 31, 2008 Eni’s share of proved reserves of equity-accounted entities amounted to 666 mmBOE. The 2008 year end amounts comprise 60% of proved reserves of the three Russian gas companies purchased in 2007 as part of a bid procedure for assets of bankrupt Russian company Yukos. Terms of the call option granted to Gazprom to purchase a 51% interest in the share capital of OOO SeverEnergia (Eni’s interest being 60%), which owns 100% of these three Russian companies engaging in the development of gas reserves, are currently under review by Eni, Enel and Gazprom.

The reserve replacement ratio for Eni’s subsidiaries was 136% in 2008 (38% in 2007 and 38% in 2006). The average reserve life index for Eni’s subsidiaries was 9.6 years at December 31, 2008. The reserve 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 SFAS No. 69 (see the supplemental oil and gas information in the Consolidated Financial Statements). The reserve replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by reserve additions booked according with SEC criteria under Rule 4-10 of Regulation S-X. Management considers the reserve replacement ratio to be an important gauge of the ability of the Company to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate development and production 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 infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks. Specifically, in recent years Eni’s replacement produced reserves has been affected by the impact of higher year-end oil prices on reserves entitlements in the Company’s Production Sharing Agreements (PSAs) 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 prices for Brent crude oil 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. In 2008 this negative trend reversed resulting in a higher amount of booked reserves associated with the Company’s PSAs as the oil price recorded at 2008 year-end was lower than the previous year.

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The table below show Eni’s calculations of its reserve replacement ratios for the years ended December 31, 2006, 2007 and 2008.

	Subsidiaries		Equity-accounted entities

	2006		2007		2008		2006		2007		2008

Additions to proved reserves		244			237			882			1			639			6
of which purchases and sales of reserves-in-place		(172	)		156			32						617
Production for the year		(640	)		(627	)		(650	)		(6	)		(7	)		(8	)

 

	Subsidiaries

	2006		2007		2008

Proved reserves replacement ratio of subsidiaries

38

38

136

Proved developed reserves of subsidiaries at December 31, 2008 amounted to 3,948 mmBOE (2,009 mmBBL of liquids and 11,138 BCF of natural gas) representing 63% of total estimated proved reserves (64% and 63% at December 31, 2007 and 2006, respectively).

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 679 mmBOE as of December 31, 2008 (676 and 583 mmBOE as of December 31, 2007 and 2006, respectively). Said volumes are not included in reserves volumes shown in the table herein.

The tables below set forth a geographical breakdown of Eni’s proved reserves and proved developed reserves of hydrocarbons, on a barrel of oil equivalent basis, for the periods indicated.

Proved reserves

Eni’s proved reserves of hydrocarbons by geographic area

Year ended December 31,

		2006		2007		2008

Italy		805		747		681
North Africa		2,018		1,879		1,922
West Africa		1,122		1,095		1,146
North Sea		682		617		510
Caspian Area		1,219		1,061		1363
Rest of the World		554		611		620
Total consolidated subsidiaries		6,400		6,010		6,242
Equity-accounted entities		36		668		666

Eni’s proved reserves of liquids by geographic area

Year ended December 31,

		2006		2007		2008

Italy		215		215		186
North Africa		982		878		823
West Africa		786		725		783
North Sea		386		345		276
Caspian Area		893		753		939
Rest of the World		195		211		236
Total consolidated subsidiaries		3,457		3,127		3,243
Equity-accounted entities		24		142		142

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Eni’s proved reserves of natural gas by geographic area

Year ended December 31,

		2006		2007		2008

Italy		3,391		3,057		2,844
North Africa		5,946		5,751		6,311
West Africa		1,927		2,122		2,084
North Sea		1,697		1,558		1,336
Caspian Area		1,874		1,770		2,437
Rest of the World		2,062		2,291		2,202
Total consolidated subsidiaries		16,897		16,549		17,214
Equity-accounted entities		68		3,022		3,015

Eni’s proved developed reserves of hydrocarbons by geographic area

Year ended December 31,

		2006		2007		2008

Italy		562		534		465
North Africa		1,242		1,183		1,229
West Africa		798		766		827
North Sea		571		524		407
Caspian Area		525		494		670
Rest of the World		334		361		350
Total consolidated subsidiaries		4,032		3,862		3,948
Equity-accounted entities		27		101		107

Eni’s proved developed reserves of liquids by geographic area

Year ended December 31,

		2006		2007		2008

Italy		136		133		111
North Africa		713		649		613
West Africa		546		511		576
North Sea		329		299		222
Caspian Area		262		219		321
Rest of the World		140		142		166
Total consolidated subsidiaries		2,126		1,953		2,009
Equity-accounted entities		18		26		33

Eni’s proved developed reserves of natural gas by geographic area

Year ended December 31,

		2006		2007		2008

Italy		2,449		2,304		2,031
North Africa		3,042		3,065		3,537
West Africa		1,447		1,469		1,443
North Sea		1,395		1,293		1,065
Caspian Area		1,511		1,580		2,006
Rest of the World		1,105		1,256		1,056
Total consolidated subsidiaries		10,949		10,967		11,138
Equity-accounted entities		48		428		420

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Mineral Right Portfolio and Exploration Activity for the year

As of December 31, 2008, Eni’s mineral right portfolio consisted of 1,244 exclusive or shared rights for exploration and development in 39 countries on five continents, for a total net acreage of 415,494 square kilometers (394,490 at December 31, 2007). Of these 39,244 square kilometers concerned production and development (37,642 at December 31, 2007). Outside Italy net acreage (395,085 square kilometers) increased by 21,258 square kilometers mainly due to the acquisition of Burren Energy Plc for a total net exploration and development acreage of 9,569 square kilometers (mainly in Turkmenistan, Yemen, Congo and Egypt) and an increase of net exploration acreage in Mali. These increases were partly offset by the contractual revision in Libya. In addition, new exploration leases were awarded in Angola, Algeria, Alaska, the Gulf of Mexico, Gabon, Indonesia, Norway and the United Kingdom for a total acreage of 57,361 square kilometers (net to Eni, 99% operated).

In Italy, net acreage (20,409 square kilometers) declined by 255 square kilometers due to releases.

A total of 111 new exploratory wells were drilled in 2008 (58.4 of which represented Eni’s share), as compared to 81 exploratory wells completed in 2007 (43.5 of which represented Eni’s share). In addition, 21 exploratory wells were in progress at year end. The overall commercial success rate was 36.5% (43.4% net to Eni) as compared to 40% (38% net to Eni) in 2007. In 2006, 68 exploratory wells were completed (35.9 of which represented Eni’s share), with an overall success rate of 43% (the success rate of Eni’s share of exploratory wells was 49%).

 

Production

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

In 2008, oil and natural gas production available for sale averaged 1,748 KBOE/d (liquids 1,026 KBBL/d; natural gas 4,143 mmCF/d), an increase of 64 KBOE/d, or 3.8%, compared to 2007. This improvement mainly came from the assets acquired in the Gulf of Mexico, Congo and Turkmenistan (up 62 KBOE/d), as well as continuing production ramp-up in Angola, Congo, Egypt, Pakistan and Venezuela. This increase was partially offset by mature field declines as well as planned and unplanned facility downtime in the North Sea and hurricane-related impacts in the Gulf of Mexico (down 11 KBOE/d). Higher oil prices on a yearly average resulted in lower volume entitlements in Eni’s PSAs and similar contractual schemes, down approximately 37 KBOE/d. When excluding the impact of lower entitlements in PSAs, production was up 5.6%. The share of oil and natural gas produced outside Italy was 89% (88% in the full year 2007).

Production of liquids amounted to 1,026 KBBL/d and was up 0.6% from a year ago. The most significant increases were registered in: (i) the Gulf of Mexico, Congo and Turkmenistan due to the contribution of acquired assets; (ii) Angola due to the start-up of the Mondo and Saxi/Batuque fields in the development area of former Block 15 (Eni’s interest 20%); and (iii) Venezuela due to the start-up of the Corocoro field (Eni’s interest 26%). Production decreases were reported in the North Sea and Italy due to planned and unplanned facility downtime and mature field declines. In addition, lower volume entitlements associated with higher average yearly oil prices were reported in the Company’s PSAs.

Production of natural gas for the full year was 4,143 mmCF/d and increased by 324 mmCF/d, or 8.5%, from a year ago. The improvement was driven by growth in the Gulf of Mexico, due to the contribution of acquired assets, and Pakistan due to production ramp-up of the Zamzama field (Eni’s interest 17.25%) and start-up of the Badhra field (Eni operator with a 40% interest). Production decreased in Italy and the United Kingdom due to mature field declines.

Oil and gas production sold in 2008 amounted to 632 mmBOE. Approximately 53% of liquids production sold (370.2 mmBBL) was destined to Eni’s Refining & Marketing division; about 32% of natural gas production sold (1,503 BCF) was destined to Eni’s Gas & Power division.

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The tables below set forth Eni’s production of liquids and natural gas on an available-for-sale basis for the periods indicated.

Year ended December 31,

		2006		2007		2008

Liquids production (1) (2)
Italy		79		75		68
North Africa		329		337		338
West Africa		322		280		289
North Sea		178		157		140
Caspian Area		64		70		81
Rest of the World		107		101		110
Total		1,079		1,020		1,026

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(1)

i

Data includes Eni’s share of production of affiliates and joint venture accounted for under the equity method of accounting amounting to 5, 7 and 8 KBBL/d in 2008, 2007 and 2006, respectively.

 

Year ended December 31,

		2006		2007		2008

Natural gas production available for sale (1) (2)
Italy		883		763		725
North Africa		1,187		1,357		1,661
West Africa		232		220		204
North Sea		557		557		521
Caspian Area		214		222		227
Rest of the World		606		700		805
Total		3,679		3,819		4,143

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(1)	i	Data includes Eni’s share of production of affiliates and joint venture accounted for under the equity method of accounting amounting to 13, 28 and 31 mmCF/d in 2008, 2007 and 2006, respectively.
(2)	i	It excludes production volumes of natural gas consumed in operations. Said volumes were 281, 296 and 286 mmCF/d in 2008, 2007 and 2006, 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 93 KBOE/d, 75 KBOE/d and 57 KBOE/d in 2008, 2007 and 2006, respectively.

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The table below sets forth certain information and operating data regarding Eni’s principal oil and natural gas interests as of December 31, 2008.

Principal oil and natural gas interests at December 31, 2008

		Commencement of operations		Number of interests		Gross exploration and development acreage (1)		Net exploration and development acreage (1)		Type of fields		Number of producing fields		Number of other fields
Italy		1926		159		25,522		20,409		Onshore/Offshore		87		99
Outside Italy				1,085		732,976		395,085		Onshore/Offshore		419		219
North Africa
Algeria		1981		34		2,921		909		Onshore		28		12
Egypt		1954		59		26,335		9,741		Onshore/Offshore		34		34
Libya		1959		13		36,375		18,164		Onshore/Offshore		12		17
Mali		2006		5		193,200		128,801		Onshore
Tunisia		1961		11		6,464		2,274		Onshore/Offshore		21		4
				122		265,295		159,889				95		67
West Africa
Angola		1980		55		20,492		3,323		Onshore/Offshore		45		27
Congo		1968		26		15,655		8,244		Onshore/Offshore		20		8
Gabon		2008		6		7,615		7,615		Onshore/Offshore
Nigeria		1962		50		44,049		8,574		Onshore/Offshore		95		38
				137		87,811		27,756				160		73
North Sea
Norway		1965		50		11,771		3,861		Offshore		13		8
United Kingdom		1964		91		5,207		1,450		Offshore		35		14
				141		16,978		5,311				48		22
Caspian Area
Kazakhstan		1995		6		4,933		880		Onshore/Offshore		1		5
Turkmenistan		2008		1		200		200		Onshore		2
				7		5,133		1,080				3		5
Rest of world
Australia		2001		18		60,486		29,520		Offshore		2		2
Brazil		1999		2		1,389		1,389		Offshore
China		1983		3		899		192		Offshore		10		3
Croatia		1996		2		1,975		988		Offshore		6		5
East Timor		2006		5		12,224		9,779		Offshore
Ecuador		1988		1		2,000		2,000		Onshore		1		1
India		2005		3		24,425		9,091		Onshore/Offshore		4		2
Indonesia		2001		11		28,605		17,316		Onshore/Offshore		7		12
Iran		1957		4		1,456		820		Onshore/Offshore		3
Pakistan		2000		21		35,938		18,855		Onshore/Offshore		7		3
Russia		2007		5		6,636		3,891		Onshore				9
Saudi Arabia		2004		1		51,687		25,844		Onshore
Trinidad & Tobago		1970		1		382		66		Offshore		3		4
United States		1968		575		11,478		6,648		Onshore/Offshore		69		11
Venezuela		1998		3		1,556		614		Offshore		1
Yemen		2008		1		3,911		3,598		Onshore
				656		245,047		130,611				113		52
Other countries				9		6,311		1,363		Offshore
Other countries with only exploration activity				13		106,401		69,075		Onshore/Offshore
Total				1,244		758,498		415,494				506		318

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(1)

i

Square kilometers.

Eni’s principal regions of operations are described below. In the discussion that follows references to hydrocarbon production are to be intended to hydrocarbon production available for sale.

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sidetracking and infilling (Antares, Cervia, Emma, Fratello North, Giovanna, Hera-Lacinia, Gela, Luna and Fiumetto); (ii) continuation of drilling and upgrading of producing facilities in the Val d’Agri; and (iii) completion of development activities at Cascina Cardana field and phase 1 of the Val d’Agri project.

Other development activities were the development of the Annamaria and the Guendalina gas fields in the Adriatic Sea. The Annamaria project provides for the installation of a production platform and the linkage by sealines to the Fano plant. Start-up is expected in 2009. Actions on Guendalina include the installation of a platform and the linkage by existing facilities to the Ravenna plant. Start-up is expected in 2010.

In December 2008 Eni was awarded two onshore exploration blocks in Puglia region.

Major discoveries were made in offshore Sicily with the operated gas discovery Cassiopea that has yielded excellent results in addition to the positive appraisal of the Argo gas field. Eni holds a 60% interest in the two discoveries. In particular for Cassiopea an accelerated development plan is foreseen in order to provide optimal synergies with the nearby Panda and Argo discoveries. The project provides for the drilling of undersea producing wells and the installation of a production platform linked to the existing onshore treatment facilities. Production start up is expected in 2011.

In the medium-term, management expects production in Italy to remain stable at current level due to the production ramp-up of the Val d’Agri fields and ongoing new field project and continuing development activities designed to counteract mature field decline.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2008, North Africa accounted for 36% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2008, Eni’s oil and gas production averaged 80 KBOE/d. Operating activities are located in the Bir Rebaa area in the South-Eastern desert and include the following exploration and production blocks: (a) Blocks 403 a/d (Eni’s interest 100%); (b) Blocks 401a/402a (Eni’s interest 55%); (c) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); and (d) under development Blocks 212 (Eni’s interest 22.38%) and 208 (Eni’s interest 12.25%).

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Rhourde Messaoud and Zemlet Adreg development licenses for further 10 years and the Bir Rebaa North license for further 5 years.

Production in Blocks 401a/402a is supplied mainly by the Rod and satellite fields and accounted for approximately 23% of Eni’s production in Algeria in 2008. Infilling activities are being performed in order to maintain the current production plateau.

The main fields in Block 403 are BRN, BRW and BRSW and accounted for approximately 14% of Eni’s production in Algeria in 2008. Exploration activities for appraising the mineral potential of the area are planned.

Block 208 is located south of Bir Rebaa. The El Merk Synergy, designed to jointly develop of this block and adjoining blocks operated by other companies, is the main project underway in Algeria. In 2008 following an international bid procedure, the seven EPC contracts of the project have been awarded. The project provides for the construction of a new treatment plant with a capacity of 11 KBOE/d net to Eni and production facilities in Block 404/208. Start-up is expected in the first quarter of 2012.

Main discoveries for the year were achieved in: (a) the Block 401a/402a with the ROD-21 appraisal well that started production through existing facilities; (b) the Block 404a with the BKNE-24 and HBNSE-12 appraisal wells, with the latter starting production through existing facilities.

The new Algerian hydrocarbon law No. 05 of 2007 introduced a higher tax burden for the national oil company Sonatrach that requested to renegotiate the economic terms of certain PSAs in order to restore the initial economic equilibrium. Eni signed an agreement for Block 403 while negotiations are ongoing for Block 401a/402a (Eni’s interest 55%) and Block 208 (Eni’s interest 12.25%). At present, management is not able to foresee the final outcome of such renegotiations.

In the medium-term, management expects to increase Eni’s production in Algeria to approximately 110 KBOE/d, reflecting the development and integration of the First Calgary acquired assets.

Egypt. Eni has been present in Egypt since 1954. In 2008, Eni’s share of production in this country amounting to 232 KBOE/d and accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Belayim concession (Eni’s interest 100%) and offshore the Gulf of Suez. Gas production mainly comes from the operated or participated concession of North Port Said (former Port Fouad, Eni’s interest 100%), Baltim (50% interest), Ras el Barr (50% interest, non-operated) and el Temsah (50% interest) offshore the Nile Delta. In 2008 production from these concessions also including a portion of liquids accounted for 90% of Eni’s production in Egypt.

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In the medium-term, management expects production in Egypt to be one of Eni’s largest oil and gas producing countries.

Libya. Eni started operations in Libya in 1959. In 2008, Eni’s oil and gas production averaged 300 KBOE/d, the portion of liquids being 48%. Production activity is carried out in the Mediterranean offshore facing Tripoli and in the Libyan Desert area.

In June 2008, Eni and the Libyan national oil company NOC finalized six Exploration and Production Sharing contracts (EPSA) converting the original agreements that regulated Eni’s exploration and development activities in the country. The terms of Eni’s assets in Libya have been extended till 2042 and 2047 for oil and gas properties respectively. The two partners have also agreed to develop a number of industrial initiatives designed to monetize the large reserve base, particularly through the implementation of important gas projects. The economic effects and Eni’s production entitlements based on the new contracts have been determined effective from January 1, 2008.

Under above agreement the Eni’s assets have been grouped into six contract areas as follows: (i) area A including 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 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 Muzurk basin (161/1, 161/2&4, 176/3) and in the Kufra area (186/1, 2, 3 & 4).

The tax burden on Eni’s taxable profit has been determined based on the renewed tax framework, enacted in 2007, applicable to foreign oil companies operating under PSA schemes. In line with past practice, NOC has retained the role of tax agent on behalf of foreign oil companies. This tax regime does not alter the agreed economic value of the EPSAs currently in place between Eni and NOC. Based on the arrangements agreed upon with NOC, the tax base of the Company’s Libyan oil properties has been reassessed resulting in the partial utilization of previously accrued deferred tax liabilities amounting to euro 173 million.

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Within the Western Libyan Gas project upgrading of plants and facilities is underway aimed at increasing gas exports by 106 BCF/y fully operating from the 2014 and maintaining production profiles at the Wafa oil field. In 2008 exported volumes amounted to 332 BCF, equal to 90% of the total gas production of the two fields. In addition 35 BCF were sold on the Libyan market for power generation. Other ongoing development activities concern the A-NC118 field (Eni’s interest 50%) linking it to the pipelines connecting Wafa with Mellitah plant and the valorization of associated gas of the Bouri field. The partially treated gas and associated condensates will be shipped by sealine to the nearby Sabratha platform and exported through the GreenStream pipeline. Main discoveries for the year were achieved in: (a) the offshore Block NC41, where the U1-NC41 discovery well showed the presence of oil and natural gas and the D4-NC41 appraisal well showed the presence of natural gas and condensates; and (b) in former Concession 82, the YY-1 discovery well showed the presence of oil. In the medium-term, management expects to increase Eni’s production in Libya owing to the expected ramp-up of new mineral structures near the Western Libyan Gas Project fields with the support of the upgrade of the GreenStream pipeline, despite mature field declines. Eni targets a production level in excess of 280 KBOE/d. If this target is achieved, in the medium-term Libya will become the largest producing country by volume in Eni’s portfolio.

 

Tunisia. Eni has been present in Tunisia since 1961. In 2008, Eni’s production amounted to 15 KBOE/d. Eni’s activities are located mainly in the Mediterranean offshore facing Hammamet and in the Southern desert areas.

Exploration and production in this country are regulated by concessions.

Production mainly comes from 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.

The ongoing development activities mainly regarded the optimization of production at the Adam, Oued Zar, MLD and El Borma concessions.

Development activities started also at the production platform of the Maamoura (Eni’s interest 49%) and Baraka (Eni’s interest 49%) fields. Production start-up is expected in 2009.

Main discoveries for the year were achieved in the following permits: (a) Adam, where the Mejda-1 and El Azzel North-1 wells showed the presence of oil; (b) Bek (Eni operator with a 25% interest), where the Abir-1 well found oil and natural gas; (c) MLD, where the LASSE-1 well found oil and natural gas; and (d) El Borma, where the EB-406 exploratory well showed additional oil resources.

In the medium-term, Eni expects production in Tunisia to increase due to the development of recent discoveries.

West Africa

Eni’s operations in West Africa are conducted in Angola, Congo and Nigeria. In 2008, West Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2008, Eni’s production averaged 121 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

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Development at the Landana and Tombua oil fields in offshore Block 14 (Eni’s interest 20%) progressed. Early production is ongoing in the north area of Landana that was linked to the Benguela/Belize-Lobito/Tomboco facilities. Production is expected to peak at 100 KBBL/d in 2010 at the end of the drilling program.

Activities at the Banzala oil field in Block 0 in Cabinda (Eni’s interest 9.8%) progressed as planned. The commissioning of a third production platform was achieved early 2008. Peak production at 27 KBBL/d (3 net to Eni) is expected in 2009. Mafumeira project in Block 0 also progressed according to schedule toward first production expected in 2009.

With respect to the activities for gas flaring reduction, projects progressed at the Takula and Nemba fields in Block 0. The start-up of Takula project is expected in 2009. Gas currently flared will be re-injected in the field; condensates will be shipped via a new pipeline to the Malongo treatment plant to be converted into LPG. Development activities at the Nemba field are planned including the drilling of gas injection wells and the installation of a new production platform. Start-up is expected in 2011.

The Mondo and Saxi/Batuque fields in Block 15 (Eni’s interest 20%) were started-up by means of a floating, production, storage and offloading (FPSO) vessel. Peak production at 100 KBBL/d (18 KBBL/d net to Eni) was achieved at both fields in 2008. The outlined projects and other ongoing development activities aim at maintaining current oil production plateau in the area.

In 2008 the final investment decision was achieved regarding the development of the Kizomba Satellites project-phase 1. The project plans to produce reservoir of the Clochas and Mavacola oil discoveries. Start-up is expected in 2012.

Eni holds a 13.6% interest in the Angola LNG Limited (A-LNG) consortium responsible for the construction of an LNG plant in Soyo, 300 kilometers north of Luanda. It will be designed with a processing capacity of 1 BCF/y of natural gas and produce 5.2 mmtonnes/y of LNG and related products. The project has been sanctioned by relevant Angolan authorities. It envisages the development of 10,594 BCF of associated gas reserves in 30 years. Gas volumes currently being produced from offshore production blocks are flared. In 2008 the final investment decision was reached to build a pipeline linking the fields located in Blocks 0 and 14 to LNG plant in order to monetize gas currently flared. Start-up is expected in 2012.

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Main oil discoveries for the year were made in: (a) Block 15/06, with the Ngoma-1 and Sangos-1 discoveries. Both discoveries were declared of commercial interest; (b) Block 0, with the Kambala appraisal well; (c) the development area of former Block 14, with the Lucapa-5 appraisal well; and (d) the development area of former Block 15 with the Mavacola-3 appraisal well.

In the medium-term, management expects to increase Eni’s production to approximately 150 KBBL/d reflecting contributions from ongoing development projects, despite mature field declines.

Eni plans to monetize the heavy oil by applying its EST (Eni Slurry Technology) proprietary technology intended to fully convert the heavy oil into high quality light products. The project will also benefit from synergies resulting from the close proximity of the operated M’Boundi oilfield; (ii) collaboration in the use of vegetable oils, aimed at covering domestic demand for food uses and using excess amounts for the production of bio-diesel with Eni’s proprietary technology Ultra-Bio-Diesel; and (iii) construction of a 450 MW electricity generation plant near the Djeno oil terminal, with start-up expected in late 2009. The power station (Eni’s share 20%) will be fired with the associated natural gas from the M’Boundi field and offshore discoveries in permit Marine XII (Eni operator with a 90% interest) contributing to the reduction of gas flaring. The final investment decision was reached in 2008. This project aims at qualifying as Clean Development Mechanism in implementing the Kyoto protocol and as a contribution to the sustainable development of the Country.

The Awa Paloukou (Eni’s interest 90%) and Ikalou-Ikalou Sud (Eni’s interest 100%) operated fields in the Marine X and Madingo permits were started up in 2008 with production peaking at 13 KBOE/d net to Eni in 2009.

Development activities of the M’Boundi field moved forward with the revision of the production schemes and layout to plan application of advanced recovery techniques and a design to monetize associated gas.

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 140 KBBL/d in 2012.

Nigeria. Eni has been present in Nigeria since 1962. In 2008, Eni’s oil and gas production averaged 119 KBOE/d located mainly in the onshore and offshore of the Niger Delta.

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In the development/production phase Eni is operator of onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%), OMLs 120-121 (Eni’s interest 40%) and holds a 12.5% interest in OML 118 as well as in OML 119 and 116 service contracts. Through SPDC JV oil joint venture, Eni also holds a 5% interest in 31 onshore blocks and a 12.86% interest in 5 conventional offshore blocks. In the exploration phase Eni is operator of Oil prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (former OPL 211 - Eni’s interest 85%) 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 (former OPL 219).

In December 2008 Eni exercised its pre-emption rights on the remaining 49.81% interest in Blocks OML 125 and 134. On the same occasion Eni transferred a 15% stake to the Nigerian company OANDO. This transaction has been approved by relevant authorities.

Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, where Eni acts as contractor for state owned companies.

In Blocks OMLs 60, 61, 62 and 63 development activities of gas reserves are underway: (i) the basic engineering work for increasing capacity at the Obiafu/Obrikom plant was completed. The project also provides for the installation of a new treatment plant and transport facilities; and (ii) the development plan of the Tuomo gas field has been progressing. Production is expected to start by means of linkage to the Ogbainbiri treatment plant. These activities target to supply 311 mmCF/d of feed gas to the Bonny liquefaction plant (Eni’s interest 10.4%) for a period of 20 years.

In the OML 118, Bonga field produced about 19 KBOE/d net to Eni via a FPSO unit with a 225 KBBL/d treatment capacity. The associated gas is gathered into a platform in EA field and then delivered to the Bonny liquefaction plant.

In the OML 119, Okono/Okpoho production reached about 12 KBBL/d net to Eni via a FPSO unit with a 40 KBBL/d treatment capacity.

In the OMLs 120/121 blocks (Eni operator with a 40% interest), the development plan of the Oyo oil discovery was approved. The project provides for the installation of an FPSO unit with treatment capacity of 40 kBBL/d and storage capacity of 1 mmBBL. Production start-up is expected in 2009.

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Through the SPDC JV, the Forcados/Yokri oil and gas field is under development as part of the integrated associated gas gathering project aimed at supplying gas to the Bonny liquefaction plant. Offshore production facilities have been installed. Onshore activities regard the upgrading of the Yokri and North/South Bank flow stations and the construction of a gas compression plant with a 233 mmCF/d capacity. Completion is expected in 2009.

In the OML 125, oil production deriving from Abo field. Ongoing development activities aim at reaching a peak production of 27 KBBL/d (18 KBBL/d net to Eni) in 2009. Production is supported by an FPSO unit with a 45 KBBL/d capacity and an 800 KBBL storage capacity.

Eni holds a 10.4% interest in Nigeria LNG Ltd that manages the Bonny liquefaction plant located in the Eastern Niger Delta, with a treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 trains. The seventh unit is being engineered with start-up expected in 2012. 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. In 2008 total supplies were 3,461 mmCF/d (268 mmCF/d net to Eni, corresponding to 46 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 is operator with a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal. This plant is expected to start operating in 2014 with a production capacity of 10 mmtonnes/y of LNG corresponding to 618 BCF/y (approximately 64 net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the OMLs 60 and 61 onshore blocks. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity. The front end engineering is underway and the final investment decision is expected in 2009.

In the medium-term, management expects to increase Eni’s production in Nigeria to approximately 200 KBOE/d, reflecting in particular the development of gas reserves.

North Sea

Eni’s operations in the North Sea area are conducted in Norway and United Kingdom. In 2008, the North Sea accounted for 13% of Eni’s total worldwide production of oil and natural gas.

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Currently Eni is only performing exploration activities in Barents Sea. Operations in this area are focused on the appraisal of the mineral potential of the large Goliath discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest) aimed at its commercial development. The project is progressing according to schedule. Commencement is expected in 2013 with a production plateau at 100 kBBL/d. In 2008 contracts were awarded for the study of two possible development plans by means of a cylindrical FPSO unit. The final investment decision is expected in 2009.

Main discoveries for the year were achieved in the: (a) Prospecting License 312 (Eni’s interest 17%) with the Gamma gas discovery at a depth of about 2,500 meters. Production will be treated at the nearby Aasgaard facilities; (b) the Prospecting License 122 (Eni operator with a 20% interest), where appraisal activities confirmed the mineral potential of the Marulk discovery; (c) the Prospecting License 293 (Eni operator with a 45% interest), with the gas and condensate Aphrodite discovery. Ongoing pre-development activities aim to assessing the economic viability of the project; and (d) Prospecting License 128 (Eni’s interest 11.5%) with the Dompap gas discovery at a depth of about 2,750 meters. Appraisal activities are underway.

United Kingdom. Eni has been present in the United Kingdom since 1964. Eni’s activities are carried out in the British section of the North Sea, in the Irish Sea and in some areas East and West of the Shetland Islands. In 2008 Eni’s net production of oil and gas averaged 104 KBOE/d.

Exploration and production activities in the United Kingdom are regulated by concession contracts.

In November 2008, Eni finalized an agreement with the British company Tullow Oil to purchase a 52% stake and the operatorship of fields in the Hewett Unit in the British section of the North Sea and relevant facilities including the associated Bacton terminal. Eni acquired operatorship of the assets with an 89% interest. Eni aims to upgrade certain depleted fields in the area so as to achieve a gas storage facility with a 177 BCF working gas capacity to support seasonal upswings in gas demand in the UK leveraging on the strategic purchased facilities. The Bacton terminal, in fact, is very close to the incoming point of the Interconnector pipeline connecting the United Kingdom with Europe. For this purpose, Eni intend to request a storage license.

In December 2008 following an international bid procedure, Eni was awarded four exploration blocks with a 22% interest located in the Shetland Islands. One of the awarded blocks is located near the Tormore (Eni’s interest 20%) and Laggan (Eni’s interest 20%) recent gas discoveries in the North Sea.

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Eni holds interests in 12 production areas in the British section of the North Sea. The main fields are Elgin/Franklin (Eni’s interest 21.87%), the J-Block (Eni’s interest 33%), Andrew (Eni’s interest 16.21%), Farragon (Eni’s interest 30%), the Flotta Catchment Area (Eni’s interest 20%) and Mac-Culloch (Eni’s interest 40%) which in 2008 accounted for 63% of Eni’s production in the United Kingdom. Development activities progressed at the West Franklin field (Eni’s interest 21.87%) by completing a second development well planned. The production is supported by facilities of the nearby Elgin/Franklin field which peaked at 20 KBOE/d (4 net to Eni). Other activities related to: (i) optimization of production in the J-Block through the upgrading of existing facilities; and (ii) infilling actions at the Flotta Catchment Area and Mac-Culloch fields targeting to maintain production levels. Development activities started at the Burghely field (Eni’s interest 21.92%). Pre-development activity continued on the Suilven discovery (Eni’s interest 8.75%).

Eni holds a 53.9% interest in 6 production fields in the Liverpool Bay area in the Eastern section of the Irish Sea. Main fields are Douglas, Hamilton and Lennox and their extension which in 2008 accounted for 24% of Eni’s production in UK. Facilities upgrading is underway.

Eni holds interest in 6 production permits located East of the Shetland Islands. Main fields are Ninian (Eni’s interest 12.94%) and Magnus (Eni’s interest 5%) which in 2008 accounted for 4% of Eni’s production in the United Kingdom. In 2008 maintenance and optimization actions were performed with the drilling of infilling wells.

Main discoveries for the year were achieved in the: (i) Block 16/23 (Eni’s interest 16.67%) with the Kinnoul oil and gas discovery which is planned to be developed in synergy with the production facilities of the Andrew field (Eni’s interest 16.21%); (ii) Block 30/6 (Eni’s interest 33%) where gas and condensates were found near the recent Jasmine discovery. Joint development of these two structures is being assessed in combination with existing facilities; and (iii) Block 22/25a (Eni’s interest 16.95%) with the gas and condensate Culzean discovery near the Elgin/Franklin producing field (Eni’s interest 21.87%). Study of development activities is underway.

Caspian Area

In 2008, Eni’s operations in the Caspian Area accounted for 7% of its total worldwide production of oil and natural gas.

Kazakhstan. Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and, up to January 2009, acted as the single operator of the North Caspian Sea Production Sharing Agreement (NCSPSA) activities.

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Kashagan. Eni holds a 16.81% participating interest in the NCSPSA. The change in the participating interest from a previous 18.52% was effective as of January 1, 2008 according to an agreement signed in October 2008 with the Kazakh authorities. The Eni partners of this international consortium are the Kazakh national oil company KazMunayGas 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% based on the renewed contractual arrangements. The NCSPSA defines terms and conditions for the exploration and development activities to be performed in the area covered by the contract. The Kashagan field was discovered in the northern section of the contractual area in the year 2000. Management believes this field to contain a large amount of hydrocarbon resources. The phased development plan of the Kashagan field provides for the drilling of about 240 wells and the construction of production plants located on artificial islands which will collect production from other satellite artificial islands. Oil production will be marketed. Natural gas will be mostly used (80%) for re-injection into the reservoir for maintaining pressure levels. The natural gas not re-injected will be treated for the removal of hydrogen sulphide and will be used as fuel in power generation for the production plants. The remaining amounts will be marketed.

As outlined above, on October 31, 2008, all the international partners of the NCSPSA consortium and the Kazakh authorities signed the final agreement implementing the new contractual and governance framework of the Kashagan project, based on the Memorandum of Understanding signed on January 14, 2008.

The material terms of the agreement are: (i) the proportional dilution of the participating interest of all the international members of the Kashagan consortium, following which the stake held by the national Kazakh Company KazMunayGas and the stake held by the other four major stakeholders are each equal to 16.81%, effective from January 1, 2008. The Kazakh partner will pay the other co-ventures an aggregate amount of $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the NCSPA, the amount of which will vary in proportion to future levels of oil prices. Eni is expected to contribute to the value transfer package in proportion to its new participating interest in the project (16.81%); and (iii) a new operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The new North Caspian Operating Company (NCOC) BV has been established and capitalized by the seven partners of the consortium. In January 2009 the new entity 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 is confirmed to be the operator of phase-one of the project (the so-called "Experimental Program") and in addition will retain operatorship of the onshore operations of phase 2 of the development plan.

In conjunction with the signing of the final agreements, the partners also reached a final approval of the revised expenditure budget of phase-one of the development plan, amounting to $32.2 billion (excluding general and administrative expenses) of which $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities. Eni will fund those expenditures in proportion to its participating interest of 16.81%. Management expects to achieve first oil late in 2012 on the basis of progress to completion (55% of phase 1 of the project) and accumulated expertise and project know-how. In the following 12-15 months treatment facilities and compression units for gas re-injection will be entirely commissioned enabling the Consortium to deploy an installed production capacity of 370 KBBL/d in 2014. Subsequently, production capacity of phase-one (Experimental Program) is expected to step-up to 450 KBBL/d, leveraging on additional compression capacity for gas re-injection associated with the start-up of phase-two offshore facilities. In addition, within phase-one a rail terminal with carrying capacity at 300 KBBL/d of oil and 4,500 tonnes/d of sulphur will be built.

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The development plan of the Kashagan field was originally sanctioned by the Kazakh authorities in February 2004, contemplating a three-phase development scheme including partial gas re-injection in the reservoir to enhance the recovery factor of the crude oil. The sanctioned plan budgeted expenditures amounting to U.S. $10.3 billion (in 2007 real terms) to develop phase-one, with a target production level of 300 KBBL/d. First oil was originally scheduled to be produced by the end of 2008. Eni was expected to fund these expenditures according to its participating interest in this project. On June 29, 2007, Eni, as operator, filed with the relevant Kazakh authorities amendments to the sanctioned development plan. These amendments rescheduled the production start-up to 2010 and estimated development expenditures for phase-one at U.S. $19 billion. As outlined above the amended development plan that was sanctioned in October 2008 forecast production start-up late in 2012 and an expenditure budget for phase one amounting to $25.4 billion. The production delay and cost overruns were driven by a number of factors: depreciation of the U.S. dollar versus the euro and other currencies; cost price 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 magnitude of the reserves base, the results of the well tests conducted and the findings of subsurface studies completed so far support expectations for a full field production plateau of 1.5 mmBBL/d, which represents a 25% increase above the original plateau as presented in the 2004 development plan. An independent reserve evaluation performed by a petroleum engineer (Ryder Scott Petroleum Consultants) fully supports the target production plateau. The achievement of the full field production plateau will require a material amount of expenditures in addition to the development expenditures needed to complete the execution of phase-one. However, taking into account that future development expenditures will be incurred over a long time horizon, 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, for which various options are currently under review by the consortium. These include: (i) the use of existing infrastructure, such as the Caspian Pipeline Consortium pipeline (Eni’s interest 2%) and the Atyrau-Samara pipeline, both of which are expected to undergo a capacity expansion; (ii) the construction of a new transportation system. In this respect, it is worth mentioning the project aimed at building a line connecting the onshore Bolashak production centre with the Baku-Tbilisi-Cehyan pipeline (where Eni holds an interest of 5% corresponding to the right to transport 50 KBBL/d) through the KCTS pipeline to Kuryk and a further shipping across the Caspian Sea to Baku; and (iii) the construction of a new transport system linking Samsum on the Turkish coast of the Black Sea to Cehyan on the Mediterranean coast in order to bypass the Turkish Straits of Bosporus and Dardanelles.

As of December 31, 2008, Eni’s proved reserves booked for the Kashagan field amounted to 594 mmBOE determined according to Eni’s participating interest of 16.81%, recording an increase of 74 mmBOE with respect to 2007 despite the divestment of a 1.71% stake in the Kashagan project following the finalization of the agreements implementing the new contractual and governance framework of the project. The amount booked for the year reflected higher volume entitlements resulting from lower year end oil prices from a year ago and upward revisions of previous estimates which were supported by an independent evaluation of the field made by an oil engineering company (Ryder Scott Petroleum Consultants).

As of December 31, 2007, Eni’s proved reserves booked for the Kashagan field amounted to 520 mmBOE, recording a decrease of 76 mmBOE with respect to 2006 mainly due to the impact of increased year-end oil prices on reserve entitlements in accordance with the PSA scheme. Proved reserves for the field as of December 31, 2007 were determined according to Eni’s then current participating interest of 18.52%.

As of December 31, 2006, Eni’s proved reserves booked for the Kashagan field amounted to 596 mmBOE, recording an increase of 107 mmBOE with respect to 2005 due to an extension of the proved area and project cost revision, offset in part by the impact of price revisions.

As of December 31, 2008, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $3.3 billion (euro 2.4 billion at the EUR/USD exchange rate of December 31, 2008) net of the divestment of a 1.71% stake in the Kashagan project following the finalization of the agreements implementing the new contractual and governance framework of the project ($0.4 billion). This capitalized amount included: (i) $2.3 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $1 billion relating primarily to accrued 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, 2007, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $2.6 billion. This capitalized amount included: (i) $1.8 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $0.8 billion relating primarily to accrued 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. The $2.6 billion amount was equivalent to euro 1.8 billion based on the 2007 year-end euro /U.S. dollar exchange rate.

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As of December 31, 2006 the aggregate costs incurred by Eni for the Kashagan project that were capitalized by Eni in its financial statements amounted to $1.9 billion, corresponding to euro 1.5 billion based on 2006 year-end exchange rates.

Costs borne by Eni to explore and develop this field are recovered in accordance with the mechanisms typically contemplated by a PSA scheme, which is widely used in the industry. In this type of contract the national oil company or State-owned entity assigns to the international oil company (the contractor) the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is generally 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. Accordingly, recoverability of the expenditures is subject to approval from the relevant State-owned or controlled entity who is party to the agreement. Similarly, cost overruns are recovered to the extent they are sanctioned by the State-owned or controlled entity who is party to the agreement.

Karachaganak. Located in West onshore Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a Production Sharing Agreement lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture both with a 32.5% interest.

In 2008 production from this field averaged 234 KBBL/d of liquids (69 KBBL/d net to Eni) and 774 mmCF/d of natural gas (227 mmCF/d 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 two thirds of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity in excess of 150 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining third of non-stabilized liquid production and volumes of associated gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg.

The execution of fourth oil treatment unit has been progressed to completion and will enable to increase the exported oil volumes to Western markets.

The Phase 3 project engineering activities have identified a staged approach to best develop the Karachaganak field. The first stage envisages the development of approximately 55 mmtonnes of liquids the doubling of the existing gas injection capacity (from 233 to 466 BCF/y) and the maintenance of a production plateau at 12 mmtonnes/y of stabilized liquids (until 2018) and 318 BCF/y of acid gas at Orenburg. An alternative option is under review which entails marketing of a portion of the additional gas re-injected. Start-up is expected late in 2013 subject to approval by the relevant authorities.

The construction of the Uralsk Gas Pipeline is ongoing. This new infrastructure, with a length of 150 kilometers, will link the Karachaganak field to the Kazakhstan gas network. Start-up is expected in 2009.

In April 2008, the Kazakh authorities approved a tax decree enacting an Export Duty on crude oil; such tax was applied on Karachaganak from July 2008 up to January 2009 when it was "zero rated". In the same month the authorities enacted a new tax code that does not affect the profitability of this project taking into account that certain clauses in the PSA regulating the activities at the field provide the stability of the tax burden for the ventures.

As of December 31, 2008, Eni’s proved reserves booked for the Karachaganak field amounted to 740 mmBOE, recording an increase of 200 mmBOE with respect to 2007 and derived from upward revisions of previous estimates mainly related to higher entitlements reported in PSA resulting from lower year end oil prices from a year ago.

As of December 31, 2007, Eni’s proved reserves booked for the Karachaganak field amount to 541 mmBOE, recording a decrease of 82 mmBOE with respect to 2006 as a result of downward and upward revisions of previous estimates. Downward revisions mainly related to an adverse price impact in determining volume entitlements in accordance with the PSA scheme. These negative revisions were partly offset by upward revisions mainly related to the finalization of the gas sale contract as outlined above.

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Turkmenistan. Eni started its activities in Turkmenistan in connection with the purchase of British company Burren Energy plc in 2008. Activities are mainly focused in the western part of the country. In 2008 Eni’s production averaged 12 KBOE/d. Exploration and production activities in Turkmenistan are regulated by Production Sharing Agreements. Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. During 2008, the development activities were focused at the production optimization by means of drilling development wells and carry-over of the program for water injection and facility upgrading. The drilling activity at Uzboy and Balkan fields, nearby Burun field, progressed. The fields achieved early production in 2006.

Rest of the World

In 2008, Eni’s operations in the rest of world accounted for 14% of its total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2000. In 2008 Eni’s production of oil and natural gas averaged 16 KBOE/d. Activities are focused on conventional and deep offshore fields.

The main production blocks in which Eni holds interests are WA-25-L (Eni operator with a 65% interest) and JPDA 03-13 (Eni’s interest 10.99%). In the exploration phase Eni holds interests in 13 licenses (in 7 as operator and in 5 of which with a 100% interest), of particular interest are the blocks WA-33-L and WA-313-P, where the Blacktip and Penguin discoveries are located.

Exploration and production activities in Australia are regulated by concessions, while in the cooperation zone between East Timor and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs.

The main producing fields are Woollybutt and Bayu Undan in WA-25-L and JPDA03-13, respectively.

In 2008 development activities have been completed in the southern area of the Woollybutt oil field with a new horizontal production well that was linked to an FPSO unit with relevant production ramp-up in July 2008.

Development activities are underway at the Blacktip gas field (Eni operator with a 100% interest). The development strategy envisages installation of an unmanned platform that will be linked to an onshore treatment plant. Start-up is expected in 2009, peaking at 26 BCF/y in 2010. Natural gas production is destined to supply a power plant.

In 2008, an important discovery was made in the Block JPDA 06-105 (Eni operator with a 40% interest), located in the international offshore cooperation zone between East Timor and Australia, where the Kitan discovery showed the presence of oil at a depth of 3,658 meters and yielded 6.1 KBBL/d in test production. In June 2008, the oilfield development area was approved by the Timor Sea Designated Authority pursuant to the declaration of commercial discovery that was made by Eni. Activities are ongoing for the preparation of a development plan to be filed with relevant authorities. The final investment decision is expected in 2009.

In the medium-term, management expects to increase Eni’s production in Australia through ongoing development activities.

Brazil. Eni has been present in Brazil since 1999 and is performing exploration activities in: (i) operated blocks BM-S-4 and BM-S-857, subjected official awarding, (both with a 100% interest) located in the deep offshore in the Santos basin; (ii) block BM-CAL-14 (Eni operator with a 100% interest) in the deep offshore in the Camamu-Almada basin.

The current exploration program aims at appraising the Belmonte gas discovery in block BM-S-4.

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In 2008 Eni and Petrobras renewed a Memorandum of Understanding signed on 2007 aimed at identifying joint production and refining opportunities. Eni will make available its EST (Eni Slurry Technology) proprietary technology for the complete conversion of heavy oils (typical of the Brazilian upstream) into high-quality light products. China. Eni has been present in China since 1984. Activities are located in the South China Sea. In 2008 Eni’s production amounted to 8 KBOE/d. Exploration and production activities in China are regulated by Production Sharing Agreements. Production derives mainly from offshore blocks 16/08 and 16/09 operated by the CACT-Operating Group (Eni’s interest 16.33%). Oil production, destined to the domestic market, mainly derives from the HZ25-4 field (Eni’s interest 49%) through fixed platforms underwater linked to an FPSO. Natural gas production from the HZ21-1 field is delivered to the Zhuhai treatment plant.

Ongoing development activities are mainly focused on the HZ25-4 and the HZ25-3/1 fields, on the latter the construction of a production platform is ongoing and start-up is expected in 2009. The development plan of the HZ25-4 field, on stream since 2007, provides for the drilling of addition producing wells as planned.

Colombia. In 2008 Eni signed a Memorandum of Understanding with the national oil company Ecopetrol aimed at identifying joint opportunities for exploration and production in Colombia and in other Southern American countries.

Croatia. Eni has been present in Croatia since 1996. In 2008 Eni’s production of natural gas averaged 66 mmCF/d. Activities are deployed in the Adriatic Sea facing the city of Pula. Exploration and production activities in Croatia are regulated by PSAs. The main producing gas fields are Ivana, Ika & Ida, Marica and Katerina operated by Eni through a 50/50 joint venture with the Croatian oil company INA. In 2008 the Ana field (Eni’s interest 50%) was started-up through linkage to the facilities existing in the area. Development activities are nearing completion in the Irina, Vesna and Annamaria fields. Start-ups are expected in 2009. Exploration activities yielded positive results in the Bozica (Eni’s interest 50%) and the Ika gas fields with appraisal activity.

East Timor. Eni entered East Timor in 2006 and is operator with an 80% interest of 5 offshore blocks. The first exploration phase of the exploration plan with a three-year term provides for the acquisition seismic data which was completed during the year, and the drilling of 2 wells.

Ecuador. Eni has been present in Ecuador since 1988. In 2008 Eni’s production averaged 16 KBBL/d. Since 2000, Eni became operator of Block 10 (Eni’s interest 100%) located in the Amazon forest and on which Villano field has been discovered.

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

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Production derives from the Villano field, started-up in 1999. Production is carried out by means of a Central Production Facility linked by pipeline to the storage facility. During the year work-over and infilling activities were aimed to contrast the natural depletion.

India. Eni has been present in India since 2005.

In August 2008, Eni acquired control of the Indian Company Hindustan Oil Exploration Ltd (HOEC) following execution of a mandatory tender offer on a 20% stake of the HOEC share capital. The mandatory offer was associated with Eni’s acquisition of a 27.18% of HOEC as part of the Burren Energy deal. Assets acquired, located onshore in the Cambay Basin and offshore Chennai, include: (i) development and producing assets which are expected to reach a production plateau of 10 KBOE/d in 2010; and (ii) fields where exploration and appraisal activities are underway. Main development activities are focused on the PY1 gas field. Start-up is expected in 2009.

Other activities are related to exploration of the onshore Block RJ-ONN-2003/1 (Eni operator with a 34% interest) and offshore Blocks AN-DWN-2003/2 (Eni operator with a 40% interest) and MN-DWN-2002/1 (Eni’s interest 34%).

The exploration program for Block RJ-ONN-2003/1 located in the desert of Rajasthan provides for the drilling of 4 wells in the first four years of the license. Any hydrocarbons discovered will be sold locally.

The exploration program for Block AN-DWN-2003/2 near the Andaman Islands provides for the drilling of 3 wells in the first four years of the license and expected start-up in 2010.

The exploration program for Block AN-DWN-2002/1 located in the deep offshore of the eastern coast provides for the drilling of 3 wells in the first year of the license.

Indonesia. Eni has been present in Indonesia since 2000. Eni’s production amounted to 16 KBOE/d, mainly gas, in 2008. Activities are concentrated in the eastern offshore and onshore of Borneo and the offshore Sumatra, where Eni holds interest in 11 blocks.

In May 2008, following an international bid procedure, Eni was awarded the operatorship of the West Timor exploration block extending over an offshore and onshore area of about 4,000 square kilometers.

Exploration and production activities in Indonesia are regulated by PSAs.

Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.81%) with seven production fields. This gas is treated at the Bontang liquefaction plant, one of the largest in the world, and is exported to the Japanese, South Korean and Taiwanese markets.

Eni as operator is evaluating major development opportunities in the Bukat permit (Eni’s interest 66.25%) where oil and gas discoveries were recently made. Eni, as partner, is also involved in the ongoing joint development of the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%), gas production of which will be sent to the Bontang LNG plant.

During 2008, the exploration activity was focused: (i) in the Krueng Mane permit (Eni operator with a 85% interest), with the start-up of the drilling activities; and (ii) in the Bukat permit, with the finalization of a seismic data acquisition campaign.

Iran. Eni has been present in Iran since 1957. In 2008 Eni’s production averaged 28 KBBL/d. Activities are concentrated in the offshore and onshore facing of the Persian Gulf.

Exploration and production activities in Iran are regulated by buy-back contracts.

The main producing fields are South Pars phases 4&5 in the offshore of the Persian Gulf and Darquain field located onshore which accounted for 91% of Eni’s production in Iran in 2008. Eni also holds interests in the Dorood field (Eni’s interest 45%).

The main project regards the Darquain field operated by Eni with a 60% interest. Upgrading activities are underway by means of drilling additional wells, increasing capacity of the existing treatment plant and gas injection. These actions aim at increasing production from the present 100 KBBL/d to over 160 KBBL/d (14 net to Eni) by 2009.

The legislation and other regulations of the United States of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties. Particularly, under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition

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of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under, ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 9 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buyback contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country. It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation.

Pakistan. Eni has been present in Pakistan since 2000. In 2008 Eni’s production averaged 54 KBOE/d, mainly gas.

Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).

In March, 2009 Eni signed a Protocol for Cooperation with the government of Pakistan to develop a number of important upstream, midstream and downstream projects in the Country. This deal follows Eni’s growth strategy through the discovery of new reserves. Eni will provide its expertise as well as new technologies developed in the oil and gas sector, mainly in the exploration and production of hydrocarbon fields.

Eni’s main permits are Bhit (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.25%), which in 2008 accounted for 90% of Eni’s production in Pakistan.

As part of the reserve development of the Bhit permit the operations of a third treatment unit started increasing the plant capacity by 46 mmCF/d and allowing the start-up of the satellite Badhra field. Other activities were targeted at optimizing production from the Kadanwari, Miano, Sawan and Zamzama fields by means of the drilling additional wells and upgrading the existing facilities.

Main discoveries for the year were made in: (a) the Mubarak Block (Eni’s interest 38%) with the Saquib gas discovery which was tested at a production rate of 2,472 KCF/d; and (b) the Latif exploration license, where the Latif-2 appraisal well has confirmed the hydrocarbon potential of the area.

Papua New Guinea. In 2008 Eni signed a Partnership Agreement with Papua New Guinea for the start of an exploration program aimed at identifying development opportunities and oil and gas projects. The agreement provides also for projects in electrical power generation and unconventional and renewable energy sources, which will foster sustainable development in this country.

Qatar. In 2008 Eni signed a Memorandum of Understanding with the state-owned company Qatar Petroleum International to target joint investment opportunities in the exploration and production of oil and gas. The agreement also envisages the development of joint projects in the petrochemical industry and power generation.

Russia. Eni has been present in Russia since 2007 following the acquisition of Lot 2 in the Yukos liquidation procedure. In particular, acquired assets included three Russian companies operating in the exploration and development of natural gas reserves: OAO Arctic Gas Co, ZAO Urengoil Inc and OAO Neftegaztechnologia. The three companies are managed by the OOO SeverEnergia subholding, owned by Eni (60%) and Enel (40%). Eni and Enel granted to Gazprom a call option on a 51% interest in OOO SeverEnergia. Terms of the call option are currently under review by Eni, Enel and Gazprom. Acquired companies are located in the Yamal Nenets region: (i) OAO Arctic Gas Co owns two exploration licenses, Sambugurskii and Yevo-Yahinskii including seven gas and condensates fields currently in the appraisal/development phase. Main fields are

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Sambugorskoye currently under development and Urengoiskoye. The final investment decision for both fields is expected in 2009 with production start-up in 2010; (ii) ZAO Urengoil Inc owns exploration and development licenses for the Yaro-Yakhinskoye gas and condensates field. Ongoing are representend by workovers of some existing wells and by new seismic acquisition; and (iii) OAO Neftegaztechnologia owns the exploration and development license of the Severo-Chasselskoye field where an acquisition of seismographic data is underway.

Other activities concern exploration in the Karalatskiy block (Eni’s interest 54%) in the Astrakhan region. This exploration license is part of the assets acquired from Burren Energy Plc.

Saudi Arabia. Eni entered Saudi Arabia in 2004 and is performing exploration activities in the so called C Area in order to discover and develop gas reserves. This license is located in the Rub Al Khali basin at the border with Qatar and the United Arab Emirates. The exploration plan provides for the drilling of 4 wells in five years. In case of a commercial discovery, the contract will last 25 years with a possible extension to a maximum of 40 years. Any gas discovered will be sold locally for power generation and as feedstock for petrochemical plants. Condensates will be sold on international markets.

Trinidad and Tobago. Eni has been present in Trinidad & Tobago since 1970. In 2008 Eni’s production averaged 55 mmCF/d. Activity is concentrated offshore north of Trinidad.

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

Production is provided by the Chaconia, Ixora and Hibiscus gas fields in the North Coast Marine Area 1 Block (Eni’s interest 17.4%). Production is supported by fixed platforms linked to the Hibiscus treatment facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant under long-term contracts. LNG production is sold in the United States, Spain and the Dominican Republic.

The main development project concerns the Poinsettia, Bougainvillea and Heliconia fields. The project provides for the installation of a production platform on Poinsettia and linked to the Hibiscus treatment facility, due to be upgraded. During the year drilling activity was started. Production start-up is expected in 2009.

United States. Eni has been present in the United States since 1966. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and more recently onshore and offshore Alaska.

In 2008 Eni’s oil and gas production deriving mainly from the Gulf of Mexico averaged 86 KBOE/d.

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

Eni holds interests in 412 exploration and production blocks in the Gulf of Mexico, 60% operated.

The main fields operated by Eni with a 100% interest are Allegheny, East Breaks and Morphet as well as Devils Towers, Triton and Goldfinger (Eni operator with a 75% interest). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%), and King Kong (Eni operator with a 56% interest) fields.

In March 2008, following an international bid procedure Eni was awarded 32 exploration blocks. The subsequent development phase will leverage synergies relating to the proximity of acquired acreage to existing operated facilities.

In August 2008, Eni was awarded 5 exploration licenses in the Keathley Canyon area, one of the main exploration areas in the Gulf of Mexico. The blocks will be 100% operated by Eni. The transaction is subject to authorization from relevant authorities.

In November 2008 Eni signed a cooperation agreement with the Colombian state company Ecopetrol for exploration assets in the Gulf of Mexico. Under the terms of this agreement, Ecopetrol will invest approximately $220 million to acquire a 20-25% interest in five exploration wells due to be drilled before 2012.

The development program of the Longhorn discovery (Eni’s interest 75%) was sanctioned. The project provides for the installation of a fixed platform linked to three underwater wells. Start-up is expected in 2009 with peak production at 29 KBOE/d (about 20 net to Eni).

Main discoveries for the year were made in the following blocks: (a) Block Mississippi Canyon 771 (Eni’s interest 25%) with the oil and gas Kodiak discovery close to the operated Devil’s Tower platform (Eni’s interest 75%); (b) Block Walker Ridge 508 (Eni’s interest 15%) the Stones-3 discovery well found oil. This discovery is part of the exploration assets acquired from Dominion Resources; (c) Block Mississippi Canyon 459 (Eni’s interest 100%) with the Appaloosa oil discovery. The final investment decision was reached at the end of 2008. Start-up is expected in 2010 with peak production at 7.5 KBBL/d; (d) Block Keathley Canyon 1008 (Eni’s interest 100%) with appraisal activities of the Hadrian oil discovery; and (e) Block offshore Green Canyon 859 (Eni’s interest 12.5%) with the oil and gas Heidelberg-1 discovery at a depth of 9,163 meters. Eni’s activities in Alaska are currently in the exploration and development phase in 158 blocks with interests ranging from 10 to 100%, over half as operator. In February 2008, following an international bid procedure Eni was awarded 18 offshore exploration blocks, 4 of which as operator, in the Chukchi Sea. The acquired acreage will strengthen Eni’s position in the area. The phased development plan of the Nikaitchuq field (Eni operator with a 100% interest) was sanctioned. Production is expected to start in 2010 with production plateau at 26 KBOE/d.

In June 2008, production started at the Oooguruk oil field (Eni’s interest 30%), in the Beaufort Sea, by linking to onshore facilities located on an artificial island. Peak production at 17 KBOE/d is expected in 2011.

In the medium-term, management expects to increase Eni’s production due to the development and integration of assets acquired and the start-up of fields in Alaska, targeting at approximately 110 KBOE/d in 2012.

Venezuela. Eni has been present in Venezuela since 1998. In 2008 Eni’s production averaged 5 KBBL/d. Activity is concentrated in the Gulf of Venezuela and in the Gulfo de Paira.

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Exploration and production 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 Venezuela State oil company PDVSA, preferably Corporación Venezuelana de Petróleo (CVP).

In February 2008, Eni and the Venezuelan Authorities reached a final settlement over the dispute regarding the expropriation of the Dación field which took place on April 1, 2006. Under the terms of the settlement, Eni will receive cash compensation in line with the carrying amount of the expropriated asset. Part of this cash compensation has been collected in the period. Eni believes this settlement represents an important step towards improving and strengthening cooperation with the PDVSA.

As part of improving cooperation with PDVSA, the two partners signed two agreements in September 2008: (i) a joint study agreement for the development of the Junin Block 5 located in the Orinoco oil belt, covering a gross acreage of 670 square kilometers. Once relevant studies have been performed and a development plan defined, a joint venture between PDVSA and Eni will be established to execute the project. Eni intends to contribute its experience and leading technology to the project in order to maximize the value of the heavy oil; and (ii) an agreement for the exploration of two offshore areas, Blanquilla and Tortuga in the Caribbean Sea, both with a 20% interest over an area of 5,000 square kilometers. The prospective development of these areas will take place through an integrated LNG project.

In 2008, production started at the Corocoro field (Eni’s interest 26%) in the Gulfo de Paira West Block. A second development phase is expected to be designed based on the results achieved in the first one regarding well production rate and field performance under water and gas injection. A production peak of 66 KBBL/d (17 net to Eni) is expected in 2012.

Eni holds an interest of 50% in the Cardon IV offshore exploration block, covering an area of 938 square kilometers.

Eni is participating with 19.5% interest in the Gulfo de Paira Centrale offshore exploration block, covering an area of 259 square kilometers, where the Punta Sur oil discovery is located.

 

Capital Expenditures

See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".

 

Storage

Natural gas storage activities are performed by Stoccaggi Gas Italia SpA (Stogit) to which such activity was conferred on October 31, 2001 by Eni SpA and Snam SpA, in compliance with Article 21 of Legislative Decree No. 164 of May 23, 2000, which provides for the separation of storage from other activities in the field of natural gas.

Storage services are provided by Stogit through eight storage fields located in Italy, based on ten storage concessions³ vested by the Ministry of Productive Activities.

In 2008, the share of storage capacity used by third parties was 61%. From the beginning of its operations, Stogit markedly increased the number of customers served and the share of revenues from third parties; the latter, from a non-significant value, passed to 50%.

Storage		2006		2007		2008

Available capacity:
- modulation and mineral		(BCM)		8.4		8.5		8.6
. share utilized by Eni		(%)		54		44		39
- strategic		(BCM)		5.1		5.1		5.1
Total customers		(No.)		38		44		48

Until 2008, results of the storage activities in Italy have been reported within the Exploration & Production segment. Following the 100% divestment of Stogit to Snam Rete Gas that was approved by Eni’s Board of Directors and is expected to close by mid 2009 (for details on this deal see "Significant Business and Portfolio Developments" above), from 2009 the results of the storage business conducted in Italy will be reported within the Gas & Power segment, under the "Regulated Business".

In 2008 operating profit reported by the natural gas storage business was euro 183 million down euro 83 million or 31.2% from 2007.

 

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Gas & Power

Eni’s Gas & Power segment engages in supply, transport, distribution, storage and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets.

Eni’s strategy in its Gas & Power segment is to grow international sales also leveraging on the Distrigas acquisition, preserve the profitability of Italian gas marketing operations, increase operational efficiency and effectiveness mainly in regulated businesses (i.e., Italian transport and distribution activities), and develop a global LNG business.

Eni has revised down its long-term expectations for gas demand growth due to the current economic downturn that is reducing gas consumption in all industrial segments and in power generation. In Europe, Eni expects gas demand to remain substantially stable during 2009 and to resume growing at an average annual rate of 2% in the following years till 2020, reaching an amount of 722 BCM. The main long-term driver of growth in European demand will be the wider use of gas in power generation. A growing portion of European gas requirements is expected to be satisfied by imports via pipeline. According to Eni’s estimates, European gas imports will cover at least 80% of consumption from the current level of 60%, due to domestic production decrease, stressing European dependence on producing countries. The most important pipeline supply sources will remain Russia and Algeria and, to a lesser degree, Norway and Libya. Eni expects that LNG supplies will contribute to diversify sources of supply.

In 2008, natural gas demand in Italy amounted to 84.88 BCM representing a small decline from 2007 due to the economic slowdown; approximately 90% of gas requirements were met through imports and 10% was covered by domestic production. The outlook for the Italian demand is more challenging as demand is expected to shrink in 2009 and to post a moderate recovery in subsequent years. Over the long-term, the Company expects Italian gas demand to increase at an average growth rate of approximately 2% through 2020, reaching an amount of 106.7 BCM in 2020 (gas volumes are projected at 94.2 BCM in 2012), driven by rising consumption in the power generation sector. Growing gas needs will be met by a projected increase in import capacity, which will be supported by significant capital expenditure projects designed to upgrade existing infrastructures and to build new ones, including new LNG terminals. The Company expects additional import capacity to supply up to 10 BCM in 2009 as Eni’s upgrades of its main TTPC and TAG pipelines from Algeria and Russia respectively reach full operations. In addition, Eni is completing another leg of expansion at the TAG pipeline and is planning to upgrade its pipeline from Libya. A competitor has commenced commissioning operations at a new LNG terminal in the Adriatic Sea. Overall the Company expects that import capacity will increase by 25 BCM by 2012 of which 90% available by 2010.

Against this backdrop, management plans to increase international natural gas sales leveraging on the integration of and expected synergies from the Distrigas acquisition as well as Eni’s competitive advantages ensured by gas availability under long-term supply contracts and equity gas, access to infrastructures, long-term relationships with key producing countries (mainly Russia, Algeria and Libya), market knowledge and a wide portfolio of clients. Eni intends to strengthen its positioning in European markets where its presence is already established – such as the Iberian Peninsula, Germany, France, the United Kingdom, Benelux and Turkey – and to develop its marketing activities internationally, particularly in the U.S. leveraging on the planned expansion of the Company’s LNG business.

In Italy, in an increasingly competitive market, Eni sales volumes are projected to decline from the 53 BCM level achieved in 2008 to approximately 50 BCM in 2012. The Company intends to preserve the profitability of its marketing operations by leveraging on cost controls and a number of marketing initiatives designed: (i) to focus the most profitable customer segments; (ii) to upgrade the commercial offer by tailoring pricing and services to customers’ specific needs; and (iii) to develop the combined offer of gas and power ("dual offer"). A strong focus will be devoted to reducing general and selling expenses.

In the medium-term, Eni plans to increase worldwide gas sales targeting a volume of 124 BCM by 2012, leveraging on expected growth in international sales that are projected to achieve an average annual rate of increase of 7% and upon synergies deriving from the Distrigas acquisition.

The matters regarding future natural gas demand and sales target discussed in this section and elsewhere here in 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.

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Supply of natural gas

In 2008 Eni’s consolidated subsidiaries, including Distrigas’ share amounting to 5.15 BCM, supplied 89.65 BCM of natural gas with a 5.85 BCM increase from 2007, up 7%. Excluding the contribution of Distrigas, gas volumes supplied outside Italy (76.50 BCM from consolidated companies), imported in Italy or sold outside Italy, represented 91% of total supplies with an increase of 1.35 BCM from 2007, or 1.8%, mainly due to the growth registered on European markets in particular in the first months of the year, with higher volumes purchased: (i) from Algeria via pipeline (up 1.07 BCM); (ii) from Libya (up 0.63 BCM) in line with the growth of gas equity production; and (iii) from the Netherlands (up 0.36 BCM); (iv) from Russia to Turkey (up 0.31 BCM) in line with the increased gas demand on the Turkish market. Supplies in Italy (8 BCM) declined by 0.65 BCM from 2007, or 7.5%, due to lower domestic production. Supplies of Russian gas for the Italian market declined by 0.97 BCM mainly due to the implementation of agreements with Gazprom providing for Gazprom’s entrance in the market of supplies to Italian importers and the corresponding reduction in Eni offtakes.

In 2008, main gas volumes from equity production derived from: (i) Italian gas fields (7.5 BCM); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2008 these two fields supplied 3.2 BCM net to Eni; (iii) certain Eni’s fields located in the British and Norwegian sections of the North Sea (2.3 BCM); and (iv) other European areas (in particular Croatia with 0.6 BCM). Considering also the direct sales of the Exploration & Production division in Europe and in the Gulf of Mexico and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 21 BCM representing 21% of total volumes available for sale.

In 2008, net input of natural gas volumes to storage deposits owned by Eni’s subsidiary Stoccaggi Gas were 0.08 BCM compared to volumes uplifted from storage of 1.49 BCM in 2007.

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

Natural gas supply		2006		2007		2008

Italy		10.21			8.65			8.00
Outside Italy		79.06			75.15			81.65
Russia		24.98			23.44			22.91
Algeria (including LNG)		20.42			18.41			19.22
Libya		7.70			9.24			9.87
the Netherlands		10.28			7.74			9.83
Norway		5.92			5.78			6.97
the United Kingdom		2.50			3.15			3.12
Hungary		3.28			2.87			2.84
Qatar (LNG)		-			-			0.71
Other supplies of natural gas		2.41			2.2			4.07
Other supplies of LNG		1.57			2.32			2.11
Total supplies of subsidiaries		89.27			83.80			89.65
Withdrawals from (input to) storage		(3.01	)		1.49			(0.08	)
Network losses and measurement differences		(0.50	)		(0.46	)		(0.25	)
Volumes available for sale of Eni's subsidiaries		85.76			84.83			89.32
Volumes available for sale of Eni's affiliates		7.65			8.74			8.91
E&P volumes		4.69			5.39			6.00
Total volumes available for sale		98.10			98.96			104.23

In order to meet the medium and long-term demand for natural gas, in particular in the Italian market, Eni entered into long-term purchase contracts with producing countries. The residual average life of the Company’s supply portfolio currently amounts to approximately 21 years. Such contracts, which generally contain take-or-pay clauses, will ensure a total of approximately 62.4 BCM/y of natural gas by 2010.

The finalization of the purchase of the Belgian company Distrigas (for details on this deal see "Significant Business and Portfolio Developments" above) has entailed significant expansion of Eni’s supply portfolio with an addition of long-term supplies of approximately 14.7 BCM (Norway, the Netherlands and Qatar) having a residual average life of about 14 years. Eni’s supply portfolio will be more diversified and less risky, as Eni will depend from one single supplier for about 20-22% of total projected supplies in 2012.

Despite the fact that an increasing portion of natural gas volumes is planned to be sold outside Italy, management believes that in the long-term unfavorable trends in the Italian natural gas demand and supply, also due to the increase in import capacity (pipeline upgrading and new LNG plants) that took place in 2008 and the

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finalization of projects in progress or publicly announced by Eni and third parties, as well as the evolution of Italian regulations in the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts. See "Item 3 – Risk Factors" and "Item 5 – Contractual Obligations".

In 2008, Eni purchases under its take-or-pay contracts were higher than its minimum uplift obligation. This amount relates mainly to a contractual year, rather than a calendar year (from October to end of September for a sizeable part of Eni Gas & Power long-term supply contracts).

 

Marketing

Natural Gas Sales for the Year 2008

In 2008, worldwide natural gas sales of 104.23 BCM, including own consumption, sales by affiliates and E&P sales in Europe and in the Gulf of Mexico, increased by 5.3% from 2007 mainly due to the organic growth recorded in the European markets (up 9%) and the contribution of the acquisition of Distrigas as well as higher seasonal sales recorded in the first quarter. These positives were partly offset by the lower performance of the Italian market (down 5.8%).

Natural gas sales in Italy were 52.87 BCM (including own consumption) and declined by 3.26 BCM from 2007, or 5.8%.

The Italian market includes large businesses, power generation users, wholesalers, middle-sized enterprises and service and residential customers; they are further grouped as follows: (i) large industrial clients and power generation utilities directly linked to the national and the regional natural gas transport networks; (ii) wholesalers, mainly local selling companies which resell natural gas to residential customers through low pressure distribution networks and distributors of natural gas for automotive use; and (iii) residential customers include households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and middle-sized enterprises (also referred to as the middle market) located in large metropolitan areas and urban centers. As of December 31, 2008, Eni clients amounted to 6.63 million units.

In 2008, the decline in sales on the Italian gas market was primarily due to wholesalers (down 2.49 BCM) and industrial customers (down 2.13 BCM) mainly reflecting the impact of lower gas demand and competitive pressures. The decrease was partly offset by higher supplies to the power generation sector (up 0.48 BCM) and higher seasonal sales to residential customers (up 0.43 BCM) due to colder weather in the first quarter. The decline in sales to wholesalers and industrial customers also reflects the increase in sales under the gas release programs (3.28 BCM, up 0.91 BCM from 2007). These sales related to certain proceedings settled between Eni and the Italian Antitrust Authority. In June 2004, Eni agreed with the Antitrust Authority to sell a total volume of 9.2 BCM of natural gas (2.3 BCM/y) in the four thermal years from October 1, 2004 to September 30, 2008 at the Tarvisio entry point into the Italian network. In March 2007 a new gas release program was signed for volumes amounting to 4 BCM of natural gas to sell in the two thermal years from October 1, 2007 to September 30, 2009 at a virtual exchange point in the Italian market.

Sales to importers in Italy (11.25 BCM) increased by 0.58 BCM, up 5.4%, as a larger portion of these sales in 2007 was replaced with direct sales in Italy.

Gas sales in European markets (31.78 BCM including affiliates and the contribution of Distrigas acquisition) increased by 7.43 BCM, or 30.5%, also reflecting market share gains. Excluding the impact of Distrigas, sales of natural gas on European markets amounted to 26.55 BCM, increasing by 2.20 BCM, or 9%, mainly due to the growth registered in: (i) France (up 0.64 BCM) due to marketing initiatives targeting wholesalers and industrial customers; (ii) the Iberian Peninsula (up 0.53 BCM) due to higher supplies to wholesalers and the power generation segment; (iii) Turkey (up 0.31 BCM), due to the progressive reaching of full operations of the Blue Stream pipeline; and (iv) Germany-Austria (up 0.20 BCM) due to higher sales to wholesalers. Sales to markets outside Europe (2.33 BCM) are substantially in line with 2007.

E&P sales in Europe and in the United States increased by 0.61 BCM, up 11.3%, as a result in particular of the production ramp-up in the Gulf of Mexico.

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

Natural gas sales by entities		2006		2007		2008

Total sales of subsidiaries		85.76		84.83		89.32
Italy		57.07		56.08		52.82
Rest of Europe		27.93		27.86		35.61
Outside Europe		0.76		0.89		0.89
Total sales of Eni's affiliates (Eni's share)		7.65		8.74		8.91
Italy		0.02		0.05		0.05
Rest of Europe		6.88		7.16		7.42
Outside Europe		0.75		1.53		1.44
Total sales of G&P		93.41		93.57		98.23
E&P in Europe and in the Gulf of Mexico (a)		4.69		5.39		6.00
Worldwide gas sales		98.10		98.96		104.23

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(a)

i

E&P sales include volumes marketed by the Exploration & Production division in Europe (4.07, 3.59, 3.36 BCM in 2006, 2007 and 2008, respectively) and in the Gulf of Mexico (0.62, 1.8 and 2.64 BCM in 2006, 2007 and 2008, respectively).

 

Natural gas sales by market		2006		2007		2008

ITALY		57.09		56.13		52.87
Wholesalers		11.54		10.01		7.52
Gas release		2.00		2.37		3.28
Italian gas exchange and spot markets		-		1.90		1.89
Industries		14.33		12.77		10.64
Industries		13.33		11.77		9.59
Medium-sized enterprises and services		1.00		1.00		1.05
Power generation		16.67		17.21		17.69
Residential		6.42		5.79		6.22
Own consumption		6.13		6.08		5.63
INTERNATIONAL SALES		41.01		42.83		51.36
Importers in Italy		14.10		10.67		11.25
European markets		20.71		24.35		31.78
Iberian Peninsula		5.24		6.91		7.44
Germany-Austria		4.72		5.03		5.29
Turkey		3.68		4.62		4.93
Belgium		-		-		4.57
Northern Europe		2.62		3.15		3.21
Hungary		3.10		2.74		2.82
France		1.07		1.62		2.66
Other		0.28		0.28		0.86
Extra European markets		1.51		2.42		2.33
E&P in Europe and in the Gulf of Mexico		4.69		5.39		6.00
WORLDWIDE GAS SALES		98.10		98.96		104.23

Planned Actions and Sales Target

In the medium-term, Eni plans to increase its sales volumes of natural gas in international markets, mainly in Europe and the U.S., in order to compensate for lower growth opportunities on its domestic market due to sector-specific regulation imposing limits to the size of Italian gas operators. In order to achieve its growth targets, Eni will leverage on its strengths represented by gas availability both as equity gas and under long-term purchase contracts, operational flexibility ensured by access to a large transport network, regasification terminals and logistic assets, a large portfolio of clients and market knowledge. Eni expects to increase international sales also leveraging on synergies deriving from the Distrigas acquisition that will help drive sales growth and markets share gains in Eni’s target markets in spite of an unfavorable short-term outlook for European gas demand.

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(i) Italy

In the medium-term, the Italian gas market will be characterized by greater competition related to the short-term decline in demand resulting from the economic slowdown and the entry on the market of new supplies related to the upgrade of import infrastructure. In particular import capacity is expected to increase by approximately 25 BCM in the next four years. About 90% of new capacity is expected to come on stream in 2010. This capacity derives in particular from the upgrades achieved by Eni on pipelines from Russia (TAG), Algeria (TTPC) and Libya (GreenStream) and the full operation of the re-gasification plant of Rovigo owned by third parties.

In order to support sales and profitability of its marketing operations in Italy, Eni intends to implement an effective marketing policy, intended to deliver value to customers leveraging on the quality of the service and the offer of customized price formulas. Eni’s marketing initiatives will focus on all segments in particular the middle and retail markets, also leveraging on the expected development of the combined offer of gas and power to residential customers ("dual offer"). Large industrial clients will be retained based on selective marketing policies targeting the most valuable and profitable. Volumes to thermoelectric utilities will be supported in order to maintain current levels.

At the same time, Eni expects to preserve its selling margins by means of reducing the cost to serve leveraging on technological innovation, streamlining front-end and back-end processes and achieving economies of scale and synergies, particularly those driving from the dual offer in terms of process integration for acquiring, retaining and managing customers.

As part of its marketing activities in Italy, Eni engages in the marketing of power. Particularly, the Company offers to its retail clients a commercial offer that provides the combined supply of gas and power ("the dual offer"). Eni plans to achieve by 2012 a penetration rate of over 20% of Eni’s retail customer base.

In 2008, sales of power amounted to 29.93 TWh and decreased by 3.26 TWh from 2007, down 9.8%, reflecting lower traded volumes as the economic activity declined in the last part of the year. The decrease mainly regarded sales to the power exchange. Sales on the free market to wholesalers increased due to higher spot sales, and so did sales to industrial users due to new customers acquired. Sales of power amounting to 29.93 TWh were directed to the free market (76%), the power exchange (13%), industrial sites (9%) and Electricity Service Operator (2%). In 2008, the program for expanding the combined integrated offer of gas and power (dual offer) progressed in accordance with the Company’s expansion plans.

		2006		2007		2008

Power generation		24.82		25.49		23.33
Trading of electricity		6.21		7.70		6.60
		31.03		33.19		29.93
Power sales by market
Free market		16.22		20.73		22.89
Italian Exchange for electricity		9.67		8.66		3.82
Industrial plants		2.70		2.81		2.71
Electricity Service operator (ESO)		2.44		0.99		0.51
		31.03		33.19		29.93

Power availability to Eni is ensured by internal production (see the generation business below) and purchases on the free market. In 2008, production availability covered 78% of sales volumes.

 

(ii) European Markets

In the future, Eni intends to strengthen its leadership in the European gas markets, targeting to increase both volumes and market shares. A review of Eni’s presence in key European markets and volume targets for 2012 is presented below.

Benelux. The acquisition of Distrigas finalized in October 2008 granted Eni a solid base from which to develop its presence in Benelux countries (Belgium, the Netherlands and Luxembourg). Distrigas is a key operator in Benelux, in particular in Belgium, the strategic hub of the continental European gas market thanks to its central position and high level of interconnectivity with the transit gas networks of central and northern Europe. The company sells natural gas mainly to industries, wholesalers and power generation. Distrigas also has diversified sources of supply, both in geographical terms with its long-term supply contracts portfolio in the Netherlands, Norway and Qatar, and technically as it purchases natural gas, transports it via pipeline and as LNG. It also owns an

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11% interest in Interconnector UK Ltd, the company that owns the interconnection of the transit gas networks between Belgium and the UK and the Methania gas tanker ship. Its transport assets connect natural gas sources with European markets and the Zeebrugge hub on the Belgian coast.

In 2008 Distrigas natural gas sales in Benelux amounted to approximately 13.5 BCM and by 2012 Eni targets sales of 14.8 BCM, an annual average growth rate of 2% and a 22% market share.

France. Eni sells natural gas to industrial clients and resellers and to the segments of small businesses and retail though its partnership with Altergaz in which it holds a 38.91% stake. Altergaz supplies approximately 23,000 clients (of these 17,000 are residential customers), with revenues of approximately euro 260 million. Eni will support Altergaz’s development in the target segments through a 10-year supply contract of 1.3 BCM/y and will pursue synergies with its own commercial structure. On September 23, 2008, Eni and Altergaz acquired a 17% stake each in the share capital of Gaz de Bordeaux SAS, a gas distributor in the municipality of Bordeaux and defined the terms of a long-term supply contract for 250 mmCM/y to Gaz de Bordeaux.

In addition, the recent acquisition of Distrigas provides Eni with a customer base and sound commercial structures.

The retail segment in France presents attractive development opportunities with its 10.8 million of sites and delivery points and consumption equaling 27% of total national consumption.

Eni expects to ramp sales on the French market to achieve 6.8 BCM of sales by 2012. This target represents an annual average growth rate of 14%. Eni’s market share is expected to reach 13%.

Germany/Austria. Eni is present on the German natural gas market through its affiliate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.22 BCM in 2008 (2.11 BCM being Eni’s share) and through a direct marketing structure (Eni G&P GmbH). In the medium-term, Eni, supported by the synergies achieved with GVS, plans to significantly increase its sales to the local distribution companies and industrial segment, leveraging on the pursuit of opportunities arising from the ongoing liberalization process. The objective is to sell 7.6 BCM in 2012, equal to a 7% market share with an annual growth rate of 9%.

Iberian Peninsula
Portugal. Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%) which sold approximately 5.78 BCM in 2008 (1.93 BCM being Eni’s share).

Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets in particular LNG from Nigeria and through Unión Fenosa Gas (UFG) (Eni’s interest 50%) which supplies natural gas mainly to final customers and power generation utilities. In 2008 gas sales of UFG in Europe amounted to 4.32 BCM (2.16 BCM Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) regasification plants, with a 42.5% and 18.9% interest, respectively.

Eni targets to increase its sales in the Iberian Peninsula from the current 7.44 BCM level to approximately 8.6 BCM by 2012, with an annual average growth rate of 4%, in line with the growth of the Spanish market.

UK/Northern Europe. Eni through its subsidiary North Sea Gas & Power (Eni UK Ltd) markets equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). Eni plans to grow volumes sold on the markets of the UK/ Northern Europe from the current 3.2 BCM level to approximately 6.8 BCM by 2012, with a 21% average annual growth rate.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2008 sales amounted to 4.93 BCM. Leveraging on the expected demand growth, Eni plans to increase sales up to 6.4 BCM by 2012, equal to a 7% growth rate.

 

(iii) The United States

Eni’s plans to expand its natural gas sales in the U.S. are described under the "LNG business" below.

 

The LNG Business

Eni is present in the all phases of LNG: liquefaction, shipping, regasification and sale, and intends to speed up the development of its LNG business on a global scale, aiming at building or acquiring assets in the LNG value chain in order to seize the opportunities arising from the increasing role of LNG in satisfying energy requirements.

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Expansion of LNG business in particular on extra European markets, mainly in the USA, will enable Eni to fully monetize its large equity reserves.

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

Italy. Eni, through Snam Rete Gas, operates the only regasification terminal operating in Italy at Panigaglia (Liguria). At full capacity, this terminal can regasify 17,500 CM of LNG per day and input 3.5 BCM/y into the Italian transport network. Eni plans to increase the capacity of the Panigaglia plant from the current 3.5 BCM to 8 BCM. From 2014 the upgrade of this structure will allow to increase imports to Italy by 4.5 BCM/y. In accordance with Management’s revised plans, works are expected to commence by 2011, if all authorizations are granted.

Qatar. The closing of the acquisition of Distrigas allowed Eni to increase its development opportunities in the LNG business with the access to new supply sources mainly from Qatar, under a 20-year long agreement with RasGas (owned by Qatar Petroleum with a 70% interest and ExxonMobil with a 30% interest) and to the Zeebrugge LNG terminal on the Western coast of Belgium. In 2008 the terminal was authorized to load gas carriers, allowing Distrigas to start its LNG export activity to very profitable markets.

Egypt. Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant producing approximately 5 mmtonnes/y of LNG equal to a feedstock of 7 BCM/y of natural gas. In 2008, the Gas & Power segment withdrew 0.7 mmtonnes of LNG (approximately 1 BCM of natural gas) to be marketed in Europe.

Spain. Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto regasification plant, near Valencia, with a capacity of 6.7 BCM/y. At present, Eni’s capacity entitlement amounts to 1.6 BCM/y of gas. A capacity upgrading plan has been sanctioned targeting a 0.8 BCM/y capacity increase by 2009. Eni through Unión Fenosa Gas also holds a 9.5% interest in the El Ferrol regasification plant, located in Galicia, which started operations in November 2007, with a treatment capacity of approximately 3.6 BCM/y, 0.4 BCM/y being Eni’s capacity entitlements.

USA
Cameron. Eni acquired from the U.S. company Sempra a capacity entitlement in the Cameron regasification plant, under construction on the banks of the Calcasieu River, approximately 15 miles south of Lake Charles in Louisiana. Eni’s capacity entitlement amounts to 6.5 BCM/y, equal to a 40% share of the total plant capacity for a duration of 20 years. The validity of the contract is conditional upon the actual start-up of the regasification service, expected by end of 2009. This transaction will allow Eni to market the natural gas reserves that it is developing in North Africa and Nigeria on the North American market.

Pascagoula. Within the upstream project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes/y of LNG (approximately 7.3 BCM/y) for the North American market, Eni has an option to purchase a capacity entitlement amounting to 5.8 BCM/y for 20 years at the regasification plant that will be built near Pascagoula in Mississippi, with start up expected by end of 2011.

With the contribution of the Distrigas acquisition and of sales of the E&P segment, by 2012 Eni targets sales of LNG of about 17 BCM (12 BCM in 2008).

LNG sales		2006		2007		2008

G&P sales		6.4		8.0		8.4
Italy		1.5		1.2		0.3
European markets		4.4		5.6		7.0
Extra european markets		0.5		1.2		1.1
E&P sales		3.5		3.7		3.6
Liquefaction plants:
Bontang (Indonesia)		0.9		0.7		0.7
Point Fortin (Trinidad & Tobago)		0.4		0.6		0.5
Bonny (Nigeria)		1.8		2.0		2.0
Darwin (Australia)		0.4		0.4		0.4
		9.9		11.7		12.0

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Power Generation

Eni conducts its power generation activities at its sites of Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi and Ferrara. In 2008 production of power amounted to 23.33 TWh, down 2.16 TWh from 2007, or 8.5% due mainly to a decline in sales volumes. Total installed capacity was 4.9 GW at December 31, 2008. Sales of steam (10,584 ktonnes) in 2008 decreased by 265 ktonnes from 2007, down 2.4% and were directed to end customers.

In the medium-term Eni intends to complete its plan for expanding power generation capacity, targeting an installed capacity of 5.5 GW. At full capacity in 2012, production is expected to amount to approximately 29 TWh, corresponding to approximately 8% of power expected to be generated in Italy at that date. This expansion will allow Eni to consolidate its market share and its position as third power producer in Italy. Supplies of natural gas are expected to amount to approximately 5.6 BCM/y from Eni’s diversified supply portfolio. Residual expected capital expenditure amount to euro 0.7 billion in addition to the euro 2.4 billion already invested until 2008. The development plan is underway at Ferrara (Eni’s interest 51%), where in partnership with EGL Holding Luxembourg (a company belonging to Swiss group EGL) construction of two new 390 MW combined cycle units is currently undergoing testing and the relevant authorizations are pending with start up expected in early 2009.

New installed generation capacity uses the combined cycle gas fired technology (CCGT), 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, the use of the CCGT technology on a production of 26.5 TWh reduces emissions of carbon dioxide by approximately 5 mmtonnes, as compared to emissions using conventional power generation technology. The CCGT technology has been acknowledged by the Authority for Electricity and Gas as a production technology that entails priority on the national dispatching network and the exemption from the purchase of "green certificates". Article 11 of Legislative Decree No. 79/1999 concerning the opening up of the Italian electricity market obliges importers and producers of power from non renewable sources to input into the national power system a share of power produced from renewable sources set at 2% of power imported or produced from non renewable sources exceeding 100 GW. Calculations are made on total amounts net of co-generation and own consumption. This obligation can be met also by purchasing volumes or rights from other producers employing renewable sources (the so-called green certificates) to cover all or part of such 2% share. Legislative Decree No. 387/2003 established that from 2004 to 2006 the minimum amount of power from renewable sources to be input in the grid in the following year be increased by 0.35% per year. The Minister of Productive Activities, with decrees issued in consent with the Minister of the Environment, will define further increases for the 2007-2009 and 2010-2012 periods.

Eni’s operated power plants are described below.

Ferrera Erbognone. This power plant has an installed capacity of approximately 1,030 MW divided on three combined cycle units, two of them with an approximately 390 MW capacity are fired with natural gas, the third one with approximately 250 MW capacity is fired whit a mixed fuel, natural gas and refinery gas obtained from the gasification of a heavy residue form crude processing at the nearby Eni-operated Sannazzaro refinery.

Ravenna. Two new combined cycle 390 MW units started operations in 2004. Added to the existing capacity, the power plant’s installed capacity has reached approximately 1,100 MW.

Brindisi. This power plant has been upgraded by installing three new combined cycle units, each with capacity of 390 MW, increasing overall capacity at approximately 1,500 MW.

Mantova. This power plant has been upgraded by installing two new combined cycle units, each with capacity of 390 MW, increasing overall capacity at approximately 900 MW. This power plant also provides steam for heating purposes delivered to the Mantova’s urban network through a heat exchanger.

Livorno. This power plant has an installed capacity of approximately 200 MW, divided on gas and steam turbines with steam generators.

Taranto. The existing power units have a capacity of approximately 75 MW, divided on gas and steam turbines with steam generators.

Ferrara. Two new combined cycle 390 MW units started operations in 2008. Added to already existing gas and steam turbines, the power plant’s installed capacity has reached approximately 840 MW.

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Power Generation		2006		2007		2008

Purchases
Natural gas		(mmCM)		4,775		4,860		4,530
Other fuels		(ktoe)		616		720		560
- of which steam cracking				136		137		131
Production
Electricity		(TWh)		24.82		25.49		23.33
Steam		(ktonnes)		10,287		10,849		10,584
Installed generation capacity		(GW)		4.9		4.9		4.9

 

Infrastructures

Eni operates a large European network of integrated infrastructure for transporting natural gas, which links key consumption basins with the main producing areas (North Africa, Russia and the North Sea).

In Italy Eni operates almost all the national transport network and can count on an extended system of local distribution networks serving retail markets. The availability of regasification capacity in Italy and the Iberian Peninsula coupled with a significant storage capacity ensures a high level of operating flexibility. These assets represent a significant competitive advantage. Eni is implementing plans for upgrading its import pipelines from Russia, Algeria and Libya and its storage capacity, and for expanding and modernizing its national transport and distribution networks. The Company plans to invest approximately euro 7 billion in the next four years in these businesses to cope with long-term growth expected in the European gas demand.

Transport infrastructure
Route		Lines		Length of main line		Diameter		Transport capacity (1)		Pressure min-max		Compression stations
ITALY		(units)		(km)		(inch)		(mmCM/d)		(bar)		(No.)
Mazara del Vallo-Minerbio (under upgrading)		2/3		1,480		48/42 - 48		101.8		75		7
Tarvisio-Sergnano-Minerbio		3		433		42/36, 34 e 48/56		106.0		58/75		3
Passo Gries-Mortara		2		177		48/34		64.9		55/75		1
		Lines		Total length		Diameter		Transport capacity (2)		Transit capacity (3)		Compression stations
OUTSIDE ITALY		(units)		(km)		(inch)		(BCM/y)		(BCM/y)		(No.)
TENP (Bocholtz-Wallbach)		2 lines of km 500		1,000		36/38/40		22.9		15.5		4
Transitgas (Rodersdorf-Lostorf)		3 lines of km 165, 71 and 55		291		36/48		24.9		19.9		1
TAG (Baumgarten-Tarvisio)		3 lines of km 380		1,140		36/38/40/42		45.2		37.4		5
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		33.2		33.2
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	Transport capacity refers to the capacity at the entry point connected to the import pipelines.
(2)	i	Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(3)	i	The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.

 

International Transport Activities

In order to import natural gas to Italy, Eni owns capacity entitlements in a network of international high pressure pipelines extending for a total of over 4,400 kilometers enabling the Company to import natural gas produced in Russia, Algeria, the North Sea and Libya to Italy. A description of the main pipelines is provided below.

•

The TAG pipeline, 1,140-kilometer long, made up of three lines, each about 380-kilometer long, with a transport capacity of 37 BCM/y, and three compression stations. This pipeline transports Russian natural gas from Baumgarten, the delivery point at the border of Austria and Slovakia, to Tarvisio, point of entry in the Italian natural gas transport system. This facility is undergoing an upgrade project entailing the construction of two new compression stations in order to increase the transport capacity by 6.5 BCM/y. A first portion of 3.2 BCM/y has started operating in October 2008. The second portion of 3.3 BCM/y is

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		expected to start operating in the fourth quarter of 2009. In 2008 the whole new capacity has been awarded to third parties following a transparent and non discriminatory procedure (lottery) agreed with Austrian and European Authorities.
•		The TTPC pipeline, 740-kilometer long, made up of two lines 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. In 2008 the transport capacity of this facility has been increased by 6.5 BCM/y. A first portion of 3.2 BCM/y came on line on April 1, 2008, while the second portion of 3.3 BCM/y started operations in October 2008. The whole new capacity has been awarded to third parties.
•		The TMPC pipeline for the import of Algerian gas, 775-kilometer long, made up of five lines each 155-kilometer long with a transport capacity of 33.5 BCM/y. It crosses underwater the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.
•		The TENP pipeline, 1,000-kilometer long (two 500-kilometer long lines) with transport capacity of 15.5 BCM/y and four compression stations. It transports natural gas from the Netherlands through Germany, from the German-Dutch border of Bocholtz to Wallbach at the German-Swiss border.
•		The Transitgas pipeline, 291-kilometer long, with one compression station, that transports natural gas from the Netherlands and from Norway crossing Switzerland with its 165-kilometer long main line and a 71-kilometer long doubling line, from Wallbach where it joins the TENP pipeline to Passo Gries at the Italian border. It has a transport capacity of 20 BCM/y. A new 55-kilometer long line from Rodersdorf at the French-Swiss border to Lostorf, an interconnection point with the line coming from Wallbach, was built for the transport of Norwegian gas. Eni is assessing an upgrade of the capacity of this pipeline of 2 BCM/y. The final investment decision is subject to the approval of relevant authorities.
•		The GreenStream pipeline that started operations in October 2004 for the import of Libyan gas produced in Eni operated fields at Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 BCM/y and crosses underwater 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 plans to upgrade the transport capacity of this pipeline by additional 3 BCM/y to 11 BCM/y with completion expected in 2012.

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.

The South Stream project

Eni and Gazprom are assessing a project to build a new route for importing gas from Russia to Europe through the Black Sea. The South Stream pipeline is expected to be composed by two sections: (i) an offshore 900-kilometer long section crossing the Black Sea from the Russian coast at Beregovaya (the same starting point of the Blue Stream pipeline) to the Bulgarian coast at Varna. It will be laid reaching water depths of more than 2,000 meters; and (ii) an onshore section for which two options are currently being evaluated: one envisages crossing Serbia and Hungary to connect to existing trunklines from Russia; another section pointing South West crossing Greece and Albania then linking to the Italian network. Eni and Gazprom will carry out the project using the most advanced technologies in full respect of the strictest environmental criteria.

 

Regulated businesses in Italy

Italian Transport Activity

Eni, through Snam Rete Gas, a company listed on the Italian Stock Exchange, in which Eni holds a 50.03% interest, operates most of the Italian natural gas transport network as well as the only regasification terminal currently operating in Italy.

Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, transport and regasification activities are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This makes transport a low risk business capable of delivering stable returns.

Eni’s network extends for 31,474 kilometers and comprises: (i) a national transport network extending over 8,779 kilometers, made up of high pressure trunk-lines mainly with a large diameter, which carry natural gas from the entry points to the system – import lines, storage sites and main Italian natural gas fields – to the linking points with regional transport networks. The national network includes also some interregional lines reaching important markets; and (ii) a regional transport network extending over 22,695 kilometers, made up of smaller lines and allowing the transport of natural gas to large industrial complexes, power stations and local distribution companies in the various local areas served. The major pipelines interconnected with import trunk-lines that are part of Eni’s national network are:

•

for natural gas imported from Algeria (Mazara del Vallo delivery point):

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-

two lines with a 48/42-inch diameter, each approximately 1,500-kilometer long, including the smaller pipes that cross underwater the Messina Strait, connect Mazara del Vallo on the Southern coast of Sicily where they link with the TMPC pipeline carrying Algerian gas, to Minerbio (near Bologna). This pipeline is undergoing an upgrade with the laying of a third line with a 48-inch diameter 528-kilometer long (of these 309 are already operating). At the Mazara del Vallo entry point the available transport capacity, which is measured at the beginning of each thermal year starting on October 1, is approximately 102 mmCM/d;

•

for natural gas imported from Libya (Gela delivery point):

-

a 36-inch line, 67-kilometer long linking Gela, the entry point of the GreenStream underwater pipeline, to the national network near Enna along the trunkline transporting gas coming from Algeria. Transport capacity at the Gela entry point is approximately 31 mmCM/d;

•

for natural gas imported from Russia (Tarvisio and Gorizia delivery points):

-

two lines with 42/36/34-inch diameters extending for a total length of approximately 900 kilometers connect the Austrian network at Tarvisio. This facility crosses the Po Valley reaching Sergnano (near Cremona) and Minerbio. This pipeline has been upgraded by the laying of a third 264-kilometer long line with diameter from 48 to 56 inches. The pipeline transport capacity at the Tarvisio entry point amounts to approximately 106 mmCM/d plus the transport capacity available at the Gorizia entry point of approximately 5 mmCM/d;

•

for natural gas imported from the Netherlands and Norway (Passo Gries delivery point):

-

one line, with a 48-inch diameter, 177-kilometer long extends from the Italian border at Passo Gries (Verbania), to the node of Mortara, in the Po Valley. The pipeline transport capacity at the Passo Gries entry point amounts to 65 mmCM/d;

•

for natural gas coming from the Panigaglia LNG terminal:

-

one line, with a 30-inch diameter, 170-kilometer long links the Panigaglia terminal to the national transport network near Parma. The pipeline transport capacity at the Panigaglia entry point amounts to 13 mmCM/d;

•

for natural gas coming from the Rovigo Adriatic LNG terminal:

-

a 36-inch connection at the Minerbio junction with the Cavarzere-Minerbio pipeline belonging to Edison Stoccaggio SpA, which will receive gas from the LNG terminal located offshore of Porto Viro, once in operation.

In 2008, Eni’s national transport network increased by 393 kilometers due to certain upgrades to both national trunklines (231 kilometers) and the regional network (162 kilometers). Eni’s system is completed by: (i) 11 compressor stations with a total power of 830 MW used to increase gas pressure in pipelines to the level required for its flow; and (ii) 5 marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo, Messina and Gela in Sicily and Favazzina and Palmi in Calabria. The interconnections managed by Snam Rete Gas in the Italian transport network are guaranteed by 23 linkage and dispatching nodes and by 569 plant units including pressure reduction and regulation plants. These plants allow to regulate the flow of natural gas in the network and guarantee the connection of pipes working at different pressures.

Snam Rete Gas is currently assessing a project to build the Italian section of the new Galsi pipeline connecting Algeria to Italy through Sardinia with an 8 BCM/y capacity. The Italian section of this new infrastructure will be consist of an onshore section crossing Sardinia and an offshore section reaching Tuscany where it will link with the national network for a total length of 600 kilometers. Galsi will be responsible for project engineering and obtaining needed licenses and authorizations, while Snam Rete Gas will build the pipeline and manage it when operational.

For the next four years Snam Rete Gas approved a capital expenditure plan of approximately euro 4.3 billion aimed mainly at increasing transport capacity by 25% and upgrading the network in view of increasing import flows.

In 2008, volumes of natural gas input in the national grid (85.64 BCM) increased by 2.36 BCM from 2007, up 2.8%, mainly due to higher volumes of natural gas input to storage for the rebuilding of stocks in summer months as a result of higher offtakes related to higher seasonal sales registered in the first months of the year. Eni transported 33.84 BCM of natural gas on behalf of third parties, up 2.95 BCM from 2007, or 9.6%.

Gas volumes transported (a)		2006		2007		2008

Eni		57.09		52.39		51.80
On behalf of third parties		30.90		30.89		33.84
		87.99		83.28		85.64

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(a)

i

Includes amounts destined to domestic storage.

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Transport capacity in Italy		2007-2008 Thermal year		2008-2009 Thermal year

Entry points		Available capacity		Awarded capacity		Saturation		Available capacity		Awarded capacity		Saturation
		(mmCM/d)		(mmCM/d)		(%)		(mmCM/d)		(mmCM/d)		(%)
Tarvisio		112.6		92.2		81.9		106.0		97.8		92.2
Mazara del Vallo		90.7		80.4		88.7		101.8		93.2		91.6
Passo Gries		63.5		59.6		93.8		64.9		60.8		93.7
Gela		30.3		29.5		97.3		30.5		30.5		100.0
GNL Panigaglia		13.0		11.4		87.7		13.0		11.4		87.7
Gorizia		4.8		0.5		9.4		4.8
		314.9		273.6		86.9		321.0		293.7		91.5

In 2008, the LNG terminal in Panigaglia (La Spezia) regasified 1.52 BCM of natural gas (2.38 BCM in 2007).

 

Distribution Activity

Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. Eni, through its 100% subsidiary Italgas and other subsidiaries, operates in the distribution activity in Italy serving 1,320 municipalities through a low pressure network consisting of approximately 49,400 kilometers of pipelines supplying 5.6 million customers and distributing 7.3 BCM in 2008. Under Legislative Decree No. 164/2000 on the opening up of the natural gas market in Italy, distribution activities are considered a public service and therefore are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This business, therefore, presents a low risk and a steady cash generation profile.

Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. According to Legislative Decree No. 164/2000, the award of the service has to take place by competitive bid from the end of a transition period no later than December 31, 2012. Future concessions will last no more than twelve years. Eni intends to develop its market and improve efficiency and quality of services rendered.

Distribution activity in Italy		2006		2007		2008

Volumes distributed		(BCM)		7.54		7.44		7.63
- on behalf of Eni				6.90		6.39		6.33
- on behalf of third parties				0.64		1.05		1.30
Installed network		(km)		48,724		48,746		49,410
Active meters		(No. of users)		5,550,700		5,598,677		5,676,056
Municipalities served		(No.)		1,317		1,318		1,320

For the next four years Eni defined a capital expenditures plan of approximately euro 1 billion for the development/upgrade of its distribution networks and their technological upgrade.

 

Storage

Following the 100% divestment of Stogit to Snam Rete Gas that was approved by Eni’s Board of Directors and is expected to close by mid 2009 (for details on this deal see "Significant Business and Portfolio Developments" above), from 2009 the results of the storage business conducted in Italy described in the Exploration & Production section will be reported within the Gas & Power segment, under the "Regulated Business". The storage gas business in Italy is a fully-regulated activity which returns are preset by the Italian Authority for Electricity and Gas. Italian regulated storage services are provided through eight storage fields, with a modulation capacity of 8.6 BCM.

In addition to storage activities conducted in Italy, Eni, through its Gas & Power segment, engages in certain gas storage activities in Europe. Particularly, the Company is developing a storage facility in the UK section of the North Sea following the acquisition of the Hewett Unit where certain depleted fields will be converted to gas storage deposits (for further detailed information see "Item 4 – Exploration & Production" above). The expected capital expenditure program for this project amounts to euro 0.7 billion with expected start-up in 2011. The storage capacity

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will be located to complement Eni’s production, sales and trading activities in Europe and will further enhance the flexibility of Eni’s portfolio in serving the main markets. Eni considers the development of gas storage facilities as a core element of the gas business. Gas storage capacity provides flexibility to match gas demand in peak periods, thereby contributing to the optimization of the gas supply portfolio. The activity of gas storage in the UK is de-regulated and results from this project will be reported within the "Marketing business".

 

Capital Expenditures

See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".

 

Refining & Marketing

Eni’s Refining & Marketing segment engages in refining of crude oil and marketing of refined products in Italy and in a number of European markets. Based on public data, Eni is the main operator in the markets for refining and marketing of refined products in Italy. Eni’s refining and marketing operations are efficiently integrated and supported by a full set of logistic assets. Refining know-how, strong market acceptance of the brand, the ability to develop innovative fuels, and the integration with upstream operations represent Eni’s principal competitive advantages. Eni’s key medium-term target is to enhance the profitability of its downstream oil business and to reduce the cash requirements of the business by applying tight financial discipline on capital expenditures.

The strategic guidelines to attain this target are:

•

to upgrade Eni’s refining system through a focused capital program;

•		to improve profitability and qualitative standards of the Italian retail network; and
•		to pursue higher levels of operational efficiency.

In the next four years the implementation of these strategies will be supported by a capital expenditure program of approximately euro 2.8 billion that will be directed to upgrade Eni’s most efficient and profitable refineries and improve the quality standards of Eni’s retail operations, in particular in Italy, expanding activities for the supply of non oil products and developing the market share in selected European markets. Efficiency improvement actions will be directed to all activities targeting control of operating costs and improvement of energy efficiency.

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

 

Supply and Trading

In 2008, a total of 57.91 mmtonnes of crude were purchased by the Company’s Refining & Marketing segment (59.56 mmtonnes in 2007), of which 29.71 mmtonnes from Eni’s Exploration & Production segment. Volumes amounting to 16.11 mmtonnes were purchased under long-term supply contracts with producing countries, while 12.09 mmtonnes were purchased on the spot market. Approximately 29% of crude purchased in 2008 came from West Africa, 19% from European and Asian Russia, 29% from North Africa, 14% from the Middle East, 14% from the North Sea and 6% from Italy.

Approximately 26 mmtonnes of crude purchased in 2008 were resold, up 0.7% from 2007. In addition, 3.39 mmtonnes of intermediate products were purchased (3.59 mmtonnes in 2007) to be used as feedstock in conversion plants and 17.42 mmtonnes of refined products (16.14 mmtonnes in 2007) were purchased to complement production availability.

 

Refining

Eni’s refining system has total refinery capacity (balanced with conversion capacity) of approximately 36.8 mmtonnes (equal to 737 KBBL/d) and a conversion index of 57.6%. The conversion index is a measure of a refinery complexity. The higher the index, the wider is the spectrum of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies associated with the fact that certain qualities of crude (particularly the heavy ones) trade at discount with reference to the light crude benchmark Brent. Eni’s five 100-percent owned refineries have balanced capacity of 27.2 mmtonnes (equal to 544 KBBL/d), with a 60.3% conversion rate. In 2008, refinery throughputs in Italy and outside Italy were 35.84 mmtonnes.

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In the next four years, Eni plans to selectively upgrade its refining system by increasing complexity and flexibility of plants, using Eni’s proprietary EST technology and achieving a conversion index of 65% in Europe (71% in Italy). The completion of construction of three new hydrocrackers at Sannazzaro, Taranto and Bayernoil is scheduled in 2009. Middle distillate yields are expected to come in at 45% from 40% in 2008 (more than double of gasoline yields) and equity crude volumes processed to increase from 19.0% to 19.6%. Improvement in operations as result of investment upgrading and efficiency actions targeting operating costs are expected to enable refining operations to lower the break-even level with respect to 2008. This means that in the medium-term our refineries will achieve positive results in a lower refining margin scenario compared to 2008. Management’s projections about the break-even level also take into account the operating expenses required to comply with environmental rules on the emissions of carbon dioxide (CO₂) which amounted to approximately euro 17 million in 2008 as the business emissions are higher than the entitled allowance based on the criteria of Law Decree No. 216/2006 which implemented in Italy the EU Directive on Emission Trading (see below under the section Environmental Regulation). Management expects that the Refining & Marketing business will incur a level of operating expenses similar to 2008 in the next four-years to comply with the outlined environmental regulation.

In the next four-years period, Eni’s investment plans are designed to take advantage of certain expected market trends in the refining industry:

(i)		a significant reduction in European demand for gasoline, despite the diffusion of new gasoline fuelled engines with efficiency levels in consumption comparable to those of diesel fuel, is expected in the medium-term, while consumption of diesel fuel is expected to grow driven by the continuing renewal of the car fleet;
(ii)		a slowdown in the demand for gasoline on the U.S. market is expected, reflecting the negative economic scenario, the diffusion of more energy efficient car models and the increasingly widespread use of bio-fuels;
(iii)		implementation of increasingly tight environmental regulations in Europe will require significant capital expenditures for refinery upgrading;

(iv)

demand for fuel oil is expected to decrease due to increasingly strong competition from natural gas in firing power plants; and

(v)

opportunities will arise to monetize heavy crudes and non conventional resources by applying advanced refinery technologies.

Eni’s refinery capital projects will be designed to: (i) increase plant conversion capacity in view of boosting middle distillate yields and extracting value from equity crude; (ii) improve refinery flexibility in order to optimize processed feedstock and capture market opportunities arising from an expected increased availability of heavy/sour crudes that are typically discounted in the marketplace; (iii) produce fuels in line with product specifications provided for increasingly tight European environmental standards; and (iv) enhance operational efficiency of refineries, including energy efficiency gains.

The table below sets forth certain statistics regarding Eni’s refineries at December 31, 2008.

Refining system in 2008

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		544		60.3		69		22		37		29		89		47		82		94
Italy
Sannazzaro		100		223		223		170		50.9		34						29		29				73		99
Gela		100		129		129		100		144.8		35				37						47		82		101
Taranto		100		120		120		110		64.6				22						38				97		79
Livorno		100		106		106		84		11.4														88		102
Porto Marghera		100		107		107		80		20.2										22				79		86
Partially owned refineries (3)				874		245		193		49.7		163		25				99		27				77		98
Italy
Milazzo		50		248		124		80		73.0		41		25				32						68		99
Germany
Ingolstadt/Vohburg/      Neustadt (Bayernoil)		20		215		43		41		34.0		49						43						93		95
Schwedt		8.33		231		19		19		41.8		49								27				98		102
Czech Republic
Kralupy e Litvinov      (Ceska Rafinerska)		32.4		180		59		53		29.6		24						24						86		80
Total refineries				1,559		930		737		57.6		232		47		37		128		116		47		81		95

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(1)	i	Stated in fluid catalytic cracking equivalent/topping (% by weight), based on 100% of balanced primary distillation capacity.
(2)	i	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)	i	Capacity of conversion plant is 100%.

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Italy

Eni’s refining system in Italy is composed of five 100-percent owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy has operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic positioning with respect to end markets and the integration with Eni’s other activities.

The Sannazzaro refinery has balanced refining capacity of 170 KBBL/d and a conversion index of 50.9%. It is one of the most efficient refineries in Europe. Located in the Po Valley, it supplies mainly markets in North-Western Italy and Switzerland. The high degree of flexibility 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 Genova 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), a mild hydrocracker (HdCK) middle distillate conversion unit and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syngas to feed the nearby EniPower power plant at Ferrera Erbognone. A significant conversion capacity and flexibility upgrading program is ongoing in order to transform it in a world class plant. In particular, a new hydrocracking unit with a processing capacity of 28 KBBL/d is under construction with expected start-up in 2009. In addition Eni plans to develop a conversion plant employing the Eni Slurry Technology with a 23 KBBL/d capacity for the processing of extra heavy crude with high sulphur content producing high quality middle distillates, in particular gasoil, and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled in 2012.

The Taranto refinery has balanced refining capacity of 110 KBBL/d and a conversion index of 64.6%. This refinery can process a wide range of crude and other feedstock. It mainly produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants and relevant facilities, including two units for the desulphurization of middle distillates, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant for the conversion of high sulphur content residues into valuable products and catalytic cracking feedstocks. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2008 a total of 2.3 mmtonnes of this oil were processed). A new hydrocracking unit with a capacity of 17 KBBL/d is expected to start production in 2009. Eni’s plan to upgrade the conversion capacity of this refinery will enable to extract value from fuel oil and other semifinished products currently exported.

Gela, with a balanced refining capacity of 100 KBBL/d and a conversion index of 144.8%, this refinery located on the Southern coast of Sicily is highly integrated with upstream operations as it processes heavy crude produced from nearby Eni fields offshore and onshore Sicily. In addition, it is integrated downstream as it supplies large volumes of petrochemical feedstock to Eni’s in site petrochemical plants. The refinery also manufactures fuels for automotive use and petrochemical feedstock. Its high conversion level is ensured by an FCC unit with go-finer for the upgrading of feedstocks and two coking plants for the vacuum conversion of heavy residues. The power plant of this refinery also contains modern residue and exhaust fume treatment plants which allow full compliance with the tightest environmental standards. An upgrade of the Gela refinery is underway by means of an upgrade of its power plant, through the revamping of its boilers, aimed at increasing profitability by exploiting the synergies deriving from the integration of refining and power generation.

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

Porto Marghera, with a balanced refining capacity of 80 KBBL/d and a conversion index of 20.2%, this refinery 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) designed to increase yields of valuable products.

 

Rest of Europe

In Germany Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that included the Ingolstadt, Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 70 KBBL/d mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany. In 2008 the restructuring of the whole complex was completed with the closing down and divestment of the Ingolstadt site, the construction of a new hydrocracker with a capacity of approximately 2 mmtonnes/y (40 KBBL/d), the revamping other assets (in particular a reformer and a hydrofiner) and the shutting-down of a topping unit in Neustadt. The project completed in 2008 with start-up in the second half of December and production expected in 2009, aimed at increasing middle distillate yields and reducing the production of gasoline.

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Eni holds a 32.4% stake in Ceska Rafinerska, which includes two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to about 53 KBBL/d.

In addition, with its 33.34% interest in Galp, with the Portuguese group Amorim Eni jointly controls two refineries in Portugal: a small one in Porto specialized in the manufacture of lubricant bases and a larger and more complex one in Sines integrated with petrochemicals.

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

Availability of refined products		2006		2007		2008

Italy
Refinery throughputs
At wholly-owned refineries		27.17			27.79			25.59
Less input on account of third parties		(1.53	)		(1.76	)		(1.37	)
At affiliates refineries		7.71			6.42			6.17
Refinery throughputs on own account		33.35			32.45			30.39
Consumption and losses		(1.45	)		(1.63	)		(1.61	)
Products available for sale		31.90			30.82			28.78
Purchases of refined products and change in inventories		4.45			2.16			2.56
Products transferred to operations outside Italy		(4.82	)		(3.80	)		(1.42	)
Consumption for power generation		(1.10	)		(1.13	)		(1.00	)
Sales of products		30.43			28.05			28.92
Outside Italy
Refinery throughputs on own account		4.69			4.70			5.45
Consumption and losses		(0.32	)		(0.31	)		(0.25	)
Products available for sale		4.37			4.39			5.20
Purchases of finished products and change in inventories		11.51			13.91			15.14
Products transferred from Italian operations		4.82			3.80			1.42
Sales of products		20.70			22.10			21.76
Refinery throughputs on own account		38.04			37.15			35.84
of which: total equity crude input		12.50			9.29			6.98
Total sales of refined products in Italy and outside Italy		51.13			50.15			50.68
Crude oil sales		30.66			25.82			26.00
TOTAL SALES		81.79			75.97			76.68

In 2008, refining throughputs on own account in Italy and outside Italy were 35.84 mmtonnes, down 1.31 mmtonnes from 2007, or 3.5%. Volumes processed in Italy decreased by 2.06 mmtonnes, or 6.3%, due to planned and unplanned refinery downtime at the Taranto, Porto Marghera and Gela plants, as well as lower volumes at the Livorno refinery due to a challenging refining environment in the first half of the year. The increase recorded outside Italy (up 750 ktonnes) was mainly due to higher capacity entitlements at Ceska Rafinerska following the purchase of an additional ownership interest made in 2007, partly offset by the lower volumes in Germany.

Total throughputs in wholly-owned refineries (25.59 mmtonnes) decreased 2.20 mmtonnes, down 7.9%, from 2007. Approximately 21.5% of volumes processed crude was supplied by Eni’s Exploration & Production segment (30.2% in 2007) representing a 8.7% decrease from 2007, equivalent to a lower volume of 2.3 mmtonnes due to lower equity crude availability from Russia, Libya and Italy.

 

Logistics

Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 21 directly managed storage sites and a network of petroleum product pipelines for the sale and storage of refined products, LPG and crude.

Eni holds interests in five joint entities established by partnering the major Italian operators. These are located in Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) and aim at reducing logistic costs, and increasing efficiency.

Eni operates in the transport of oil and refined products: (i) on land through a pipeline network of leased and owned pipelines extending over 3,019 kilometers (1,447 kilometers are owned by Eni); and (ii) by sea through spot and long-term lease contracts of tanker ships. Secondary distribution to retail and wholesale markets is effected through third parties who also own their means of transportation, in some instances with minority participation of Eni.

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In 2008 Eni implemented a new hub model made up of five main areas in Italy and including all Eni logistic assets among which refining ones. This new model aims to enhance the efficiency of logistic operations by: (i) centralizing the handling of products flows on a single platform enabling real time monitoring; and (ii) introducing more efficient operating modes in the collection and delivery of orders with the aim of reducing unit delivery costs.

 

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		2006		2007		2008

Italy
Retail marketing		8.66		8.62		8.81
Wholesale marketing		11.74		11.09		11.15
		20.40		19.71		19.96
Petrochemicals		2.61		1.93		1.70
Other sales		7.42		6.41		7.26
Total		30.43		28.05		28.92
Outside Italy
Retail marketing		3.82		4.03		3.86
Wholesale marketing		4.60		4.96		5.38
		8.42		8.99		9.24
Other sales		12.28		13.11		12.52
Total		20.70		22.10		21.76
		51.13		50.15		50.68

In 2008, sales volumes of refined products (50.68 mmtonnes) were up 0.53 mmtonnes from 2007, or 1.1%, mainly due to larger volumes sold on retail and wholesale markets in Italy and wholesale market in the rest of Europe.

 

Retail Sales in Italy

Eni markets refined products in Italy trough its Agip-branded network of operated service stations. In 2008, volumes of refined products marketed on the Italian network (8.81 mmtonnes) were up 190 ktonnes from 2007, or 2.2%, despite a decrease recorded in domestic consumption, mainly due to marketing activities ("Iperself" promotional campaign – see below – and fidelity programs) that sustained market share growth from 29.2% to 30.6%; market share is computed as ratio of Eni’s sales volumes to national consumption as published in national statistics. Higher sales mainly related to gasoil sales while gasoline sales registered a decrease.

The average throughput per service station measured on gasoline and gasoil sales was 2,470 kliters, an increase of 26 kliters from 2007, or up 1.1%.

At December 31, 2008, Eni’s retail network in Italy consisted of 4,409 service stations, 19 more than at December 31, 2007, resulting from the positive balance of acquisitions/releases of lease concessions (32 units), the opening of new service stations (7 units), partly offset by the closing of service stations with low throughput (19 units) and the release of one service station under highway concession.

In 2008, fuel sales of the Blu line – high performance and low environmental impact fuel – declined due to sensitivity of demand to prices of these products in an environment of economic downturn and high fuel prices on average. Sales of BluDiesel and its reformulated version BluDieselTech amounted to 583 ktonnes (677 mmliters), declining by 152 ktonnes from 2007 and represented 10.6% of gasoil sales on Eni’s retail network. At year end, service stations marketing BluDiesel totaled 4,095 units (4,065 in 2007) covering to approximately 93% of Eni’s network. Retail sales of BluSuper amounted to 78 ktonnes (91 mmliters) and decreased by 20 ktonnes from 2007 and covered 2.5% of gasoline sales on Eni’s retail network. At year end, service stations marketing BluSuper totaled 2,631 units (2,565 at December 31, 2007), covering approximately 60% of Eni’s network.

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In 2007, Eni launched its "You&Agip" promotional campaign, lasting 3 years, designed to boost customer loyalty to the Agip brand. This three-year long initiative offers prizes to customers in proportion to purchases of fuels and convenience items at Agip’s stores as well as at the ones of certain partners to the program. At every purchase of fuels or convenience items, clients are granted a proportional amount of points that are credited to a fidelity card. Clients are able to decide how to accumulate points and when to spend them. At December 31, 2008, the number of customers that actively used the card in the period amounted to over about 4 million. The average number of cards active each month was over 3 million. Volumes of fuel marketed under this initiative represented 46% of total volumes marketed on Eni’s service stations joining the program, and 44% of overall volumes marketed on Eni’s network.

In 2008, Eni revamped its "Iperself" promotional campaign, which provides a euro 0.06 discount per liter to customers purchasing fuel in self service stations during closing hours. Supported by other marketing activities this initiative allowed to achieve higher sales and a higher market share in retail marketing even in an environment characterized by a steep decline in domestic demand.

Eni plans to strengthen its competitive positioning in Italy by upgrading its outlets. Management targets to expand its share in the domestic retail market for fuels by 2012 from the 2008 level of 30.6%. Planned actions are designed to attain European standards of quality and services, leveraging on innovative marketing initiatives aimed at strengthening clients loyalty, develop the offer of premium products and develop innovative non oil formats. A strong focus will be devoted to pursue high levels of operating efficiency. In the next four years, Eni plans capital expenditures for the construction, upgrading and restructuring of its plants, increasing the number of "Iperself" and fully automated service stations as well as complying with applicable environmental standards and regulations.

By 2012, Eni expects to achieve volumes of approximately 11.4 billion liters sold (approximately 11 billion liters in 2008) with a retail network composed of 4,451 service stations, of which 75% owned.

 

Retail Sales in the Rest of Europe

In recent years, Eni’s strategy focused on selectively growing its market share, particularly by means of acquiring valuable assets in European areas with interesting profitability perspectives. In implementing its growth strategy, Eni has been able to leverage on synergies ensured by the proximity of these markets to Eni’s production and logistic facilities, brand awareness and economies of scale.

Growth outside Italy will continue to be selective and aimed at strengthening Eni’s competitive position in key markets.

In 2008 retail sales of refined products marketed in the rest of Europe (3.86 mmtonnes) was down 170 ktonnes from 2007, or 4.2%, mainly in the Iberian Peninsula, due to the disposal of downstream activities to Galp, and in Germany. These decreases were partly offset by higher sales in the Czech Republic, Hungary and Slovakia due to the purchase of assets made in the fourth quarter of 2007.

At December 31, 2008, Eni’s retail network in the rest of Europe consisted of 1,547 units, a decrease of 503 units from December 31, 2007 (2,050 service stations). The network evolution was as follows: (i) divestment of 371 service stations in the Iberian Peninsula to Galp; (ii) a negative balance of acquisition/releases of leased service station was recorded (down 135 units), with positive changes in Hungary and Switzerland and negative ones in Germany; (iii) 17 low throughput service stations were closed; (iv) purchased 15 service stations; and (v) opened 5 new outlets. Average throughput (2,577 kliters) was substantially in line with 2007.

The key markets of Eni’s presence are: Austria with a 7% market share, Hungary with 11.6%, Czech Republic with 11.4%, Slovakia with 10.2%, Switzerland with 6.4% and Germany with a 3.8% on national base. These market shares were calculated by Eni based on public data on national consumption and Eni’s sales volumes.

In 2008, management divested its retail and wholesale marketing activities in the Iberian Peninsula following the exercise of a call option on part of Eni’s partner Galp Energia (Eni’s share being 33.34%), in accordance with the agreement signed in December 2005 by the majority shareholders of Galp Energia (in addition to Eni, Amorim Energia and Caixa Geral de Depósitos). The transaction includes 371 Agip-branded service stations.

Growth outside Italy will continue to be selective and aimed at strengthening Eni’s competitive position in key markets, based on the competitive advantage provided by synergies in supply, logistics and brand awareness. Eni intends to focus on the German, Swiss and Austrian markets where it targets to increase its market share.

Non oil activities in the rest of Europe are carried out under the CiaoAgip brand name in 1,032 service stations, of these 325 are in Germany and 168 in France with a 67% coverage of the network and a virtually complete coverage of owned stations.

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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 2008 volumes marketed on the wholesale market in Italy, were approximately 11.15 mmtonnes up 0.06 mmtonnes from 2007, or 0.5%, mainly reflecting an increase in market bunker consumption on the and fuel oil sales. Sales volumes on wholesale markets outside Italy were 4.82 mmtonnes, up approximately 430 ktonnes from 2007, or 9.8%, mainly due to the growth in the Czech and Swiss markets, offset by declines in Spain, Austria, France and Germany.

Eni also markets jet fuel directly at 46 airports, of which 27 in Italy. In 2008, these sales amounted to 2.4 mmtonnes (of which 1.9 mmtonnes in Italy).

Eni is active also in the international market of bunkering, marketing marine fuel mainly in 40 ports, of which 23 are in Italy. In 2008 marine fuel sales were 2.4 mmtonnes (2.3 mmtonnes in Italy). Other sales were 21.36 mmtonnes of which 19.66 mmtonnes referred to sales to oil companies and traders, and 1.70 mmtonnes, supplies to the petrochemical sector.

LPG

In Italy Eni is leader in LPG production, marketing and sale with 566 ktonnes sold for heating and automotive use (under the Agip brand and wholesale) equal to a 17.8% market share. Additional 234 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.

Lubricants

Eni operates 7 (owned and co-owned) blending plants, in Italy, Europe, North and South America and the Far East. With a wide range of products composed of over 650 different blends, Eni masters international state of the-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing).

In Italy Eni is leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at Eni refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero.

In 2008, retail and wholesale sales in Italy amounted to 125 ktonnes with a 24.8% market share. Eni also sold approximately 5 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 111 ktonnes, of these about 50% were registered in Europe (mainly Spain, Germany, and France).

Oxygenates

Eni, through its subsidiary Ecofuel (Eni’s interest 100%), sells approximately 2 mmtonnes/y of oxygenates mainly ethers (approximately 10% of world demand) and methanol (approximately 1.5% of world demand). About 72% of products are manufactured in Italy in Eni’s plants in Ravenna, in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic), the remaining 28% is bought and resold.

In 2008 Eni started distributing bio-ETBE on the Italian market in compliance with the new legislation indicating the minimum content of bio-fuels. Bio-ETBE is a kind of MTBE that gained a relevant position in the formulation of gasoline in the European Union, due to the fact that it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. World market for ETBE is currently limited to the European Union and Japan and in 2008 was estimated to amount to 2.2 mmtonnes.

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Capital Expenditures

See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".

 

 

Engineering & Construction

Eni operates 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%). Saipem boasts a strong position in the relevant market leveraging on technological and operational skills mainly in frontier areas, harsh environments and complex projects, as well as on engineering and project management capabilities and ownership or availability of necessary technologies and also on its integration with Snamprogetti. In spite of a weaker scenario in the oil industry worldwide and the uncertainty of the changed economic context, Saipem plans to continue consolidating its position in onshore and offshore markets, completing the expansion of its construction and drilling fleet.

Saipem plans to achieve these objectives implementing the following strategic guidelines: (i) to maximize the efficiency in all business areas with the aim in particular to maintain top execution and security standards, optimize the utilization rate of the fleet, preserve competitive supply costs and increase structure flexibility in order to mitigate the effects of negative business cycles; (ii) to consolidate the Company’s competitive position in large offshore and onshore projects for the development of hydrocarbon fields strengthening at the same time its market share in the strategic segments of deepwater, FPSO, heavy crude upgrading and gas monetization; (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 order to confirm the Company’s leading position in the segment of complex projects with high profitability.

Saipem expects to invest approximately euro 3.9 billion over the next four years to further expand the geographical reach and operational features 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 in 2008 amounted to euro 13,860 million, of these projects to be carried out outside Italy represented 94%, while orders from Eni companies amounted to 4% of the total. Order backlog was euro 19,105 million at December 31, 2008 (euro 15,390 million at December 31, 2007). Projects to be carried out outside Italy represented 98% of the total order backlog, while orders from Eni companies amounted to 13% of the total.

		2006		2007		2008

Orders acquired and breakdown by business		(euro million)		11,172		11,845		13,860
Offshore construction				3,681		3,496		4,381
Onshore construction				4,923		6,070		7,522
Offshore drilling				2,230		1,644		760
Onshore drilling				338		635		1,197
Originated by Eni companies		(%)		24		16		4
To be carried out outside Italy		(%)		91		95		94
Order backlog and breakdown by business		(euro million)		13,191		15,390		19,105
Offshore construction				4,283		4,215		4,682
Onshore construction				6,285		7,003		9,201
Offshore drilling				2,247		3,471		3,759
Onshore drilling				376		701		1,463
Originated by Eni companies		(%)		20		22		13
To be carried out outside Italy		(%)		90		95		98

Business areas

Offshore construction

Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPIC oriented

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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 outsourcing the management of EPC projects and non core engineering activities in cost efficient areas reaching economies of scale in its engineering hubs and employing local resources in contexts where this represents a competitive advantage, directly managing offshore construction processes through the creation of a large construction yard and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, by building a pipelayer, a field development ship for deepwater and other supporting assets for offshore activity.

Saipem’s offshore construction fleet is made up of 28 vessels and 45 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 Saibos FDS 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 multifunction vessel for the development of hydrocarbon fields, able to lay rigid and flexible pipes and provided with cranes capable of lifting over 2 ktonnes; and (v) the Semac semi-submersible vessel used for large 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 2008 in Offshore construction were: (i) a contract on behalf of Nord Stream AG for laying the Nord Stream gas pipeline constituted by a twin natural gas pipeline that will link Russia and Germany across the Baltic Sea. Overall capacity of about 55 BCM/y will be reached when both lines are operational; (ii) an EPIC contract on behalf of Elf Petroleum Nigeria Ltd (Total) for the construction and installation of underwater pipelines and related facilities connecting the Usain offshore oil field to an FPSO unit (Floating Production Storage Offloading); and (iii) a contract on behalf of OLT Offshore LNG Toscana for the FSRU (Floating, Storage and Regasification Unit) of the LNG terminal of Livorno through the conversion of a gas carrier ship moored offshore Tuscany into a floating, storage and regasification unit. The FSRU will have a storage capacity of 137 KCM of LNG and a production capacity of 3.75 BCM/y of natural gas.

Onshore construction

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 intends to capture opportunities arising from the market, both in the plants and pipeline segment, by leveraging on its solid competitive position in the strategic areas of Middle East/Caspian Area, North and West Africa and Russia. In 2008, leveraging on its distinctive know-how in the gas monetization segment, Saipem has been awarded for the first time the role of main contractor for the construction of a large gas liquefaction plant in Algeria, asserting its reputation as an integrated player, capable of managing large and complex turnkey projects in the high tech market of LNG.

The most significant orders awarded in 2008 in Onshore construction were: (i) an EPC contract on behalf of Sonatrach for the construction of a single-train gas liquefaction plant, with a capacity of 4.7 mmtonnes/y of LNG near the Algerian city of Arzew; (ii) an EPC contract on behalf of Saudi Aramco for the construction of three gas/oil separation trains (GOSP, Gas Oil Separation Process) as part of the Manifa Field Development Program to increase the production capacity of Saudi Arabia by 900 BBL/d; (iii) an EPC contract on behalf of Sonatrach for the construction of three LPG production trains with a total capacity of 8 mmCM/d as part of the development of the Hassi Messaoud field in Algeria; and (iv) an EPC contract on behalf of Total Exploration and Production Nigeria Ltd for the upgrade of OML 58 Block through the revamping of the existing Flow Station and the construction of a new gas treatment train in order to increase gas production to 17.5 mmCM/d.

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, North Sea, Mediterranean Sea and 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 particular, over the next four years Saipem intends to build: (i) the Scarabeo 8 and 9, new generation semi-submersible platforms, to be employed in drilling operations in the deep-water of the Barents Sea and in the Gulf of Mexico, respectively, initially on behalf of Eni’s upstream activity; (ii) the Perro Negro 6 jack-up to conduct operations in shallow waters; and (iii) the new S12000 drilling ship to perform operations in West Africa on behalf of Total. In parallel, significant investments are planned 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).

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Saipem’s offshore drilling fleet consists of 11 vessels fully equipped for its primary operations and some drilling plants installed on board of fixed offshore platforms. One of its most important offshore drilling vessels is the Saipem 10000, designed to explore and develop hydrocarbon reservoirs operating in excess of 3,000 meters water depth in full dynamic positioning. The ship has a storage capacity of 140,000 BBL and is able to maintain a steady operating position without anchor moorings by means of 6 computerized azimuth thrusters, which offset and correct the effect of wind, waves and current in real time. The vessel is operating in ultra deep waters (over 1,000 meters) in West Africa. Other relevant vessels are Scarabeo 5 and 7, third and fourth generation semi-submersible rigs able to operate at depths of 1,900 and 1,200 meters of water, respectively. Average utilization of drilling vessels in 2008 stood at 84.7% (94.7% in 2007).

The most significant contracts awarded in Offshore drilling in 2008 included: (i) a 5-year extension of the contract for the use of the Scarabeo 7 semi-submersible platform in West Africa on behalf of Eni; (ii) a 2-year extension of the contract for the use of semi-submersible platform Scarabeo 3 in Nigeria on behalf of Addax Petroleum; and (iii) a 12-month contract extension for the use of the Scarabeo 6 semi-submersible platform in Egypt on behalf of Burullus Gas Co.

Onshore drilling

Saipem operates in this area as 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 areas Saipem can leverage on 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 2008 stood at 99% (99.6% in 2007). The 73 rigs owned by Saipem at year end were located as follows: 30 in Venezuela, 16 in Peru, 9 in Saudi Arabia, 7 in Algeria, 3 in Kazakhstan, 3 in Brazil, 2 in Italy, 1 in Ecuador, 1 in Colombia and 1 in Egypt.

The most significant orders awarded in 2008 in Onshore drilling were: (i) contracts on behalf of various oil companies for the lease of 17 rigs with an average contract duration of five years; and (ii) contracts on behalf of various oil companies for the lease of 32 rigs, of which 13 new ones, in South America (mainly in Venezuela and Peru) and Ukraine. The average contract duration was one year for the existent rigs and five years for the new ones.

 

Capital Expenditures

See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".

 

 

Petrochemicals

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 petrochemical business is to effectively and efficiently manage operations in order to lower the break-even considering the volatility of costs of oil-based feedstock and the commoditized feature of Eni’s main 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, also considering the cyclical nature of demand. See "Item 3 – Risk factors". The Company does not expect to incur significant amount of expenditures to develop this business. In future years, management forecast a yearly level of expenditures in line with 2008 mainly targeted to upgrade plant efficiency, execute de-bottlenecking interventions and to comply with all applicable regulations on environment, health and safety issues.

In 2008 sales of petrochemical products (4,684 ktonnes) decreased by 829 ktonnes from 2007, down 15%, in all business areas as a result of lower petrochemical demand for petrochemical products, due to a negative market scenario.

Petrochemical production (7,372 ktonnes) decreased by 1,423 ktonnes from 2007, or 16.2%. In a context of economic downturn, the steep decline in unit margins and sales determined unexpected outages of some plants, in particular in the last part of the year.

Nominal production capacity decreased by approximately 2 percentage points from 2007, due to the shutdown of the Gela cracker. The average plant utilization rate calculated on nominal capacity decreased by 12 percentage

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points from 80.6% to 68.6%, due to the current economic downturn that entailed reductions in production in all main plants.

Approximately 49.5% of total production was directed to Eni’s own productions cycle (48.9% in 2007). Oil based feedstock supplied by Eni’s Refining & Marketing segment covered 24% of requirements (21% in 2007).

Prices of Eni’s main petrochemical products increased on average by 7%, increasing in the business of: (i) olefins (up 13%) with increases in all products; (ii) elastomers (up 10%), in particular polybutadienic and nytrilic rubbers; and (iii) polyethylene (up 5%), in particular EVA. However, these prices increases did not made for higher purchase costs of oil-based feedstock (virgin naphtha was up 17.3% in dollar terms, 9.3% in euro), particularly until September, and as a result product margins significantly decreased from a year ago.

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

Year ended December 31,

		2006		2007		2008

Olefins		2,950			3,490			2,819
Aromatics		772			938			767
Intermediates		553			1,260			977
Styrene		1,088			1,117			1,018
Elastomers		457			515			494
Polyethylene		1,252			1,475			1,297
Total production		7,072			8,795			7,372
Consumption of monomers		(2,488	)		(4,304	)		(3,652	)
Purchases and change in inventories		692			1,022			964
		5,276			5,513			4,684

The table below sets forth Eni’s sales of main petrochemical products by volume for the periods indicated.

Year ended December 31,

		2006		2007		2008

Olefins		1,699			1,797			1,423
Aromatics		530			514			420
Intermediates		654			712			576
Styrene		587			594			543
Elastomers		412			447			433
Polyethylene		1,394			1,449			1,289
Total sales		5,276			5,513			4,684

Olefins

Olefins sales (1,423 ktonnes) decreased by 374 ktonnes from 2007 (down 20.8%), penalized by a poorer market scenario that negatively affected product demand and lower product availability. Main reductions were registered in sales of ethylene (down 30%), butadiene (down 30.3%) and propylene (down 15%).

Olefins production (2,819 ktonnes) declined by 671 ktonnes from 2007, or 19.2%, due to the maintenance shutdown of the Priolo cracker, technical problems at the Brindisi and Dunkerque plants, steep demand reduction and the shutdown of the Gela cracker.

Aromatics and intermediates

Aromatics sales (420 ktonnes) decreased by 94 ktonnes from 2007 (down 18.3%) due to lower demand for isomers (down 33%), mainly in the second part of the year. Intermediates sales (576 ktonnes) decreased by 136 ktonnes from 2007 (down 19.1%) mainly due to temporary shutdown of the Porto Torres cracker as a result of the poorer market scenario that negatively affected demand. Main decreases were registered in phenol (down 30.6%) and cyclohexanone (down 6.4%).

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Aromatics production (767 ktonnes) decreased by 171 ktonnes from 2007 (down 18.2%) mainly due to the maintenance shutdown of the Priolo cracker and the temporary shutdown of the Porto Torres plant.

Intermediates production (977 ktonnes) decreased by 283 ktonnes from 2007 (down 22.5%) mainly due to the shutdown of Porto Torres plant.

Styrene and elastomers

Styrene sales (543 ktonnes) declined by 51 ktonnes from 2007 (down 8.6%). Sales reductions affected essentially compact polystyrene (down 13%) and ABS/SAN (down 13.2%) due to lower demand. Increases in styrene (up 9.8%) and expanded polystyrene (up 5.6%) were due to higher product availability.

Elastomers sales (433 ktonnes) decreased by 14 ktonnes, or 3.1%, due to a steep decline in demand in the last part of the year, mainly in the automotive sector. Sales decreases were registered mainly in lattices (down 11%), NBR (down 9.5%) and polybutadienic rubbers (down 4%). Increases recorded in thermoplastic rubbers (up 6.3%) and SBR (up 3.4%) were due to higher product availability.

Styrene production (1,018 ktonnes) decreased by 99 ktonnes, or 8.9%.

Elastomer production (494 ktonnes) decreased by 21 ktonnes (down 4.1%) due to maintenance shutdown of the Ravenna plant and unexpected outages of the Porto Torres and Ferrara plants.

Polyethylene

Polyethylene sales (1,289 ktonnes) were down 160 ktonnes or 11%, from 2007, reflecting mainly negative market conditions for LPDE (down 19.4%) and HDPE (down 11.4%).

Production (1,297 ktonnes) decreased by 178 ktonnes, or 12.1%, due to the maintenance shutdown of the Gela, Ragusa and Priolo plants and the temporary shutdown of Porto Torres and Dunkerque plants reflecting lower demand. EVA production increased by 8% due to the fact that 2007 was impacted by the outage of Oberhausen plant.

 

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 only encompasses 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 in past years; and
•		the "Corporate and financial companies" segment encompasses Eni Corporate and certain Eni’s subsidiaries engaged in treasury, finance and other general and business support services. Eni Corporate 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 Sofid SpA, Eni International BV and Eni Insurance Ltd, Eni carries out lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an intercompany basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group’s companies).

Management does not consider Eni’s activities in these areas to be material to its overall operations.

 

Seasonality

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

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average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa.

 

 

Research and Development

Technological research and innovation represent key factors in implementing Eni’s business strategies. Eni’s efforts in technological innovation are primarily intended to develop such technologies so as to meet the environmental issues and climate change, to overcome limits in accessing to hydrocarbon resources, to strengthen partnerships with producing countries and to develop renewable sources of energy.

Eni is committed to developing advanced upstream technologies in frontiers areas with environmental and geological complex features, reducing the costs of finding and recovering hydrocarbons, upgrading heavy oils, monetizing stranded gas and protecting the environment. Over the next four years, Eni plans to invest euro 1.1 billion to fund ongoing projects in Eni’s businesses as well as research in the field of renewable energy which could result in potential break-through technologies. Particularly in the next four years Eni plans to fund euro 102 million to "Along with Petroleum" program aimed at identifying and developing research projects on the most advanced aspects of large scale use of renewable energy sources and energy efficiency.

In 2008, Eni’s expenditures on R&D amounted to euro 217 million which were almost entirely expensed as incurred (euro 208 million and euro 220 million in 2007 and 2006).

At December 31, 2008, a total of 1,098 people were employed in research and development activities.

In 2008, a total of 96 applications for patents were filed.

 

 

Insurance

Eni constantly assesses its exposure for the Italian and foreign activities that are mainly covered through the Oil Insurance Ltd ("OIL"), a mutual insurance and reinsurance company that provides its members a broad coverage tailored to the specific requirements of oil and energy companies. Eni makes use of a captive insurance company that covers the risks and implements Eni’s Worldwide Insurance Program re-insured with high quality securities in order to integrate the terms and conditions of the OIL coverage.

An insurance risk manager works in close contact with managers directly involved in core business activities in order to evaluate potential risks and their financial impact on the Group. This process allows Eni to define a constant level of risk retention and, conversely, the amount of risk to be transferred to the market.

The level of insurance maintained by Eni is generally appropriate for the risks of its businesses.

 

 

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.

A brief description of major environmental laws impacting Eni’s activities located in Italy and Europe is outlined below.

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Italy

On April 29, 2006, Legislative Decree No. 152/2006 "Environment Regulation" came into force. This was designed to rationalize and coordinate the whole regulation of environmental matters by setting:

The most important changes introduced by the Decree 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, criteria for waste classification.

The Decree 152/2006 was amended by two subsequent decrees: Legislative Decrees 284/2006 and 4/2008; the latter introduced important changes regarding SEA and EIA procedures, landfill, waste and remediation. A principle of waste hierarchy was introduced along with definition of by-product and secondary raw materials.

The most important aspects of these regulations to Eni are those regulating permits for industrial activities, waste management, remediation of polluted sites, water protection and environmental liability.

On April 9, 2008, Legislative Decree No. 81/2008 "Implementation of Article 1 of Law 123/2007, in matter of protection of the health and the security on the working places" came into force. This was designed to rationalize and coordinate working environments, the equipments and the Individual Protection Devices, the physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), the dangerous substance (chemical agents, carcinogenic substances, etc.), the biological agents and explosive atmosphere, the system of signs, the video terminals.

In 2008 Eni worked on the implementation of the general framework regulations on health and safety contained in this Legislative Decree No. 81/2008, developing all laws and regulations concerning prevention and protection of workers at national and European level to be applied for all kinds of workers and employees.

At European level Eni continued its work for applying the REACH Regulation (Registration, Evaluation, Authorization and Restriction of Chemicals, EC Regulation No. 197/2006).

The complexity and range of situations where Eni is operating imposed the definition and application of principles for consolidating its performance in health and prevention. To this end Eni upholds:

European Union

On January 23, 2008 the European Commission put forward 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 (new Energy Policy for Europe - EPE, so called "20-20 by 2020"). In December 2008 the European Parliament and Council reached an agreement on the package.

The EU is committed to reducing its overall emissions to at least 20% below 1990 levels by 2020, and is ready to scale up this reduction to as much as 30% under a new global climate change agreement when other developed countries make comparable efforts. It has also set itself the target of increasing the share of renewables in energy use to 20% by 2020.

Central to the strategy is a strengthening and expansion of the Emissions Trading System (EU ETS), the EU’s key tool for cutting emissions cost-effectively. Emissions from the sectors covered by the system (energy and manufacturing industries) will be cut by 21% by 2020 compared with levels in 2005. A single EU-wide cap on ETS emissions will be set, and free allocation of emission allowances will be progressively replaced by auctioning of allowances by 2020.

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Emissions from sectors not included in the EU ETS – such as transport, housing, agriculture and waste – will be cut by 10% from 2005 levels by 2020. Each Member State will contribute to this effort according to its relative wealth, with national emission targets ranging from -20% for richer Member States to +20% for poorer ones.

The Directive sets legally binding targets for each Member State, in order to reach the EU target of a 20% share of renewable energy 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 (biofuels, "green" electricity, etc.); this legislation also sets out sustainability criteria that biofuels will have to meet to ensure they deliver real environmental benefits.

The package also seeks 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 where it cannot contribute to global warming. The reinforced carbon market will provide a long-term incentive for investment, while up to 300 million allowances in the new entrants reserve under the EU ETS will be made available to stimulate the construction and operation of up to 12 commercial demonstration CCS projects, and for innovative renewable energy demonstration technologies in the EU.

The fuel quality Directive will place an obligation on suppliers to reduce greenhouse gases from the entire life cycle of the fuel 6% by 2020, mostly by an increased use of biofuels. A review in 2012 will consider increasing the target to 10%, through the inclusion of international projects, carbon capture and storage as well as electricity for cars.

Also a new regulation was approved to set emissions standards for new passenger cars, which is an important tool to assist Member States in meeting their emissions targets in the non-ETS sectors. It will set binding emissions targets to ensure that emissions from the new car fleet will be reduced to an average of 120g CO₂/km by 2015, including the effect of the Fuel Quality Directive, then decreasing to a stringent long-term target of 95g CO₂/km by 2020.

On January 29, 2008, the new IPPC (Integrated Pollution Prevention and Control) Directive 2008/1/EC was published in the Official Journal of the European Union No. 24. Therefore, from February 18, 2008, the new IPPC directive repeals the Directive 96/61/EC with its successive amendments. This directive rationalizes all existing regulations on this issue, confirming the achievement of high levels of environmental protection to be of primary importance to member states.

According to the IPPC Directive, the Member States of the EU have to communicate their national values of emissions into the atmosphere, wastes produced and managed and discharges of compounds into waste. The European Commission published in Official Journal of European Union, May 16, 2007 (2007/C 110/01) the definitive replacement of the European Pollutant Emission Register (EPER) by the European Pollutant Release and Transfer Register (E-PRTR), published in 2006 (Regulation No. 166/2006). In 2008 Italian legislation already required from the IPPC site owners to account and report environmental data related to 2007 according to PRTR Register as requested by the Regulation.

Eni is implementing an Integrated Environmental Information System, able to gather, manage and report the data on all the pollutants released and off-site transferred as requested by PRTR Regulations.

On December 21, 2007, the European Commission published its proposal of directive on Industrial Emissions. In view of the general call for "better regulation", the draft incorporates the reviews of six sector-specific directives (IPPC, Large Combustion Plants, VOC - Volatile Organic Compounds - emissions, incineration of waste and titanium industry). The proposed directive intends to enforce BAT definition, together with a tightening of current minimum emission values in some sectors. The directive extends the scope of the IPPC directive to cover certain activities (e.g. combustion plants between 20 and 50 MW). The new proposal introduces also more robust monitoring and inspections on installations, the review of permit conditions and the reporting of compliance.

On November 22, 2008, the new Directive on waste (Directive 2008/98/EC) was published in the Official Journal of the European Union. The new Directive simplifies the existing legislative framework by clarifying definitions, streamlining provisions and integrating the directives on hazardous waste (91/689/EEC) and on waste oils (75/439/EEC). The Directive introduces a life-cycle approach, focuses on waste policy by improving the way of resources consumption. The scope is to improve the recycling market by setting environmental standards, specifying under which conditions certain recycled waste are no longer considered such. The Directive requires that Member States take appropriate measures to encourage the prevention or reduction of waste production and its harmfulness. This can be done by a combination of several strategies. Especially mentioned are the development of clean technologies, the technical development and marketing of products designed so to contribute as little as possible to increasing the amount of waste. The Directive also sets new recycling targets.

Core of the Directive is the introduction of a waste management hierarchy. This hierarchy is as follows: 1. Waste prevention, 2. Re-use, 3. Recycling, 4. Recovery (including energy recovery), 5. Disposal.

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Moreover the Directive bolsters the importance of the extended producer responsibility in the future waste management measures.

The Member States will have to transpose this Directive into national legislation until December 12, 2010.

 

HSE Activity for the Year 2008

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

In 2008, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards.

In 2008, the total number of certifications obtained was 329 (248 in 2007), of which 123 certifications according to the ISO 14001 standard, 11 certifications according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union) and 51 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

Environment. In 2008, Eni incurred total expenditures amounting to euro 1,081 million for the protection of environment, up 1.7% from 2007. Current environmental expenses decreased by approximately 9% from 2007, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure increased by 22% and mainly related to soil and subsoil protection, water management and air emissions.

Safety. The safety of Eni’s employees, of its contractors and the one of the people living in the area where its activities and assets are located, is of fundamental importance to the Company.

As to safety regulations, in 2008 the Legislative Degree No. 81/2008 on health and safety in workplaces came into force. This decree meaningfully increases the responsibility of companies for violating applicable laws regulating safety at work, then requiring more severe controls by supervisors and managers.

Eni’s safety strategy is based on:

In 2008, the injury frequency rate was 1.45 and the injury severity rate was 0.05.

Cost incurred in 2008 to support the safety levels of operations and to comply with applicable rules and regulations were euro 441 million, down 5.8% from 2007.

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

To protect the health and safety of its employees, Eni relies on a network of 332 health care centers located in is main operating areas. A set of international agreements with the best local and international health centers ensures efficient services and timely responses to emergencies.

In 2008 Eni incurred a total expense of euro 68.6 million, up 27.5% from 2007 to protect the health of its employees.

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Implementation of the Kyoto Protocol

On February 16, 2005, the Kyoto Protocol entered into force and, with it, the commitments of the Annex I Parties which have ratified the Protocol, including the EU and Italy. According to Law No. 120/2002, Italy committed itself to reduce greenhouse gas (GHG) emissions by 6.5% in the period 2008-2012, as compared to GHG levels emitted in 1990. Reductions can be achieved through both internal measures and complementary initiatives. The latter include the so-called flexible mechanisms, which enables a Party to carry out projects in developing countries (CDM - Clean Development Mechanism) and in industrial countries with transition economies (JI - Joint Implementation) in order to obtain emission credits to fulfill the Kyoto compliance.

Italy, as an EU Member State, is part of the EU Emission Trading Scheme ("ETS") that was established by Directive 2003/87/EC. Effective from January 1, 2005, ETS is the largest virtual market in the world for exchanging emission allowances targeting industrial installations with high carbon dioxide emissions.

As foreseen by the Directive, Italy has issued two National Allocation Plans (NAP) covering the periods 2005-2007 and 2008-2012 which set out the allowances awarded to each sector and installation. Eni is part to the ETS. Moreover, Eni is active in the utilization of the Kyoto Flexible Mechanisms. In fact, due to its presence in about 70 countries, Eni is an elective partner for carrying out CDM and JI projects thus contributing to the Italian program of greenhouse gas emissions reduction. In December 2003 during the Conference of Parties to the Kyoto Protocol – COP9 – Eni and the Ministry of the Environment signed a Voluntary Agreement for using flexible mechanisms, promoting CDM and JI and contributing to the sustainable development of host countries.

The ETS EU directive provides that each Member State shall ensure that any operator who produces GHG emissions in excess of the amounts awarded based on national allocation plan, will provide allowances to cover excess emissions a year later in addition to pay a penalty. The excess emissions penalty shall be euro 100 (euro 40 for the first period 2005-2007) for each tonne of carbon dioxide equivalent emitted. All companies are expected to identify and carry out projects for emission reductions. Eni participates in the ETS scheme with 56 plants in Italy and 4 outside Italy, which collectively represent about a third of all greenhouse gas emissions generated by Eni’s plants worldwide. In the whole period (2005-2007) Eni was entitled to allowances equal to 77.2 mmtonnes of carbon dioxide for existing and new installations (of which 25.7 mmtonnes of carbon dioxide for 2007).

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 complied with mandatory limits in the whole period.

Management believes that a significant emission reduction can be achieved in connection with oil and gas production activities outside Italy, that in a number of cases, given lack of local market outlets, require the flaring of natural gas associated to oil production. The elimination of flaring and the use of associated gas for the development of local economies allow sustainable development while reducing greenhouse gas emissions. The validation of such projects as CDM and JI will provide emission credits and facilitate the achievement of the Italian reduction target, as set by the Kyoto Protocol. Eni already carried out Zero Gas Flaring projects in Nigeria and Congo while others are underway.

In November 2006 the Nigerian Kwale-Okpai project has been registered as a CDM project. It regarded the construction of a combined cycle power station, which utilizes the associated gas to oil production formerly flared. More projects are being assessed or implemented in Congo, Nigeria and Angola. Moreover, Eni endorsed the Global Gas Flaring Reduction Initiative of the World Bank, in order to fight for the elimination of obstacles to the completion of gas flaring reduction projects.

The best solutions for compliance with the Kyoto Protocol are the use of low emission energy sources and the adoption of highly efficient technologies. To address the greenhouse gas challenge, Eni performed a detailed analysis for defining its strategy to respond to climate change and to participate in the European emissions trading system, identifying a number of projects for energy saving and emission reductions from its plants.

To ensure comprehensive, transparent and accurate accounting for GHG emissions, which is consistent over time, Eni introduced in 2005 its own Protocol for the accounting and reporting of greenhouse gas emissions (GHG Accounting and Reporting Protocol), which is an essential requirement for emission certification. Indeed, accurate reporting will support the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the evaluation of progress.

For safer and more accurate management of GHG emissions and with a view to supporting accounting, Eni provided all its divisions and 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.

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As a support to its general strategy for a sustainable management of greenhouse gases, Eni continued its programs for the development of natural gas in Italy and outside Italy, by means of technologically advanced projects such as the Blue Stream gas pipeline from Russia to Turkey and the GreenStream pipeline from Libya to Sicily. Increased gas availability in Italy will lead to a further expansion of the gas-power integration, through high efficiency combined cycles with much lower carbon dioxide emissions than coal and liquid fuels.

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. In the long-term, Eni is actively engaged in the political process regarding future emission reduction regulations. In particular Eni is involved in bioenergy and biofuels.

 

 

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 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 Agreement (PSAs), 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 recover 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 PSAs 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 production sharing agreement). 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.

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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 an additional five-year extension until the field depletes.

Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. Royalties are equal to 7% and 4%, respectively, for onshore and offshore production of oil and 7% for both onshore and offshore production of natural gas. A bill of law is currently under review by the Italian Parliament which provides for an increase of royalties on hydrocarbon production from the current rate of 7 to 10%. For the year 2009 management expects that this provision would translate into higher royalties amounting to approximately euro 20 million.

Storage of natural gas

Storage activities in Italy are regulated by Legislative Decree No. 164/2000 ("Decree No. 164"), which enacted the European Directive on Natural Gas 98/30/CE into Italian legislation. The most important aspects of Decree No. 164 concerning storage activities are the following: (i) in vertically integrated enterprises, storage is to be carried out by a separate company not operating in other gas activities (such as Eni’s subsidiary Stoccaggi Gas Italia SpA) or by companies engaged only in transport and dispatching activities, provided the accounts of these two activities are clearly separated from the accounts of storage; (ii) storage activity is exercised pursuant to concessions granted by the Ministry of Productive Activities. The duration of a concession is 20 years, with the possibility of obtaining at most two ten-year extensions if operators complied with the storage programs and other obligations deriving from applicable laws. Existing storage concessions are subject to the Decree. Their original term was confirmed and includes relevant production concessions; (iii) the need for strategic storage in Italy is defined explicitly; the burden of strategic storage is imposed upon companies importing from non-EU countries, which have to provide a strategic storage capacity in Italy corresponding to 10% of the amount of natural gas imported each year; (iv) holders of storage concessions are required to provide storage capacity for domestic production, for strategic use and for modulation to eligible users without discriminations, where technically and economically viable; (v) modulation storage costs are charged to shippers which have to provide modulation services adequate to the requirements of their final customers; (vi) storage tariffs criteria are determined by the Authority for Electricity and Gas in order to ensure a preset return on capital employed, taking into account the typical risk inherent in this activity, as well as volumes stored for ensuring peak supplies and the need to incentive capital expenditure for upgrading the storage system; and (vii) the Authority for Electricity and Gas establishes the criteria and priority of access storage operators have to include in their own storage codes.

In compliance with the provisions of Article 21 of Decree No. 164/2000, on October 21, 2001 all storage activities carried out within the Eni Group were conferred to Stoccaggi Gas Italia SpA ("Stogit"), which holds ten storage concessions.

On March 3, 2006, the Authority for Electricity and Gas with Resolution No. 50/2006 published the criteria for determining storage tariffs for a regulated period starting from April 1, 2006 and ending on March 31, 2010.

According to this Resolution, the storage company calculates revenues for the determination of unit tariffs for storage services by adding the following cost elements:

(i)		a return on the capital employed by the storage company equal to 7.1% (8.33% in the first regulated period);
(ii)		depreciation and amortization charges; and
(iii)		operating costs.

In the years following the first year of the newly regulated period, reference revenues are updated to take account of variations of capital employed and the impact of the indexation of depreciation charges and operating costs to consumer price inflation lowered by a preset rate of productivity recovery.

Applicable regulation provides for incentives to capital expenditures intended to develop and upgrade storage capacity by recognizing an additional rate of return of 4% on the basic rate to capital expenditure projects aiming at

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developing new storage deposits and increasing existing capacity. Such incentives are applicable for a sixteen-year period and an eight-year period, respectively.

In November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority opened an inquiry to gain insight into the functioning of the natural gas storage activity in Italy, particularly with regards to the lack of investments by operators aimed at expanding natural gas storage capacity to store natural gas in Italy. Eni, through its wholly-owned subsidiary Stogit Italia, owns nearly the entire storage capacity currently existing in Italy.

With Resolution No. 220/2006, the Italian Authority for Electricity and Gas approved the storage code proposed by Stoccaggi Gas Italia on the basis of the framework and criteria established by Resolution No. 119/2005 ("Adoption of guarantees for free access to natural gas storage services, duties of subjects operating storage activities and rules for the preparation of a storage code").

This code regulates access to and provision of storage services during normal operational conditions, regulates procedures for conferring storage capacities, fees to be charged to customers in case they uplift from or input to storage sites volumes in excess or uses higher input/uplift capacity with respect to scheduled and operating programs. On the basis of these provisions, Eni may incur significant charges for storage services should the Company fail to use storage services in accordance with scheduled operating programs.

The code has been in force since November 1, 2006.

The storage company offers services according to an access priority established by the Italian Authority for Electricity and Gas as follows:

(i)		mandatory services, including modulation storage, mineral storage, and strategic storage services; and
(ii)		services for operating needs of transport companies, including hourly modulation.

The modulation storage service is geared towards satisfying modulation needs of natural gas users in terms of peak consumption and daily or seasonal trends in consumption. Final clients consuming less than 200,000 CM on an annual basis are entitled to a priority when satisfying their modulation requirements. To that end, the storage company makes available its capacity for space, injection and off-take on an annual basis in accordance with its storage code.

The mineral storage service aims to allow natural gas producers to perform their activity under optimal operating conditions, according to criteria determined by the Ministry of Economic Development.

The strategic storage service aims to satisfy certain obligations of natural gas importers from countries not belonging to the EU in accordance with Article 3 of Legislative Decree No. 164/2000. The relevant storage capacity dedicated to this service is determined by the Ministry of Economic Development.

Storage capacity is awarded by the storage company for periods no longer than a thermal year by April 1, of each year. The first requests to be met are those for strategic storage and for the operating balancing of the system. The residual capacity available and the maximum daily uplift capacity is awarded according to the following order of priority to: (i) holders of production concessions requesting mineral storage services; (ii) natural gas selling operators who are held to provide a modulation service of their supply to their customers according to Article 18, paragraphs 2 and 3 of Legislative Decree No. 164/2000, for maximum volumes corresponding to a seasonal demand peak with average temperatures, on the terms and conditions established by a procedure to be issued by the Authority for Electricity and Gas; (iii) to the entities mentioned in (ii) above only for those additional maximum volumes related to a seasonal demand peak in case of certain low temperatures measured on a 20-year period, under the terms and conditions of the procedure mentioned in (ii) above; and (iv) the entities requesting access for services different from the ones mentioned above.

Eni held natural gas for strategic reserve purposes in its storage business, as established by Decree No. 164. The strategic reserves of gas are defined as "stock destined to meet situations of deficit/decrease of supply or crisis of the gas system". The Ministry of the Economic Development determines quantities and usage criteria of such reserves. As of December 31, 2008 Eni held approximately 179 BCF of strategic reserves of natural gas (179 BCF at year end 2007).

 

Gas & Power

Natural gas market in Italy

The European Directive on Natural Gas was implemented into Italian legislation through Legislative Decree No. 164 of May 23, 2000 ("Decree No. 164"), effective from June 21, 2000. As concerns natural gas activities carried out by Eni, the most relevant aspects of the decree are as follows:

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(i)		starting in 2003 all customers are eligible customers (with access to the natural gas system and free to choose their supplier of natural gas);
(ii)		Antitrust thresholds are in place for gas operators in Italy as follows: (a) effective January 1, 2002, operators are prohibited to transmit into the national transport network imported or domestically produced gas volumes higher than a preset share of Italian final consumption. This share is 75% of total final consumption in the first year of regulation and then is to decrease by 2 percentage points per year to reach a 61% threshold in terms of final consumption by 2009; and (b) effective January 1, 2003, operators are prohibited to market gas volumes to final customers in excess of 50% of overall volumes marketed to final customers. Compliance with these ceilings is verified yearly by comparing actual average shares obtained by any operator in a given three-year period for both volumes input and volumes marketed to customers with average shares permitted by the law for the same period. Actual shares are computed net of losses (in the case of sales) and volumes of natural gas consumed in own operations. Based on a bill passed by the Italian upper house, Eni expects that these antitrust thresholds will be renewed when they expire in 2010;
(iii)		natural gas transport and dispatching activities have to be carried out by a separate company that is not allowed to carry out any other activity in the natural gas field, with the only exception of storage, for which, however, accounting and operating separation is envisaged. Also distribution, which includes the transport of natural gas by means of local gas pipeline networks for delivery to customers, has to be carried out by a separate company which cannot perform other gas related activities. Sales activity to final customers is compatible only with import, export and production activities and is subject to authorization from the Ministry of Productive Activities. Concessions for the distribution of natural gas will be awarded by bid procedure; and

(iv)

tariff criteria and return on capital employed for transport, dispatching, storage, use of LNG terminals and distribution are determined by the Authority for Electricity and Gas. Third parties are allowed to access transport infrastructure, storage sites, LNG terminals and distribution networks on a regulated basis. As provided for by the decree, a Network Code containing norms and regulations for the operation of and access to infrastructure was prepared by operators on the basis of criteria set by the Authority for Electricity and Gas.

Year 2008 closed the fifth three-year regulated period for natural gas volumes input in the domestic transport network, for which the allowed average percentage was 63% of domestic consumption of natural gas, and the fourth three-year regulated period for sales volumes to the Italian market. Eni’s presence on the Italian market complied with said limits.

Law No. 239 of August 23, 2004 on the restructuring of the energy sector in Italy

This law provides for:

Law Decree No. 239/2003

Law Decree No. 239/2003, converted with amendments into Law No. 290/2003, prohibits companies operating in the natural gas and power industries to hold stakes higher than 20% in the share capital of companies owning and managing national networks for the transmission of natural gas and power.

The term by which companies must comply with this provision, which was initially fixed at December 31, 2008, will be re-determined in 24 months after the effective date of said decree from the Italian Prime Minister. Currently, Eni is unable to predict that date.

In addition, on March 23, 2006 a Presidential Decree defined criteria and methods for the divestment of the interest held by Eni in Snam Rete Gas SpA, introducing the special powers of the Ministry of Economy and Finance

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provided for by the regulations on the divestment of interests held by the Italian Government ("golden share") in the By-laws of this company.

Increasing competition in the wholesale segment of natural gas and power

In order to implement the Law Decree defined by the Italian Government to face the economic downturn, on March 2009, the Authority for Electricity and Gas proposed certain rules on gas and power sales and production to increase competition on the Italian market.

The new rule is aimed at increasing competition on the wholesale segment in Italy, both in the natural gas market and the electricity one. The Authority for Electricity and Gas will define a certain amount of quantities of gas to be sold at a fixed price. The main operator in the Italian gas market will be obliged to offer this set amount of natural gas. In particular, from October 1 to March 31 of each year, starting from 2009, the main operator is obliged to offer about 100 mmCM per day and 20 mmCM per day from April 1 to September 30. This rule should limit the discretionarily of the main operator in defining higher prices of natural gas and on the other side to increase liquidity of the natural gas market in Italy.

Natural gas prices

Prices of natural gas sold to industrial and thermoelectric customers as well as to wholesalers are freely established among buyers and sellers following the liberalization of the natural gas sector introduced by Decree No. 164. Notwithstanding this, the Authority for Electricity and Gas holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the Authority for Electricity and Gas) and Legislative Decree No. 164/2000.

Furthermore, the Authority is entrusted with the power of regulating natural gas prices to residential and commercial customers which were not eligible customers until December 31, 2002.

In fact, the Presidential Decree dated October 31, 2002 entrusted the Authority for Electricity and Gas with the power to define, calculate and update gas selling prices for customers who were not-eligible customers until December 31, 2002, also after the opening up of the gas markets from January 1, 2003, additionally targeting the public goal of containing inflationary pressure deriving from increasing energy costs. Consistently with this decree, the Authority for Electricity and Gas: (i) with Decision No. 195 of November 29, 2002 changed the methods for periodically updating selling prices for natural gas in connection with changes in international prices of crude oil and refined products. Such changes regarded the scheduled update process (from every two months to every three), and the duration of the reference period for the calculation of changes in average international prices as compared to the first application quarter (changes are calculated with reference to a nine-month period preceding the update). The invariance threshold, beyond which tariffs are updated, remained at 5%; and (ii) with Resolution No. 207 of December 12, 2002, it decided that companies selling natural gas through local networks have to maintain the conditions applied to non-eligible customers until December 31, 2002 until the customer accepts a new contract offer. In addition, the Authority for Electricity and Gas decided that these companies can propose their own new contract offers and the tariffs determined according to the criteria established by the Authority for Electricity and Gas, adequately advertising them before March 31, 2003 (such offers must be published on the companies web page, on at least one newspaper of general circulation and on the Gazzetta Ufficiale of their region or autonomous province).

Changes introduced to the indexation mechanism of the raw material component in supplies to residential customers by the Authority for Electricity and Gas: Resolutions No. 248/2004; 134/2006 and 79/2007

With Resolution No. 79/2007 the Italian Authority for Electricity and Gas established a new indexation mechanism for the raw material cost component in natural gas supplies to customers consuming less than 200,000 CM/y who were not-eligible customers until December 31, 2002 (mainly residential and commercial customers located in urban centers). The new indexation mechanism of the raw material cost component in tariffs paid by end customers consuming less than 200,000 CM/y as set in Resolution No. 79/2007 basically works this way: (i) it has limited the ability of gas operators to transfer to customers changes in the raw material cost by setting a cap of 75% for changes in the raw material component linked to a fall in Brent crude prices below 20 $/BL or a rise within the 35-60 $/BL range, raising the cap at 95% if Brent crude prices are higher than 60 $/BL; (ii) it has changed the relative weight of the three products making up the reference index of energy prices whose variations – when higher or lower than 2.5% as compared to the same index in the preceding period – determine the adjustment of raw material costs; (iii) it has replaced one of the three products included in the index (a pool of crudes) with Brent crude; and (iv) it has reduced the value of the variable wholesale component of the selling price by 0.26 euro/CM. Additionally, Italian natural gas importers – including Eni – were obliged to renegotiate existing wholesale supply contracts in order to take account of this new indexation mechanism. For the year 2005, the Resolution introduced a transitory regime whereby the impact of the new indexation mechanism was equally shared by importers and wholesalers in case importers had renegotiated existing wholesale contracts and informed of this the Authority. On these basis, Eni reversed part of the reserves accrued in Eni’s accounts for 2005 and 2006 with respect to the

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preliminary estimated impact of the new indexation mechanism on its gas selling margins resulting in a gain recognized in the profit and loss for the year 2007. See "Item 5 – Results of Operations – Gas & Power".

This indexation mechanism applies for a two-year period effective July 1, 2006, with the option of a one year extension following a decision of the Authority. Eni cannot foresee any development of this matter.

Transport

Transport tariffs. With Resolution No. 120 of May 30, 2001, the Authority for Electricity and Gas published the criteria transport companies have to apply in determining natural gas transport and dispatching tariffs on national and regional transportation networks, for the first regulatory period made up of four thermal years (each thermal year begins on October 1 of each calendar year and ends on September 30), as provided for by Decree No. 164/2000. Tariffs are subject to approval by the same Authority, which ensures their compliance with preset criteria. This tariff system substituted previous agreements between Eni and customers of all categories. Within the first quarter of each calendar year, transport companies submit the tariff proposal to the Authority for Electricity and Gas who grants approval.

Criteria established by the Authority for Electricity and Gas set a cap on revenues from transport and dispatching activity ("allowed revenues") which is adjusted annually; the criteria also define a separate treatment of revenues on existing assets and on new capital expenditure on expansions and extension of infrastructure.

In the first thermal year allowed revenues are calculated as the sum of: (i) operating costs including storage and modulation costs; (ii) amortization and depreciation of transport assets; and (iii) return on net capital employed. Net capital employed is calculated by re-evaluating historic costs of transport infrastructure (pipelines, compressor stations and other support equipment) on the basis of certain inflationary indexes; resulting amounts are adjusted to take into account the residual useful life of assets (pipelines are estimated to have a useful life of 40 years) and also subtracting State grants. The application of this methodology implies an estimated value of Eni’s transport assets of approximately euro 9.6 billion. This, however, is a valuation for regulatory purposes and should not be read as an indication of the market value of Snam Rete Gas. The rate of return on capital employed set by the Authority for Electricity and Gas was 7.94% (pre-tax), for the first regulatory period. Once established, allowed revenues for the first year are divided into two components: (i) capacity revenues equal to 70% of allowed revenues which are the maximum amount of revenues collectable from the sale of transport capacity to customers; and (ii) commodity revenues equal to 30% of allowed revenues which are the maximum amount of revenues collectable from transported volumes.

Starting from the second year these two components are adjusted on a yearly basis to take into account inflation and certain reduction factors (set at 2% and 4.5% for capacity revenues and commodity revenues, respectively); commodity revenues are also adjusted to transported volumes of the current regulatory period. The 2% reduction factor on capacity revenues provides scope for improving results of operations of the transport company if cost reductions exceed the set amount, whereas the 4.5% reduction factor on commodity revenues provides scope for improving results of operations of the transport company if transported volumes grow more than the reduction factor. New capital expenditures in extension and expansion enable transport companies to increase the capacity revenue by a stated percentage in the regulatory period following the period in which new capital expenditures are incurred.

In addition, those capital expenditures give rise to a six year fixed increase in allowed commodity revenues. At the end of the first regulatory period, all transport cost components were recalculated and 50% of higher cost reductions with respect to established efficiency improvements were recognized to transport companies and 50% were transferred to customers. Once the allowed revenues are established, transport companies define individual tariffs to clients which are based on a charge for the capacity used at the entry location (border, fields, storage sites) and the capacity used at interconnection nodes with regional networks (divided into 17 zones) and on a charge for the capacity used at regional level, providing for discounts to those outgoing the network at less than 15 kilometers from the interconnection point between regional and national networks. A further charge (commodity charge) is related to the amounts of gas transported plus an annual fixed charge varying according to the delivery points. This tariff system regulated the four-thermal year period starting October 1, 2001 and ending on September 30, 2005.

With Resolution No. 166/2005, the Authority for Electricity and Gas revised the outlined tariff regime for the second regulatory period (October 1, 2005-September 30, 2008). The new tariff structure confirms the breakdown of the tariff into two components: capacity and commodity in a ratio of 70 to 30 and the entry-exit model for the determination of the capacity component on the national pipeline network, already present in the previous tariff regime established by Resolution No. 120/2001. The major new elements of the new regime are the following: (i) a reduction of the rate of return of capital employed in transport activities from 7.94% to 6.7% (pre-tax); (ii) a new set of incentives for new capital expenditure. In the previous regime, the return on upgrade and capacity expansion expenditure was 7.47% for one year only included in the calculation of the capacity component of the transport tariff and 4.98% for 6 years in the calculation of the commodity component. The new tariff structure provides an additional rate of return depending on the type of expenditure on the return rate recognized for capital employed:

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from a minimum of 1% for safety measures that do not increase transport capacity, applied for 5 years, to a maximum of 3% for expenditure that increases capacity at entry points into the national network, applied for 15 years. The additional return is part of the determination of the maximum allowed revenues in the calculation of the capacity component of the tariff and therefore is not influenced by changes in volumes transported; (iii) the updating by means of a price cap mechanism of the allowed revenues the transport undertaking is entitled to and the annual recalculation of the portion of allowed revenues relating to costs incurred for capital expenditure. This price cap mechanism applies to operating costs and amortization charges (previously it applied to all the allowed revenues). The annual rate of recovery of productivity was confirmed at 2%; this is used to reduce the effect of changes in the consumer price index on the updating of the preceding years allowed revenues; instead the preset annual rate of change of productivity recovery for the updating of the commodity component of the tariff was reduced from 4.5% to 3.5% of; and (iv) confirmation of the tariff reduction for start ups (construction/upgrade of combined cycle plants for power generation) and for off take in low season periods (from May 1 to October 31) already contained in Decisions No. 5/2005 and 6/2005 which updated the previous tariff regime. The companies active in the field of gas transport submit their tariff proposals to the Authority who grants approval, within the first quarter of each calendar year.

Network code. With Resolution No. 75 of July 1, 2003, the Authority for Electricity and Gas approved Snam Rete Gas Network Code, which defines rules and regulations for the operation and management of the transmission network. The Network Code, in accordance with Legislative Decree No. 164/2000, is based on the criteria set by the Authority for Electricity and Gas with Resolution No. 137/2002, aimed at guaranteeing equal access to all customers, maximum impartiality and neutrality in transport and dispatching activities. The Network Code regulates entitlement of transport capacity, obligations of transporter and customer and the procedures through which customers can sell capacity to other users. Transport capacity at entry points in the national gasline network (point of interconnection with import gas lines) is assigned on an annual basis and can last up to five thermal years.

Entities eligible to be assigned transport capacity on a multi-year basis are those having multi-year import contracts within the limit of their daily average contract volumes. Priority criteria envisage that available capacity is assigned first to parties in multi-year import contracts containing take-or-pay clauses signed before August 10, 1998 (date of coming in force of European Directive 98/30/CE). If requests for capacity in a given thermal year are higher than available capacity, a pro-rata mechanism is applied in compliance with the aforementioned priority.

Parties in annual or shorter import contracts and parties in multi-year import contracts are entitled to annual capacity conferrals corresponding to maximum daily contract volumes and the difference between maximum daily contract volumes and average daily contract volumes, respectively. Available transport capacity is assigned first to parties in annual import contracts and parties in multi-year import contracts. If requests for capacity in a given thermal are higher than available capacity, a pro-rata mechanism is applied in compliance with the aforementioned priority.

Eni filed a claim against this decision with the Regional Administrative Court of Lombardy, which was partially accepted with a decision of December 2004. The Authority filed a claim against this decision with the Council of State and informed Eni on February 19, 2005. This proceeding is still pending.

Adoption of guarantees for free access to LNG regasification services and rules for the regasification code. With Resolution No. 167 of August 1, 2005, the Authority for Electricity and Gas published the criteria for access to LNG regasification services. The Decision also defines criteria for the allocation of regasification capacity. In particular it establishes that take-or-pay contracts entered into before 1998, as in the case of Eni, are awarded priority access limited to the minimum amount of volumes that have been regasified in the period starting from thermal year 2001-2002. Eni filed a claim against this decision with the Regional Administrative Court of Lombardy that rejected the claim. Subsequently, Eni filed a claim with a higher degree administrative court.

Tariffs criteria for the use of LNG terminals in the third regulatory period. The Authority for Electricity and Gas has set the criteria regulating the tariffs for the use of LNG terminals in the 3^rd regulatory period (October 2008-September 2012) with its ARG/gas 92/08 resolution.

The Regulatory Asset Base (RAB) is calculated with the re-valuated historical cost methodology. The yearly adjustment of revenues and tariffs will follow the same methodologies applied in the previous regulatory period, except for depreciation that will be adjusted on a yearly basis and excluded from the price cap mechanism. The allowed rate of return (WACC) on Regulatory Asset Base has been set equal to 7.6% in real terms pre tax. Furthermore, it established an additional remuneration, up to 3% above WACC, for new capital expenditures for a maximum of 16 years. Operating costs will be adjusted every year taking into account inflation and efficiency gains (X- factor) set by the Authority at 0.5% in real terms.

The ARG/gas 92/08 resolution also established that the allocation of reference revenues between regasification capacity and the commodity component is fixed at 90:10 (compared to 80:20 ratio in the second regulated period).

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Gas not recorded in accounts on the natural gas transport networks in the 2004-2006 period. The Italian Authority for Electricity and Gas with the Resolution VIS 8/09, has completed the preliminary investigation on the gas not recorded in accounts started with Resolution VIS 41/08 "Preliminary investigation on the correct application of the provisions concerning gas not recorded in accounts on the natural gas transport networks in the 2004-2006 period". Based on the results of this preliminary investigation, future actions to be implemented by Snam Rete Gas were defined in order to improve the process of calculation of natural gas. The total amount to be recognized to the company, with regard to higher costs incurred for the purchase of fuel gas in the thermal years 2005-2006 and 2006-2007, was also set at euro 45 million. The Authority also established to determine in subsequent resolutions the additional costs incurred by the company for the thermal years 2007-2008 and 2008-2009.

Distribution

Distribution is the activity of delivering natural gas to residential and commercial customers of urban centers through low pressure networks. Distribution is considered a public service operated in concession and is regulated on the basis of Law Decree No. 164/2000.

Distribution tariffs. With Resolution No. 159/2008, the Authority for Electricity and Gas defined a new methodology for determining revenues for natural gas distribution activity. Starting from January 1, 2009 and for the duration of four-year regulated period, i.e. until 2012, the resolution provides for the recognition of total revenues for each regulated year amounting to a value that the Authority will set at the time of approving the operators’ requests for distribution tariffs and defined as Total Revenue Constraint (TRC), representing the maximum remuneration recognized by the Authority to each operator for covering costs borne.

In previous years, revenues were determined by applying tariffs set by the Authority to volumes actually distributed to selling companies in the relevant year. The resolution also provides for any positive or negative difference between TRC and revenues resulting from invoices for actually distributed volumes to be regulated through an equalization device making use of credit/debit cards lodged with the Electricity Equalization Exchange.

As a result of the new mechanism, revenues are no longer related to the seasonality of volumes distributed but are constantly apportioned during the year. The introduction of this new mechanism does not cause a decline in total revenues on a yearly basis.

 

Refining and Marketing of Petroleum Products

Refining. Under Decree No. 112, companies that seek to establish refining operations in Italy or to expand the capacity of existing refining operations must obtain an operating concession from the relevant Region, while companies that seek to build or operate new plants that do not increase refining capacity must obtain an authorization from the relevant Region. Management expects no material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium-term.

Service stations. Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 348 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, significantly changed Italian regulation of service stations. The decree replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities. Legislative Decree No. 112/1998 confers the power to grant concessions for the construction and operation of service stations on highways to Regions. Decree No. 32 also requires that contracts between license holders and service station operators have a duration of not less than six years and be drafted in accordance with arrangements agreed by the relevant trade group of license holders and the union representatives for the service station operators. 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 goal of renewing the Italian distribution network, Law No. 57/2001 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 decree was issued on October 31, 2001 and established 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.

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.

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With a recommendation approved at its meeting of January 18, 2007 and submitted to the Government and the Regions, the Italian Antitrust Authority requested the elimination of local constraints to the opening up of the fuel distribution outlets aimed at increasing competition and reducing retail prices. Specifically, the Authority urged the following measures in order to enhance the level of competition in the sector of retail marketing of fuels: (i) the development of the marketing of fuels by large retailers (supermarkets, large chain-stores, etc.); (ii) the elimination of administrative constraints to the opening of new service stations; (iii) a liberalization of opening hours; and (iv) transparency for consumers, identifying any useful tools for proper information on actual prices imposed by operators in each outlet. Currently, Eni is unable to forecast a time frame for this matter. Implementation of any of these suggested measures could enhance the level of competition in the retail marketing of fuels, leading to a reduction in retail margins for all operators.

Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 ("Decree 22/2001") enacting European Directive No. 98/1993 (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 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 22/2001 states that compulsory stocks are determined each year by a decree of the Minister of Productive Activities 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.

At December 31, 2008 Eni owned 6.3 mmtonnes of oil products inventories, of which 4.4 mmtonnes as "compulsory stocks", 1.5 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 (at December 31, 2008) were held in term of crude oil (30%), light and medium distillates (47%), fuel oil (19%) and other products (4%) and they were located throughout the Italian territory both in refineries (72%) and in storage sites (28%).

 

Recent tax development

The "Treaty of Friendship" between the Republic of Italy and Libya was enacted by Italy’s upper house on February 3, 2009 and is about to be published shortly. This law under Article No. 3 has introduced a supplemental tax rate applicable to taxable income of such individual companies that engage in the exploration and production of hydrocarbons, where fixed assets, including both tangible and intangible assets and investments dedicated to oil and gas operations exceed 33% of their respective items in the balance sheet, also having a market capitalization in excess of euro 20 billion. This supplemental tax is due whenever taxes currently payable represent less than 19% of taxable income and is to be determined as the lower of the amount of income taxes up to 19% of taxable income and the amount resulting from applying a certain set of decreasing rates to companies’ net equity as determined from individual financial statements. This supplemental tax rate is due for 2009 and following years up to 2028. Eni believes that the parent company Eni Spa will likely fall within the scope of this supplemental tax rate based on the criteria set by the law to identify the persons subject to the new tax rate and the conditions regulating its enactment. According to management’s estimates the new supplemental tax rate will cause the Company to incur additional tax payable amounting to approximately euro 300 million for the full years 2009, 2010 and 2011. In subsequent years this expense will amount to approximately euro 180 million per year. The Company is planning to file recourse against this law.

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in 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 ("Article 81" and "Article 82", respectively being the result of the new denomination of former Articles 85 and 86) and EU Merger Control Regulation No. 4064 of 1989 ("EU Regulation 4064"). Article 81 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 82 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among member states. EU Regulation 4064 sets certain 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 81 and 82 of the Treaty. In order to simplify the procedures required of undertakings in case of concentration, the new regulation substitutes the obligation to inform the Commission with a declaration that such concentration does not infringe the Treaty. In addition, the burden of proving an infringement of Article 81(1) or of Article 82 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings

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claiming the benefit of Article 81(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 81 and 82 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:

National courts shall have the power to apply Articles 81 and 82 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 81 or of Article 82 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 81 and 82 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 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 "Antitrust Law"). In accordance with the EU competition rules, the 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 Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the 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, but no one individual property is material to Eni as a whole. See "Exploration & Production" above for a description of Eni’s 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, 2008, there were 283 fully consolidated subsidiaries and 80 associates that were accounted for under the equity or cost method. For a list of subsidiaries of the Company, see "Exibit 8 – List of Eni’s fully consolidated subsidiaries for year 2008".

 

 

Item 4A. UNRESOLVED STAFF COMMENTS

None.

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.

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.

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Executive Summary

Eni reported net profit of euro 8,825 million in 2008, representing a decrease of 11.8% compared to 2007.

Operating profit in 2008 amounted to euro 18,641 million, down 1.2% from 2007 mainly reflecting the lower operating profit reported by Eni’s downstream businesses as the Refining & Marketing, Petrochemicals and Gas & Power segments reported lower operating profit by euro 1,752 million, euro 896 million and euro 194 million, respectively. These reductions were partly offset by improved operating profit recorded by:

(i)		the Exploration & Production segment which reported an increase in operating profit of euro 2,627 million. This improvement was mainly driven by higher hydrocarbon realizations in dollar terms; and
(ii)		the Engineering & Construction segment which reported an increase in operating profit of euro 208 million. This improvement mainly reflected favorable market trends.

Eni’s Group results for the year were reduced by higher finance charges, up euro 681 million, and higher income taxes, up euro 473 million. These negative factors were partly offset by higher profit (up euro 130 million) from non consolidated entities that are accounted for under the equity or the cost method.

Net cash provided by operating activities amounted to euro 21,801 million, including proceeds on advances received from the partner Suez (euro 1,552 million) following the signing of a number of long-term gas and electricity supply contracts, and cash from divestments (euro 1,160 million) were used to fund the majority of cash outflows relating to: (i) capital and exploratory expenditures totaling euro 14,562 million; (ii) the acquisition of assets and investments (euro 4,305 million which include cash and finance debt acquired as part of the purchased companies); and (iii) dividend distribution to Eni’s shareholders and Eni share repurchases for a total cash return to Eni shareholders of euro 5,688 million, as well as minority dividend payments and share repurchases relating mainly to the listed subsidiaries Snam Rete Gas SpA and Saipem SpA (totaling euro 288 million).

As of December 31, 2008 net borrowings amounted to euro 18,376 million, representing a euro 2,049 million increase from 2007. This increase mainly reflected the large amount of capital expenditures and acquisitions executed in the year which was only partially funded with cash flows from operations.

On the basis of the results achieved, Eni’s management proposed to the Annual Shareholders’ Meeting the distribution of a dividend of euro 1.30 per share, of which euro 0.65 had been paid as interim dividend in September 2008. This dividend is in line with 2007 (euro 1.30 per share) and was approved by the Annual Shareholders’ Meeting on April 30, 2009.

Eni’s oil and gas production for the year (on an available for sale basis) increased by 3.8% to 1,748 KBOE/d. This performance was mainly due to:

(i)		the contribution of assets acquired in the Gulf of Mexico, Congo and Turkmenistan (up 62 KBOE/d compared to 2007); and
(ii)		continuing production ramp-up in Angola, Congo, Egypt, Pakistan and Venezuela.

These positive factors were offset in part by:

(i)		mature field declines;
(ii)		planned and unplanned facility downtime in the North Sea;
(iii)		hurricane-related impacts in the Gulf of Mexico (down 11 KBOE/d); and
(iv)		lower entitlements in certain Production Sharing Agreements (PSAs) and similar contractual schemes (down 37 KBOE/d compared to 2007) due to higher oil prices. Under such contracts, Eni is entitled to fixed monetary amounts to recover the expenses incurred for the development of the relevant properties and as a consequence of higher oil prices, the volumes that are necessary to cover the same amount of expenses are lower.

On October 31, 2008, the international partners of the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium and the Kazakh authorities signed the final agreement implementing the new contractual and governance framework of the Kashagan project, based on the Memorandum of Understanding signed on January 14, 2008. For a more detailed discussion of this project see "Item 4 – Exploration & Production – Kazakhstan".

Worldwide gas sales in 2008 amounted to 104.23 BCM, up 5.3% from 2007 due to growth achieved in international markets (up 8.53 BCM), particularly in the main European markets, and the contribution of the acquisition of Distrigas that was completed in October 2008 (up 5.23 BCM). These increases were offset in part by lower sales to the domestic market (down 3.26 BCM) as a result of the economic downturn and stronger competitive pressure.

Capital expenditures in 2008 amounted to euro 14,562 million (euro 10,593 million in 2007), of which 84% related to the Exploration & Production, Gas & Power and Refining & Marketing segments, and mainly regarded:

(i)

development activities (euro 6,429 million) mainly in Kazakhstan, Egypt, Angola, Congo and Italy;

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(ii)		exploration projects (euro 1,918 million) of which 93% was spent outside Italy, primarily in the United States, Egypt, Nigeria, Angola and Libya;
(iii)		the purchase of proved and unproved property (euro 836 million) related mainly to the extension of mineral rights in Libya following an agreement signed in October 2007 with the state oil company NOC and the purchase of a 34.81% interest in the Abo project in Nigeria;
(iv)		development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 1,130 million and euro 233 million, respectively) and upgrading of natural gas import pipelines to Italy (euro 233 million);
(v)		ongoing construction of combined cycle power plants (euro 107 million);
(vi)		the Refining & Marketing division (euro 965 million) for projects aimed at upgrading the conversion capacity and flexibility of refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, building of new service stations and upgrading of existing ones; and
(vii)		upgrading of the fleet used in the Engineering & Construction division (euro 2,027 million).

In 2008 Eni successfully executed a number of strategic acquisitions and deals that are intended to strengthen its competitive position in its main markets. Total finance requirements for these acquisitions amounted to euro 4,305 million and mainly related to the acquisition of a 57.243% stake in Distrigas NV, the completion of the acquisition of Burren Energy Plc, the purchases of certain upstream properties and gas storage assets, mainly in Algeria, in the North Sea and in India, as well as other investments in non-consolidated entities.

In the 2009-2012 four-year period, Eni expects to invest approximately euro 48.8 billion in capital expenditures and exploration projects to implement its growth strategy. For further details see "Item 5 – Management’s Expectations of Operations".

 

Trading Environment

Whenever used in Item 5, "Margin" means 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.

		2006		2007		2008

Average price of Brent dated crude oil in U.S. dollars (1)		65.14		72.52		96.99
Average price of Brent dated crude oil in euro (2)		51.86		52.90		65.93
Average EUR/USD exchange rate (3)		1.256		1.371		1.471
Average European refining margin in U.S. dollars (4)		3.79		4.52		6.49
Euribor - three month euro rate % (3)		3.1		4.3		4.6

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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.

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 2008, Eni’s results were achieved in a trading environment characterized by a significant increase in Eni’s oil and gas realizations (up 28.1% on average) on the backdrop of a favorable oil scenario until the month of September. Subsequently Brent prices experienced a steep decline from mid-year levels as a consequence of the financial crisis and the global economic downturn that has reduced energy demand. On average yearly Brent prices were up 33.7% from 2007. Management expects that oil prices will remain weak throughout the year 2009 as the economic downturn is expected to continue impacting global demand for oil, products and natural gas. Based on current market trends, management believes that there is still uncertainty about the timing of a recovery in global energy demand and in Brent prices. See "Item 3 – Risk Factors" for a description of sensitivity of Eni’s results of operations to changes in crude oil prices. In 2009 weak energy demand is expected to impact the Company’s gas sales in its downstream marketing business, particularly on the Italian market where the economic slowdown is expected to weigh heavily on gas demand. See "Item 5 – Management’s Expectations of Operations" below.

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In 2008, margins on gas sales were affected by an unfavorable trading environment also reflecting exchange rate movements.

In 2008, refining activities were positively influenced by a strong margin environment (Brent refining margins were up 43.6%, to 6.49 $/BL). This positive trend was partly offset by a negative impact associated with narrowing differentials between light and heavy crudes that reduced the profitability of Eni’s complex refineries. This negative trend has been continuing in the first quarter of 2009 as market availability of heavy crudes has been impacted by OPEC cuts.

In 2008, a steep decline was registered in selling margins of commodity chemicals due to higher supply costs of oil-based feedstock that were not fully recovered in sales prices and weak demand. In the first quarter of 2009, results of the petrochemicals operations were negatively impacted by the economic downturn that affected demand for commodity chemicals.

In 2008, the market environment was particularly favorable in the Engineering & Construction business as a result of the strong order pattern experienced throughout the year on the backdrop of the strong oil cycle. Management believes that falling oil prices, weak energy demand and tight financial markets will reduce the investment plans of oil companies thus affecting results of operations of oilfield contractors, even though with a time lag with respect to the oil companies’ investing decisions taking into account existing orders. In the first quarter 2009, Eni’s Engineering & Construction business reported positive results due to completion of orders in backlog and revenues associated with multi-years orders. Management expects that assuming that the Company will not incur any material order delay or cancellation, full-year results of the Engineering & Construction business will be positive in the full year 2009. In the medium-term, assuming a reduction in orders coming from oil companies, the results of the Engineering & Construction business will be supported by its ability to manage complex projects and large presence in strategic countries that make the business less vulnerable to the oil cycle.

In 2008, Eni’s results were negatively affected by the 7.3% appreciation of the euro against the dollar (based on the yearly average exchange rates).

 

Key Consolidated Financial Data

		2006		2007		2008

(euro million)

Net sales from operations				86,105		87,256		108,148
Operating profit				19,327		18,868		18,641
Net profit attributable to Eni				9,217		10,011		8,825
Net cash provided by operating activities				17,001		15,517		21,801
Capital expenditures				7,833		10,593		14,562
Acquisitions of investments and businesses				95		9,665		4,019
Shareholders’ equity including minority interest at year end				41,199		42,867		48,510
Net borrowings at year end (1)				6,767		16,327		18,376
Net profit per share attributable to Eni (basic and diluted)		(euro per share)		2.49		2.73		2.43
Dividend per share		(euro per share)		1.25		1.30		1.30
Net borrowings to total shareholders’ equity ratio including minority interest (leverage) (1)				0.16		0.38		0.38

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(1)

For a discussion of the usefulness of and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see "Liquidity and Capital Resources – Financial Conditions" below.

 

Critical Accounting Estimates

The Company’s Consolidated Financial Statements are prepared in accordance with IFRS as issued by the IASB. These require 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 reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of

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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 significantly 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 with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Although there are authoritative guidelines regarding the engineering 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 and 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 will be classified as proved undeveloped. Volumes will subsequently be reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings will 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 as regards the initial estimate and, in the case of Production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered.

Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense. Depreciation 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 impairments.

 

Impairment of assets

Eni assesses its tangible assets and intangible assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate the carrying values of the assets are not recoverable. Such 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 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.

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 costs and 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 reviews 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. The estimated future level of production is based on assumptions relating to future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.

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Oil, natural gas and petroleum products prices used to quantify 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, market demand and to 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 such assets at the cash generating unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value below its carrying amount. In particular, goodwill impairment is based on the determination of the fair value of each cash generating unit to which goodwill can be attributed on a reasonable and consistent basis.

A cash generating unit is the smallest aggregate unit 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 on a pro-rata basis 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 increased 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 acquisitions, typically engages an independent appraisal firm 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 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 Decree No. 471/1999 of the Ministry of Environment concerning the remediation of contaminated sites;

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(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, as against other potentially responsible parties with respect to such litigations and the possible insurance recoveries.

 

Employee benefits

Defined benefit plans and other long-term benefits 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 pensions and other post-retirement benefits 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 rates of annuity contracts and rates of return on high quality fixed-income investments. 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, based principally on available actuarial data; 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, equities 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 10% of the greater 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 effect of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to profit or loss in their entirety.

 

Contingencies

In addition to accruing the estimated costs for environmental liabilities, asset retirement obligations 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 appropriate amounts for accrual is a complex estimation process that includes subjective judgments.

 

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, 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. Requests for additional income, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them.

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2006-2008 Group Results of Operations

Overview of the Profit and Loss Account for Three Years Ended December 31, 2006, 2007 and 2008

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

Year ended December 31,

		2006		2007		2008

Net sales from operations		86,105			87,256			108,148
Other income and revenues (1)		783			827			720
Total revenues		86,888			88,083			108,868
Operating expenses		(61,140	)		(61,979	)		(80,412	)
Depreciation, depletion, amortization and impairments		(6,421	)		(7,236	)		(9,815	)
OPERATING PROFIT		19,327			18,868			18,641
Finance income (expense)		161			(83	)		(764	)
Income from investments		903			1,243			1,373
PROFIT BEFORE INCOME TAXES		20,391			20,028			19,250
Income taxes		(10,568	)		(9,219	)		(9,692	)
NET PROFIT		9,823			10,809			9,558
Attributable to:
- Eni		9,217			10,011			8,825
- minority interest		606			798			733

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(1)

i

Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income.

The table below sets forth certain income statement items as a percentage of net sales from operations for the periods indicated.

Year ended December 31,

		2006		2007		2008

Operating expenses		71.0			71.0			74.4
Depreciation, depletion, amortization and impairments		7.5			8.3			9.1
OPERATING PROFIT		22.4			21.6			17.2

2008 compared to 2007. Net profit pertaining to Eni in 2008 was euro 8,825 million, representing a decrease of euro 1,186 million from 2007, down 11.8%. This decrease was affected by the following negative factors.

(i)		Higher finance expenses (up euro 681 million) were recorded mainly reflecting losses of euro 577 million incurred on fair value valuation of certain derivative financial instruments that do not meet the formal criteria to be qualified as hedges under IFRS. Additionally, higher finance charges on finance debt were incurred as a result of increased average net borrowings and higher interest rates on euro denominated finance debt (Euribor up 0.3 percentage points) partially offset by lower interest rates on dollar loans (Libor down 2.4 percentage points).
(ii)		An increase in income taxes of euro 473 million mainly due to increased income taxes currently payable recorded by subsidiaries in the Exploration & Production division operating outside Italy, partly offset by a positive adjustment to deferred taxation associated with new tax rules effective from January 1, 2008 applicable to Italian companies and Libyan activities (for more details on these items see "Taxation" below).
(iii)		A decrease in operating profit of euro 227 million, mainly due to the weaker operating performance reported by Eni’s downstream businesses, partly offset by an improved performance in the Exploration & Production segment driven by the strong pricing environment experienced until September 2008.

These negative factors were partly offset by higher profit from non consolidated entities that are accounted for under the equity or the cost method, up euro 130 million.

2007 compared to 2006. Net profit pertaining to Eni in 2007 was euro 10,011 million with a euro 794 million increase from 2006 (8.6%), primarily due to:

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(i)

lower income taxes (down euro 1,349 million) mainly reflecting:

-

an adjustment to deferred tax assets and liabilities for Italian subsidiaries amounting to euro 394 million relating to certain amendments to the Italian tax regime, including a lower statutory tax rate, enacted by the 2008 Budget Law, and

-

the circumstance that in 2006 deferred tax liabilities were recorded due to changes in the fiscal regimes of Algeria and the United Kingdom and charges regarding disputes on certain tax matters (totaling euro 347 million);

(ii)		an increase in net income from investments of euro 340 million, mainly due to net gains on the divestment of interests in certain associates of the Engineering & Construction segment and higher earnings from entities that are accounted for under the equity or the cost method; and
(iii)		a gain of euro 83 million deriving from a reduction in the provision accrued for post-retirement benefits for Italian employees following changes in applicable regulation (the so called curtailment of the provision for post retirement benefits). Effective January 1, 2007, Italian laws modified Italian post-retirement benefits scheme from a defined benefit plan to a defined contribution one. Following this, the provision for Italian employees was reassessed to take account of the exclusion of future salaries and relevant increases from actuarial calculations.

These positive factors were partly offset by a lower operating profit (down euro 459 million) mainly in the Exploration & Production segment (euro 1,792 million) and higher net finance charges (euro 244 million).

 

Discontinued Operations

Discontinued operations in 2008, 2007 and 2006 were immaterial.

 

Analysis of the Line Items of the Profit and Loss Account

a) Total Revenues

Eni’s total revenues were euro 108,868 million, euro 88,083 million and euro 86,888 million in 2008, 2007 and 2006, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations amounted to euro 108,148 million, euro 87,256 million and euro 86,105 million in 2008, 2007 and 2006, respectively, and its other income and revenues totaled euro 720 million, euro 827 million and euro 783 million, respectively, in these periods.

Net sales from operations

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

Year ended December 31,

		2006		2007		2008

Exploration & Production		27,173			27,278			33,318
Gas & Power		28,368			27,633			36,936
Refining & Marketing		38,210			36,401			45,083
Petrochemicals		6,823			6,934			6,303
Engineering & Construction		6,979			8,678			9,176
Other activities		823			205			185
Corporate and financial companies		1,174			1,313			1,331
Impact of unrealized intragroup profit elimination								75
Consolidation adjustment (1)		(23,445	)		(21,186	)		(24,259	)
NET SALES FROM OPERATIONS		86,105			87,256			108,148

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(1)

Intra-group sales are included in net sales from operations in order to give a more meaningful indication about the volume of the activities to which sales from operations by segment may be related. The most substantial intra-group sales are recorded by the Exploration & Production segment. See Note 36 to the Consolidated Financial Statements for a breakdown of intra-group sales by segment for the reported years.

2008 compared to 2007. Eni’s net sales from operations for 2008 (euro 108,148 million) were up euro 20,892 million from 2007, or 23.9%, primarily reflecting higher realizations on oil, products and natural gas in dollar terms and higher natural gas sales volumes due to the acquisition of Distrigas. These positives were partially offset by the impact of 7.3% appreciation of the euro versus the dollar on average during the period.

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Revenues generated by the Exploration & Production division (euro 33,318 million) increased by euro 6,040 million, or 22.1%, mainly due to higher realizations of oil and gas in dollar terms (oil up 24.2%, natural gas up 47.8%). Eni’s liquid realizations (84.05 $/BL) were affected by the settlement of certain commodity derivatives relating to the sale of 46 mmBBL in the year, with a negative impact of 4.13 $/BL (for a more detailed explanation, see the discussion on results of the Exploration & Production division below). Revenue increases in 2008 were also driven by higher production volumes sold (up 20.1 mmBOE, or 3.3%). These improvements were partially offset by the appreciation of the euro against the dollar.

Revenues generated by the Gas & Power division (euro 36,936 million) increased by euro 9,303 million, up 33.7%, mainly due to higher average natural gas prices reflecting trends in energy parameters to which gas prices are contractually indexed, as well as increased international sales due to the contribution of the acquisition of Distrigas and organic growth recorded in European target markets, partly offset by lower volumes sold in Italy due to the impact of the economic downturn and competitive pressure.

Revenues generated by the Refining & Marketing division (euro 45,083 million) increased by euro 8,682 million, up 23.9%, mainly due to higher international prices for oil and products and higher product volumes sold (up 1.1%) partly offset by the impact of the appreciation of the euro over the dollar.

Revenues generated by the Petrochemical division (euro 6,303 million) decreased by euro 631 million, down 9.1%, mainly reflecting a decline in volumes sold (down 15%) due to weaker demand.

Revenues generated by the Engineering & Construction division (euro 9,176 million) increased by euro 498 million, up 5.7%, due to increased activity levels.

2007 compared to 2006. Eni’s net sales from operations (revenues) for 2007 (euro 87,256 million) were up euro 1,151 million, a 1.3% increase from 2006, primarily reflecting higher activity levels in the Engineering & Construction division and higher realizations on oil and natural gas in dollar terms, partially offset by the impact of the appreciation of the euro versus the dollar (up 9.2%), a decline in hydrocarbon production sold and lower products volumes sold, as well as the negative trends of energy parameters to which gas prices are contractually indexed in the Gas & Power division.

Revenues generated by the Exploration & Production division (euro 27,278 million) increased by euro 105 million, up 0.4%, mainly due to higher oil realizations in dollars (up 12.7%), partially offset by to the impact of the appreciation of the euro versus the dollar and lower hydrocarbon production sold (down 14.7 mmBOE, or 2.2%).

Revenues generated by the Gas & Power division (euro 27,633 million) declined by euro 735 million, down 2.6%, mainly due to lower average natural gas prices reflecting negative trends in energy parameters to which gas prices are contractually indexed and a negative shift in the mix of volumes sold.

Revenues generated by the Refining & Marketing division (euro 36,401 million) declined by euro 1,809 million, down 4.7%, mainly due to the effect of the appreciation of the euro over the dollar and lower product volumes marketed (down 0.98 mmtonnes), partly offset by higher international prices for oil and products.

Revenues generated by the Petrochemical division (euro 6,934 million) increased by euro 111 million from 2006, up 1.6%, reflecting mainly the fact that performance in 2006 was adversely impacted by the unplanned downtime of the Priolo craker and downstream plants as a consequence of an accident that occurred at the nearby refinery in April 2006, resulting in a recovery in production volumes sold (up 4.5%). Commodity chemicals prices were also up by 4% on average.

Revenues generated by the Engineering & Construction division (euro 8,678 million) increased by euro 1,699 million, up 24.3%, due to increased activity levels in the Offshore and Onshore construction businesses.

Revenues generated by the Other activities division decreased by euro 618 million to euro 205 million, due to the intragroup divestment of the Porto Torres plant for the production of basic petrochemical products to Polimeri Europa, which occurred in 2007.

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b) Operating Expenses

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

Year ended December 31,

		2006		2007		2008

(euro million)

Purchases, services and other		57,490		58,179		76,408
Payroll and related costs		3,650		3,800		4,004
Operating expenses		61,140		61,979		80,412

2008 compared to 2007. Operating expenses for 2008 (euro 80,412 million) were up euro 18,433 million from 2007, or 29.7%, reflecting primarily higher purchase prices of natural gas as well as higher prices for refinery and petrochemical feedstock due to market trends in oil commodities and rising dollar-denominated operating expenses in the Exploration & Production division due to full consolidation of acquired assets and the impact of sector-specific inflation, mainly in the first nine months of the year. Those increases were partly offset by the appreciation of the euro over the dollar.

Payroll and related costs (euro 4,004 million) were up euro 204 million, or 5.4%, mainly due to higher unit labor cost in Italy and an increase in the average number of employees outside Italy that was recorded mainly in the Exploration & Production division, following the consolidation of acquired assets, as well as increased personnel in the Engineering & Construction business due to higher volumes. In addition in 2007 a non-recurring gain of euro 83 million was recorded in connection with the curtailment of the provision for post-retirement benefits relating to obligations towards Italian employees. These increases were partly offset by exchange rate translation differences.

2007 compared to 2006. Operating expenses for 2007 (euro 61,979 million) increased by euro 839 million from 2006, up 1.4%, mainly due to higher purchase prices for refinery and petrochemical feedstock, as well as rising dollar-denominated operating expenses in the Exploration & Production segment, partly offset by the appreciation of the euro against the dollar. Purchases, services and other include: (i) an expense of euro 91 million relating to a provision against ongoing antitrust proceedings before the European authorities net of a gain deriving from the reversal of a previously accrued provisions upon favorable developments in certain antitrust proceedings; and (ii) environmental charges (euro 327 million), recognized particularly by Syndial and the Refining & Marketing segment.

Payroll and related costs (euro 3,800 million) increased by euro 150 million, up 4.1%, mainly due to higher unit labor costs and an increase in the average number of employees outside Italy in the Engineering & Construction segment related to higher activity levels and in the Exploration & Production segment due to the acquisition of assets. These increases were offset in part by exchange rate translation differences and a gain (euro 83 million) deriving from the curtailment of the provision for post-retirement benefits existing at year-end 2006 related to obligations towards Italian employees.

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c) Depreciation, Depletion, Amortization and Impairments

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

Year ended December 31,

		2006		2007		2008

(euro million)

Exploration & Production (1)		4,646			5,483			6,733
Gas & Power		687			687			742
Refining & Marketing		434			433			430
Petrochemicals		124			116			117
Engineering & Construction		195			248			335
Other activities		6			4			3
Corporate and financial companies		70			68			76
Impact of unrealized intragroup profit elimination (2)		(9	)		(10	)		(14	)
Total depreciation, depletion and amortization		6,153			7,029			8,422
Impairments		268			207			1,393
		6,421			7,236			9,815

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(1)	i	Exploratory expenditures of euro 2,057 million, euro 1,778 million and euro 1,075 million are included in these amounts relative to the years 2008, 2007 and 2006, respectively.
(2)	i	This item concerned mainly intra-group sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end of the period.

2008 compared to 2007. In 2008 depreciation, depletion and amortization charges (euro 8,422 million) increased by euro 1,393 million, up 19.8%, mainly in the Exploration & Production segment (up euro 1,250 million). The higher charges incurred in the Exploration & Production segment were associated with: (i) increased development amortization charges reflecting consolidation of assets acquired and increased expenditures to develop new fields and to sustain production performance at mature fields; and (ii) higher exploration expenditures that are expensed in full when incurred (euro 420 million). These increases were partly offset by the appreciation of the euro against the dollar.

In 2008, impairments (euro 1,393 million) mainly regarded proved and unproved mineral properties in the Exploration & Production division due to changes in the regulatory and contractual framework for certain properties, cost increases, as well as a changed pricing environment. The value of number of plants and equipment in the Refining & Marketing and Petrochemical divisions were impaired due to a downward revision of the future profitability associated with worsening expectations for the future pricing/margin environment. For more information about the main assumptions used by the Company in testing the recoverability of the carrying amounts of its property, plant and equipment see "Note 8 to the Consolidated Financial Statements".

2007 compared to 2006. In 2007 depreciation, depletion and amortization charges (euro 7,029 million) increased by euro 876 million, or 14.2%, from 2006 mainly in the Exploration & Production segment (up euro 837 million) related to higher exploratory expenditures (euro 703 million), the consolidation of activities acquired in the Gulf of Mexico and Congo and the impact on amortization charges of an estimated update of asset retirement obligations for certain Italian and U.S. fields carried out in the preparation of 2006 consolidated financial statements, offset in part by exchange rate differences.

In 2007 impairment charges amounted to euro 207 million mainly regarding mineral assets in the Exploration & Production segment and plants and equipment in the Refining & Marketing segment.

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d) Operating Profit by Segment

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

Year ended December 31,

		2006		2007		2008

(euro million)

Exploration & Production		15,580			13,788			16,415
Gas & Power		3,802			4,127			3,933
Refining & Marketing		319			729			(1,023	)
Petrochemicals		172			74			(822	)
Engineering & Construction		505			837			1,045
Other activities		(622	)		(444	)		(346	)
Corporate and financial companies		(296	)		(217	)		(686	)
Impact of intragroup profits elimination		(133	)		(26	)		125
Operating profit		19,327			18,868			18,641

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

Year ended December 31,

		2006		2007		2008

(%)

Exploration & Production		57.3			50.5			49.3
Gas & Power		13.4			14.9			10.6
Refining & Marketing		0.8			2.0			(2.3	)
Petrochemicals		2.5			1.1			(13.0	)
Engineering & Construction		7.2			9.6			11.4
Group		22.4			21.6			17.2

Exploration & Production. Operating profit in 2008 amounted to euro 16,415 million, up euro 2,627 million from 2007, or 19.1%, reflecting higher realizations of oil and gas in dollar terms (oil up 24.2%; natural gas up 47.8%) and increased production sales volumes (up 20.1 mmBOE) due to the contribution of assets acquired in the Gulf of Mexico, Congo and Turkmenistan. These increases were partly offset by: (i) the recognition of significantly higher asset impairments (euro 810 million) due to changes in the regulatory and contractual framework for certain properties, cost increases, as well as a changed pricing environment; (ii) a negative impact on the translation to euro of the operating profit reported by subsidiaries whose functional currency is the U.S. dollar as the euro appreciated on average by 7.3%, with an estimated negative impact of euro 1,200 million; (iii) rising operating costs reflecting the impact of sector-specific inflation and higher amortization and depreciation charges, due to the consolidation of acquired assets and higher costs incurred to develop new fields and to sustain production performance at mature fields; and (iv) increased exploration expenses (euro 420 million on a constant exchange rate basis) in connection with higher geological and geophysical expenses and increased exploratory drilling expenditures that are expensed in full as incurred.

Liquids and gas realizations for the year increased on average by 28.1% in dollar terms driven by the strong market environment of the first nine months of the year. Average gas realizations were supported by a favorable trading environment and also a better sales mix reflecting higher volumes marketed on the basis of spot prices on the U.S. market. Eni’s liquids realizations for the full year amounted to 84.05 $/BL (up 24.2%) which benefited from narrowing differentials between heavy and light crude recorded in the year and were reduced by approximately 4.13 $/BL due to the settlement of certain commodity derivatives relating to the sale of 46 mmBBL in the year, as follows:

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These derivatives were entered into in 2007 to hedge future cash flows in the 2008-2011 period from the commodity risks on the sale of approximately 2% of Eni’s proved reserves as of 2006 year-end (125.7 mmBBL of which 79.7 million remained as of December 31, 2008) associated with certain asset purchases in the Gulf of Mexico and Congo that were executed in 2007.

Liquid realizations and the impact of commodity derivatives were as follows:

Full Year

		2007		2008

Sales volumes		(mmBBL)		366.7		364.3
Sales volumes hedged by derivatives (cash flow hedge)						46.0
Total price per barrel, excluding derivatives		($/BL)		67.7		88.17
Realized gains (losses) on derivatives						(4.1	)
Total average price per barrel				67.7		84.05

Operating profit in 2007 amounted to euro 13,788 million, down euro 1,792 million from 2006, or 11.5%, reflecting: (i) a negative impact due to the appreciation of the euro over the dollar (approximately euro 1,400 million), resulting in a decrease in revenues partly offset by lower operating expenses when translated into euro; (ii) lower production volumes sold (down 14.7 mmBOE) due to disruptions in Nigeria and Venezuela’s expropriation of the Dación oilfield assets; (iii) increased exploration expenses (euro 840 million on a constant basis) in connection with higher geological and geophysical expenses and increased exploratory drilling expenditures that are expensed in full as incurred; and (iv) rising operating costs reflecting the impact of sector-specific inflation and higher amortization and depreciation charges. These negatives were partly offset by higher realizations in dollars (oil up 12.7%, natural gas up 2.2%).

Gas & Power. Operating profit in 2008 amounted to euro 3,933 million, representing a euro 194 million decline compared to 2007, down 4.7%. This decrease reflected the following trends: (i) lower results from marketing operations in Italy as sales volumes of gas declined by 3.26 BCM due to the impact of lower gas demand and competitive pressures; (ii) gas selling margins were lower as they were affected by a rapid recovery in the U.S. dollar vs. the euro exchange rate in the last part of the year. The Company’s cost of gas supplies are linked to the current U.S. dollar vs. the euro exchange rate on a monthly basis, while gas selling prices are indexed to the U.S. dollar over a longer time period. As a result of this, in the last part of the year, gas purchase prices were affected by the recovery in the dollar leading to relatively higher purchase costs, while selling prices reflected the stronger euro recorded in the previous months; and (iii) the fact that certain provisions accrued in previous reporting periods were partially reversed through the 2007 profit and loss statement due to favorable developments in Italy’s regulatory framework. Those provisions were originally accrued due to the implementation of Resolution No. 248/2004 and following ones by the Italian Authority for Electricity and Gas regarding the indexation mechanism of the raw material cost in supply contracts to resellers and residential customers. These decreases were partly offset by an increase in operating results from regulated businesses in Italy.

Operating profit in 2007 amounted to euro 4,127 million, a euro 325 million increase compared to 2006, up 8.5%, due to: (i) a positive development with Italy’s regulatory framework on gas pricing to residential clients, reflecting a more favorable indexation mechanism of the raw material cost component as established by the Authority for Electricity and Gas with Resolution No. 79/2007, changing the regime in force in the first half of 2006 as established by Resolution No. 248/2004. Additionally, Eni fulfilled obligations provided by this resolution to renegotiate wholesale contracts based on the same indexation mechanism resulting in the partial reversal of provisions accrued in 2005 and in the first half of 2006 with respect to expected charges for these renegotiations; (ii) higher supply costs incurred in 2006 caused by a climatic emergency during the 2005-2006 winter; and (iii) an increase in operating result from transportation activities in Italy.

Refining & Marketing. The Refining & Marketing segment reported operating loss of euro 1,023 million, a euro 1,752 million decrease compared to 2007, mainly due to an inventory holding loss amounting to euro 1,199 million recognized in the 2008 profit and loss reflecting the impact of falling prices of crude oil and products on the year-end valuation of inventories according to the average-cost method of inventory accounting. In addition, impairment losses were recorded amounting to euro 299 million (down euro 241 million from 2007) as the recoverable amounts of certain refining plants and service stations were lower than their carrying amounts due to deteriorating profitability prospects on the backdrop of lowered expectations for the future trading environment. In 2007 an inventory holding gain of euro 658 million was recorded in connection with the impact of increasing prices of oil and refined products. 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.

In 2008, reported operating benefited from a positive underlying performance of the refining business reflecting a favorable trading environment, partly offset by lower throughputs due to planned and unplanned refinery

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downtime and higher refinery expenses associated with utilities and compliance with certain environmental regulations about carbon dioxide emissions. Marketing activities in Italy reported higher operating results due to a recovery in retail margins that were supported by a number of marketing initiatives and increased sales volumes as a result of an increased market share. The increase in wholesale business was due to higher margins.

Operating profit in 2007 amounted to euro 729 million, a euro 410 million increase compared to 2006, mainly due to: (i) an inventory holding gain amounting to euro 658 million recognized in 2007 profit and loss reflecting the impact of rising prices of crude oil and products on the valuation of year-end inventories using the average-cost method of inventory accounting. In 2006 an inventory holding loss of euro 215 million was recorded in connection with the impact of declining prices of oil and refined products. 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; and (ii) a provision accrued in 2006 against a fine imposed by the Italian Antitrust Authority for anti-competitive activities in the field of supplies of jet fuel (euro 109 million).

On the negative side, the refining business delivered a weaker operating performance on the backdrop of an unfavorable trading environment for Eni’s complex refineries, reflecting reduced discounts on sour crudes, lowering margins from any of the company’s secondary products (such as base lubricants and bitumen) as the prices for these products did not increase in proportion to the costs of the feedstock used to produce them and the appreciation of the euro over the dollar. Marketing activities in Italy also reported a lower operating profit mainly due to: (i) lower retail margins; and (ii) a decline in wholesale business result due to lower margins and volumes marketed (down 1.8%), the latter also reflecting unusually mild winter weather in the first quarter of 2007 causing lower sales of home-heating fuels.

Petrochemicals. In 2008 the Petrochemical segment reported an operating loss amounting to euro 822 million, a euro 896 million decrease compared to 2007, due to: (i) a steep decline in selling margins of commodity chemicals, reflecting higher supply costs of oil-based feedstock which were not fully transferred to final selling prices; (ii) lower demand on end-markets particularly in the fourth quarter of the year as the economic downturn worsened and (iii) an inventory holding loss (euro 166 million). In addition, impairment losses of euro 278 million were recorded as the recoverable amounts of certain petrochemicals plants were lower than their carrying amounts due to deteriorating profitability prospects on the backdrop of lowered expectations for the future unfavorable trading environment.

Operating profit in 2007 amounted to euro 74 million, a euro 98 million decrease compared to 2006, down 57%, due to lower selling margins of commodity chemicals, particularly the margin on cracker and on aromatic products (paraxilene), reflecting a sharp increase in the cost of oil-based feedstock which was not fully transferred to final selling prices. This negative was partly offset by: (i) higher production and sales volumes compared to 2006; when an accident occurred at the Priolo refinery which heavily impacted performance; and (ii) lower asset impairments (euro 50 million) and risk provisions (euro 31 million). In addition a lower inventory holding gain was recorded (down euro 54 million).

Engineering & Construction. Operating profit in 2008 amounted to euro 1,045 million, a euro 208 million increase (24.9%) compared to 2007. This increase related to an improved operating performance recorded in all business areas. In particular, Onshore and Offshore businesses benefited from improved margins, Offshore and Onshore activities reflected higher tariffs and higher activity levels.

Operating profit in 2007 amounted to euro 837 million, a euro 332 million increase (65.7%) compared to 2006. This increase related to an improved operating performance recorded in all business areas, particularly in the Offshore and Onshore construction businesses due to higher activity levels and improved margins.

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 in past years.

Other activities reported an operating loss of euro 346 million for 2008, representing an improvement of euro 98 million, or 22.1%, compared to an operating loss recorded in 2007 (euro 444 million) mainly due to impairment losses, as well as lower environmental charges (euro 109 million).

Other activities reported an operating loss of euro 444 million for 2007, representing an improvement of euro 178 million, or 28.6%, compared to the loss recorded in 2006 (euro 622 million) mainly due to lower provisions for risks and lower asset impairments (for a cumulative positive effect of euro 78 million) and to a gain recognized upon settlement of certain contractual issues with Dow Chemical. This was partly offset by higher environmental charges (euro 84 million).

Corporate and financial companies. These activities include expenses incurred in connection with corporate activities including the central treasury department and financial subsidiaries that makes available a range of

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financial services to the Group, including supporting the financing of Eni’s projects around the world, as well as results from operations of certain Eni’s minor subsidiaries that provide a range of services including training, business support, real estate and general purposes services to group’s companies.
The aggregate Corporate and financial companies reported an operating loss of euro 686 million for 2008, representing a decline of euro 469 million, compared to the loss recorded in 2007 (euro 217 million), mainly reflecting a contribution of euro 200 million to the solidarity fund pursuant to Italian Law Decree No. 112/2008 to be used to subsidize the gas bills for residential uses of less affluent citizens and higher environmental provisions.

The aggregate Corporate and financial companies reported an operating loss of euro 217 million for 2007, representing an improvement of euro 79 million, or 26.7%, compared to the loss recorded in 2006 (euro 296 million), mainly reflecting lower operating costs and lower provisions for redundancy incentives.

 

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,

		2006		2007		2008

(euro million)

Gain (loss) on derivative financial instruments		383			26			(551	)
Exchange differences, net		(152	)		(51	)		206
Interest income		194			236			87
Finance expense on short and long-term debt		(462	)		(703	)		(993	)
Finance expense due to passage of time		(116	)		(186	)		(249	)
Income from equity instruments					188			241
Other finance income (expense), net		198			227			259
		45			(263	)		(1,000	)
Finance expense capitalized		116			180			236
		161			(83	)		(764	)

2008 compared to 2007. In 2008 net finance expenses were recorded amounting to euro 764 million increasing by euro 681 million from 2007. This was mainly due to a net loss of euro 551 million (as compared to a net gain of euro 26 million in 2007) recognized in connection with fair value valuation through profit and loss of certain derivatives instruments on commodities, interest and exchange rates that do not qualify for hedge accounting under IFRS. These transactions do not qualify for hedge accounting under IFRS due to the fact that Eni hedges its exposure to commodity prices and interest and foreign exchange rates based on the overall exposure of the group to commodity prices and foreign exchange and interest rates (rather than on a transaction-by-transaction basis which would be required for hedge accounting). In addition, increased finance charges were incurred as average net borrowings increased, and interest rates on euro-denominated finance debt were up (Euribor up 0.3 percentage points) partially offset by lower interest rates on dollar loans (Libor down 2.4 percentage points). A gain from an equity instrument amounting to euro 241 million was recorded (euro 188 million in 2007) relating to the contractual remuneration of 9.4% on the 20% interest in OAO Gazprom Neft according to the contractual arrangements between Eni and Gazprom.

2007 compared to 2006. In 2007, net finance expense (euro 83 million) increased by euro 244 million from 2006 when a net finance income of euro 161 million was recorded. This change was mainly due to:

(i)

the recognition of lower gains on the fair value evaluation of certain financial derivatives instruments which do not meet the formal criteria to be assessed as hedges under IFRS, including the ineffective portion of the change in fair value of certain commodity derivatives designed as cash flow hedges resulting in a loss of euro 52 million in connection with trends in oil prices as of the date of the evaluation. Eni entered into these instruments to hedge the exposure to variability in future cash flows deriving from marketing an amount of Eni’s proved reserves equal to 2% of proved reserves as of December 31, 2006 (corresponding to approximately 125.7 mmBOE). These hedging transactions were undertaken in connection with the acquisitions executed in 2007 of proved and unproved properties in Congo and in the Gulf of Mexico. Eni put in place certain forward sale contracts at a fixed price and call and put options with the same date of exercise. These options can be exercised in presence of crude oil market prices higher or lower compared with preset contractual prices. The effective portion of the change in fair value of these hedges was directly recognized in equity and amounted to a loss of approximately euro 1.3 billion net of the related tax benefit with a corresponding decrease in other current and non-current liabilities; and

(ii)

the increase in net finance expenses due to the increase registered in average net borrowings, as well as the impact of higher interest rates on euro (Euribor up 1.2 percentage points) and dollar loans (Libor up 0.1 percentage points).

 

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These negatives were partly offset by a net gain of euro 188 million recognized in connection with the fair value valuation recorded in the profit and loss account of both a 20% interest in OAO Gazprom Neft that Eni acquired on April 4, 2007 following finalization of a bid within the Yukos liquidation procedure, and the related call option granted by Eni to Gazprom related to this interest. This call option is exercisable within 24 months starting from the acquisition date, at a price of $3.7 billion equaling the bid price, as modified by subtracting dividends received and adding possible share capital increases, a contractual remuneration of 9.4% on the capital employed and additional financing costs. The net gain recognized through the profit and loss equaled the remuneration of the capital employed by Eni in the transaction according to the contractual arrangements between the two partners. This accounting treatment is in accordance with the fair value option provided by IAS 39. Eni elected this accounting treatment to eliminate a recognition inconsistency that would otherwise arise from measuring the 20% interest in OAO Gazprom Neft and the related call option on different bases. In fact, the call option granted to Gazprom is measured at fair value through profit or loss being a derivative instrument. Fair value evaluation of the 20% interest in OAO Gazprom Neft was based on quoted market prices as this entity is currently listed on the London Stock Exchange.

 

f) Income (Expenses) from Investments

2008 compared to 2007. Net income from investments in 2008 was euro 1,373 million and was mainly related to: (i) Eni’s share of profit of entities accounted for with the equity method (euro 640 million), in particular in the Gas & Power and Exploration & Production divisions; (ii) net gains on the divestment of interest in Gaztransport et Technigaz SAS (euro 185 million) in the Engineering & Construction division and of the interest in Agip España by the Refining & Marketing division (euro 15 million); and (iii) dividends received by entities accounted for at cost (euro 510 million), mainly related to Nigeria LNG Ltd.

2007 compared to 2006. Net income from investments in 2007 was euro 1,243 million and was mainly related to: (i) Eni’s share of earning of equity-accounted affiliates (euro 773 million), particularly in the Gas & Power, Refining & Marketing and Engineering & Construction segments; (ii) net gains on the divestment of interests in Haldor Topsøe AS and Camom Group (totaling euro 290 million) in the Engineering & Construction segment; and (iii) dividends received by affiliates accounted for at cost (euro 170 million). The euro 340 million increase in net income from investments from 2006 was due essentially to higher gains on disposals of interests in the Engineering & Construction segment and higher dividends distributed in particular by Nigeria LNG, whose effects were offset in part by lower results of operations of affiliates.

 

g) Income Tax Expense

2008 compared to 2007. In 2008, income taxes amounted to euro 9,692 million, up euro 473 million, or 5.1%, mainly reflecting increased income taxes currently payable recorded by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit.

The higher taxes currently payable were partly offset by an adjustment to deferred tax relating to:

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These positives were partly offset by the fact that in 2007 Eni made use of an option provided in the annual Budget Law whereby the Company aligned the carrying amounts of certain fixed assets to their tax base by paying a one-off tax and recording through the profit and loss account excess deferred taxation resulting in a net positive impact of euro 773 million.

In 2009 management expects the Group effective tax-rate to be approximately 52-53%, representing an increase from 2008 as a result of the recently enacted supplemental tax rate for the parent company which provides for a four percentage point additional rate to be applied to profit before income taxes effective from January 1, 2009 (see "Item 3 – Risk Factors"). In addition, the Group does not expect any gains in deferred taxation for amounts comparable to those recorded in 2008. This guidance on tax rate is based on the Group full year assumption of a Brent price of U.S. dollar 43 per barrel in calculating the tax burden associated with the Company’s PSAs (see "Management expectations of operations" below).

2007 compared to 2006. Income taxes were euro 9,219 million, down euro 1,349 million, or 12.8%, mainly reflecting an adjustment to deferred tax assets and liabilities for Italian subsidiaries relating to certain amendments to the Italian tax regime, including a lower statutory tax rate, enacted by the 2008 Budget Law (euro 394 million), as well as deferred tax liabilities recorded in 2006 due to changes in the fiscal regimes of Algeria and the United Kingdom and charges regarding disputes on certain tax matters (totaling euro 347 million).

The adjustment to deferred tax assets and liabilities for Italian subsidiaries were recognized in connection with certain amendments to the Italian tax regime enacted by the 2008 Budget Law. These included a lower statutory tax rate (IRES from 33% to 27.5%, IRAP from 4.25% to 3.9%) effective January 1, 2008, and an option regarding the increase of the tax bases of certain tangible and other assets to their carrying amounts by paying a special tax with a rate lower than the statutory tax rate. The Group tax rate (46%) declined by 5.8 percentage points from 2006 (51.8%) reflecting: (i) a lower share of profit before taxes generated by the Exploration & Production division; (ii) the abovementioned adjustment to deferred tax assets and liabilities for Italian subsidiaries; and (iii) the recognition of certain gains on divestment of certain interests which are subject to lower taxation. These positives were partly offset by a higher tax rate recorded in the upstream division.

 

h) Minority Interest

2008 compared to 2007. Minority interest was euro 733 million, down euro 65 million from 2007, or 8.1%, and concerned primarily Saipem SpA (euro 407 million) and Snam Rete Gas SpA (euro 254 million).

2007 compared to 2006. Minority interest was euro 798 million, up euro 192 million from 2006, or 31.7%, and concerned primarily Saipem SpA (euro 514 million) and Snam Rete Gas SpA (euro 268 million). This increase in minority interest mainly reflected the improvement in Saipem’s results of operations and the mentioned gain on disposal of equity interest in certain affiliates.

 

 

Liquidity and Capital Resources

Eni’s cash requirements for working capital, share buybacks, dividends to shareholders, capital expenditures and acquisitions over 2006, 2007 and 2008 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,

		2006		2007		2008

(euro million)

Net profit		9,823			10,809			9,558
Adjustments to reconcile to cash generated from operating profit before changes in working capital:
- depreciation, depletion and amortization and other non monetary items		5,753			6,346			11,388
- net gains on disposal of assets		(59	)		(309	)		(219	)
- dividends, interest, income taxes and other changes		10,435			8,850			9,080
Cash generated from operating profit before changes in working capital		25,952			25,696			29,807
Changes in working capital related to operations		(1,024	)		(1,667	)		2,212
Dividends received, taxes paid, interest (paid) received during the year		(7,927	)		(8,512	)		(10,218	)
Net cash provided by operating activities		17,001			15,517			21,801
Capital expenditures		(7,833	)		(10,593	)		(14,562	)
Acquisitions of investments and businesses		(95	)		(9,665	)		(4,019	)
Disposals		328			659			979
Other cash flow related to investing activities		577			(514	)		(267	)
Changes in short and long-term finance debt		(682	)		8,761			980
Dividends paid and changes in minority interest and reserves		(6,443	)		(5,836	)		(6,005	)
Effect of changes in consolidation and exchange differences		(201	)		(200	)		918
Change in cash and cash equivalents for the year		2,652			(1,871	)		(175	)
Cash and cash equivalents at the beginning of the year		1,333			3,985			2,114
Cash and cash equivalents at year end		3,985			2,114			1,939

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

Year ended December 31,

		2006		2007		2008

(euro million)

Net cash provided by operating activities		17,001			15,517			21,801
Capital expenditures		(7,833	)		(10,593	)		(14,562	)
Acquisitions of investments and businesses		(95	)		(9,665	)		(4,019	)
Disposals		328			659			979
Other cash flow related to capital expenditures, investments and divestments		361			(35	)		(267	)
Net borrowings (1) of acquired companies					(244	)		(286	)
Net borrowings (1) of divested companies		1						181
Exchange differences on net borrowings and other changes		388			637			129
Dividends paid and changes in minority interest and reserves		(6,443	)		(5,836	)		(6,005	)
Change in net borrowings (1)		3,708			(9,560	)		(2,049	)
Net borrowings (1) at the beginning of the year		10,475			6,767			16,327
Net borrowings (1) at year end		6,767			16,327			18,376

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(1)

i

Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see "Financial Condition" below.

 

Analysis of Certain Components of Eni’s Change in Net Borrowings:

a) Cash Generated from Operating Profit before Changes in Working Capital

Net cash generated from operating profit before changes in working capital totaled euro 29,807 million in 2008 (euro 25,696 million in 2007), up euro 4,111 million from 2007.

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Net profit for 2008 was adjusted to take into account depreciation, depletion and amortization and other non-monetary items (euro 11,388 million), which primarily regarded depreciation, depletion and amortization of tangible and intangible assets (euro 8,422 million), non-monetary charges relating to environmental and risk provisions, impairments of property, plant and equipment and investments (euro 2,966 million). Adjustments to net profit also included income taxes (euro 9,692 million) and interest expense (euro 809 million).

Net profit for 2007 was adjusted to take into account depreciation, depletion and amortization and other non-monetary items (euro 6,346 million), which primarily regarded depreciation, depletion and amortization of tangible and intangible assets (euro 7,029 million), non-monetary charges relating to environmental and risk provisions, impairments of property, plant and equipment and investments (euro 207 million). Adjustments to net profit also included income taxes and interest expense (euro 8,850 million).

 

b) Changes in Working Capital related to Operations

In 2008, changes in working capital added positive flows amounting to euro 2,212 million as a result of increased current liabilities and trade payables, as well as additions to the risk provision. These positives were partly offset by cash outflows associated with increased trade receivables.

In 2007, changes in working capital were negative amounting to euro 1,667 million mainly due to: (i) an increase in the carrying amount of inventories in connection with the evaluation of inventories of refined products under the weighted-average cost method of accounting; and (ii) increased trade receivables. These cash outflows were partly offset by increased trade payables.

 

c) Investing Activities

Year ended December 31,

		2006		2007		2008

Exploration & Production		5,203			6,625			9,545
Gas & Power		1,174			1,366			1,794
Refining & Marketing		645			979			965
Petrochemicals		99			145			212
Engineering & Construction		591			1,410			2,027
Other activities		72			59			52
Corporate and financial companies		88			108			95
Impact of unrealized profit in inventory		(39	)		(99	)		(128	)
Capital expenditures		7,833			10,593			14,562
Acquisitions of investments and businesses		95			9,665			4,019
		7,928			20,258			18,581
Disposals		(328	)		(659	)		(979	)
NET INVESTMENT		7,600			19,599			17,602

Capital expenditures totaled euro 14,562 million and euro 10,593 million respectively in 2008 and in 2007.

In 2008, 84% of capital expenditures related to the Exploration & Production (euro 9,545 million), Gas & Power (euro 1,794 million) and Refining & Marketing (euro 965 million) segments.

For a discussion of capital expenditures by business segment and a description of year-on-year changes see "Capital Expenditures by Segment" below.

Acquisitions of investments and businesses totaled euro 4,019 million in 2008 and euro 9,665 million in 2007. Main acquisitions executed in the year are outlined in "Item 4 – Significant business and portfolio developments for the year".

Disposals amounted to euro 979 million in 2008 and euro 659 million in 2007.

In 2008, disposals primarily related to the Engineering & Construction segment, in connection with the divestment of the 30% stake in GTT (Gaztransport et Technigaz SAS) (euro 300 million) and the sale of Agip España by the Refining & Marketing segment (euro 153 million).

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In 2007, disposals primarily related to: (i) the Engineering & Construction segment, in connection with the divestment of interests in Haldor Topsøe AS and Camom Group (totaling euro 378 million); (ii) disposal of mineral assets and other minor assets in the Exploration & Production segment (euro 182 million); and (iii) minor assets in the Refining & Marketing segment (euro 53 million).

 

d) Dividends paid and Changes in Minority Interests and Reserves

In 2008, dividends paid and changes in minority interests and reserves (euro 6,005 million) related mainly to the dividend distribution to Eni shareholders for euro 4,910 million (of which euro 2,551 million related to the balance for the fiscal year 2007 and euro 2,359 million as an interim dividend for fiscal year 2008) and the distribution of dividend to minority interest by Snam Rete Gas SpA and Saipem SpA (euro 288 million) and other consolidated subsidiaries (euro 9 million) and the buy-back program (for euro 778 million by Eni SpA and for euro 58 million by Saipem SpA).

In 2007, dividends paid and changes in minority interests and reserves (euro 5,836 million) related mainly to the dividend distribution to Eni shareholders for euro 4,583 million (of which euro 2,384 million related to the balance for the fiscal year 2006 and euro 2,199 million as an interim dividend for fiscal year 2007) and the distribution of dividend to minority interest by Snam Rete Gas SpA and Saipem SpA (euro 282 million) and other consolidated subsidiaries (euro 7 million) and the buy-back program (for euro 680 million by Eni SpA and for euro 358 million by Snam Rete Gas SpA and Saipem SpA).

 

Financial Condition

In assessing its capital structure, Eni uses net borrowings and leverage (as described below), both of which are "non-GAAP" financial measures. Non-GAAP financial measures are measures that either exclude or include amounts that are not excluded or included in the comparable measures calculated and presented in accordance with generally accepted accounting principles, in Eni’s case IFRS issued by the IASB and IFRS issued by the IASB as adopted by the European Union. 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 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 mainly of deposits with banks and other financing institutions and deposits in escrow. Securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the means whereby Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including minority 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 constantly monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds vs. 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 leverage measure, derived from IFRS reported amounts, is the ratio of total debt to shareholders’ equity (including minority interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

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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,

		2006		2007		2008

Short-term

Long-term

Total

Short-term

Long-term

Total

Short-term

Long-term

Total

(euro million)

Total debt (short-term and long-term debt)		4,290			7,409			11,699			8,500			11,330			19,830			6,908			13,929			20,837
Cash and cash equivalents		(3,985	)					(3,985	)		(2,114	)					(2,114	)		(1,939	)					(1,939	)
Securities not related to operations		(552	)					(552	)		(174	)					(174	)		(185	)					(185	)
Non-operating financing receivables		(143	)		(252	)		(395	)		(990	)		(225	)		(1,215	)		(337	)					(337	)
Net borrowings		(390	)		7,157			6,767			5,222			11,105			16,327			4,447			13,929			18,376

 

	As of December 31,

		2006		2007		2008

Shareholders’ equity including minority interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS		(euro million)		41,199			42,867			48,510
Ratio of total debt to total shareholders’ equity including minority interest				0.28			0.46			0.43
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including minority interest				(0.12	)		(0.08	)		(0.05	)
Ratio of net borrowing to total shareholders’ equity including minority interest (leverage)				0.16			0.38			0.38

Net borrowings

In 2008, net borrowings amounted to euro 18,376 million, representing a euro 2,049 million increase from 2007. This increase was mainly due to the large amount of capital expenditures and acquisitions executed in the year which was only partially funded with cash flows from operations. Total debt of euro 20,837 million consisted of euro 6,908 million short-term debt (including the portion of long-term debt due within twelve months equal to euro 549 million) and euro 13,929 million of long-term debt.

Total debt included bonds for euro 6,843 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 412 million (including accrued interest and discount). Bonds issued in 2008 amounted to euro 1,812 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (77%), U.S. dollar (11%), pound sterling (10%) and 2% in other currencies.

In 2007, net borrowings amounted to euro 16,327 million, a euro 9,560 million increase over 2006, up 141%, reflecting the large amount of capital expenditures and acquisitions executed in the year which was only partially funded with cash flows from operations. Total debt of euro 19,830 million consisted of euro 8,500 million short-term debt (including the portion of long-term debt due within twelve months equal to euro 737 million) and euro 11,330 million of long-term debt.

Total debt included bonds for euro 5,386 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 584 million (including accrued interest and discount). Bonds issued in 2007 amounted to euro 1,118 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (78%), U.S. dollar (13%), pound sterling (8%) and 2% in other currencies.

Short-term Debt

As of December 31, 2008, short-term debt of euro 6,908 million (including the portion of long-term debt due within twelve months) decreased by euro 1,592 million over 2007. The weighted average interest rate of Eni’s short-term debt was 4.2% and 4.9% for the years ended December 31, 2008 and 2007, respectively.

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As of December 31, 2008, Eni had maintained committed and uncommitted unused borrowing facilities of euro 3,313 million and euro 7,696 million, respectively (euro 5,006 million and euro 6,298 million at December 31, 2007). These facilities were under interest rates that reflected market conditions. Changes in unutilized facilities were not significant.

As of December 31, 2007, short-term debt of euro 8,500 million (including the portion of long-term debt due within twelve months) increased by euro 4,210 million over 2006. The weighted average interest rate of Eni’s short-term debt was 3.9% and 4.9% for the years ended December 31, 2006 and 2007, respectively.

As of December 31, 2007, Eni had maintained committed and uncommitted unused borrowing facilities of euro 5,006 million and euro 6,298 million, respectively (euro 5,896 million and euro 6,523 million at December 31, 2006). These facilities were under interest rates that reflected market conditions. Changes in unutilized facilities were not significant.

Long-term Debt

As of December 31, 2008, long-term debt of euro 13,929 million increased by euro 2,599 million over 2007.

At December 31, 2007 and 2008, the amount of short and long-term debt subject to restrictive covenants was euro 1,429 million and euro 1,323 million, respectively. Furthermore, Saipem SpA entered into certain borrowing facilities for euro 75 million with a number of financial institutions subordinated to the maintenance of certain performance indicators based on the consolidated financial statements of Saipem. Eni and Saipem are in compliance with the covenants contained in their respective financing arrangements. Bonds of euro 6,843 million consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 6,391 million and other bonds for a total of euro 452 million.

 

Capital Expenditures by Segment

Exploration & Production. In 2008, capital expenditures of the Exploration & Production segment amounted to euro 9,545 million, representing an increase of euro 2,920 million, or 44.1%, from 2007 mainly due to the development of oil and gas reserves. Significant expenditures were directed mainly outside Italy, in particular Kazakhstan, Egypt, Angola, Congo and the United States. Development expenditures in Italy concerned a well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 93% of exploration expenditures were directed outside Italy, in particular to the United States, Egypt, Nigeria, Angola and Libya. In Italy, exploration activities were directed mainly to the offshore of Sicily. Acquisition of proved and unproved property concerned mainly the extension of Eni’s mineral rights in Libya, following the agreement signed in October 2007 with NOC, the National Oil Corporation (effective from January 1, 2008), and the acquisition of a 34.81% stake in ABO project in Nigeria.

In 2007, capital expenditures of the Exploration & Production segment amounted to euro 6,625 million, representing an increase of euro 1,422 million, or 27.3%, from 2006 due to development of oil and gas reserves. This amount of expenditures was also affected by industry-wide cost trends regarding oilfield services and equipment. Main projects were executed mainly outside Italy, in particular Kazakhstan, Angola, Egypt and Congo. Development expenditures in Italy concerned in particular a well drilling program and facility upgrading in Val d’Agri and sidetrack and infilling interventions in mature fields. Significant expenditures were directed toward exploratory projects. About 94% of these expenditures were also directed outside Italy, in particular the Gulf of Mexico, Egypt, Brazil, Norway and Nigeria. In Italy, exploration activities were directed mainly to the offshore of Sicily. Acquisition of proved and unproved property concerned mainly a 70% interest in the Nikaitchuq oilfield in Alaska, in which Eni reached a 100% ownership.

Gas & Power. In 2008, capital expenditures in the Gas & Power segment totaled euro 1,794 million and related essentially to: (i) developing and upgrading Eni’s transport network in Italy (euro 1,130 million); (ii) the upgrading plan of international pipelines (euro 233 million); (iii) developing and upgrading Eni’s natural gas distribution network in Italy (euro 233 million); and (iv) ongoing construction of combined cycle power plants (euro 107 million), in particular at the Ferrara site.

In 2007, capital expenditures in the Gas & Power segment totaled euro 1,366 million and related essentially to: (i) developing and upgrading Eni’s primary transport network in Italy (euro 691 million); (ii) the upgrading plan of international pipelines (euro 253 million); (iii) developing and upgrading Eni’s natural gas distribution network in Italy (euro 195 million); and (iv) ongoing construction of combined cycle power plants (euro 175 million), in particular at the Ferrara site.

Refining & Marketing. In 2008, capital expenditures in the Refining & Marketing segment amounted to euro 965 million and related mainly to: (i) refining, supply and logistics (euro 630 million) in Italy, with projects designed to improve the conversion rate and flexibility of refineries, in particular ongoing construction of a new

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hydrocracker at the Sannazzaro refinery, and expenditures on health, safety and environmental upgrades; (ii) upgrade and restructuring of the retail network in Italy (euro 183 million); and (iii) upgrade of the retail network and purchase of service stations in the rest of Europe (euro 115 million). Expenditures on health, safety and the environment amounted to euro 166 million.

In 2007, capital expenditures in the Refining & Marketing segment amounted to euro 979 million and regarded mainly: (i) refining, supply and logistics (euro 675 million) in Italy, with projects designed to improve the conversion rate and flexibility of refineries, in particular the start-up of construction of a new hydrocracking unit at the Sannazzaro refinery, and expenditures on health, safety and environment upgrades; (ii) upgrade and restructuring of the retail network in Italy (euro 176 million); and (iii) upgrade of the retail network in the rest of Europe (euro 106 million). Expenditures on health, safety and the environment amounted to euro 141 million.

Petrochemicals. In 2008, capital expenditures in the Petrochemical segment amounted to euro 212 million (euro 145 million in 2007) and related mainly to extraordinary maintenance (euro 84 million), plant upgrades (euro 51 million), environmental protection, safety and environmental regulation compliance (euro 41 million), upkeeping and rationalization (euro 24 million).

In 2007, capital expenditures in the Petrochemical segment amounted to euro 145 million regarded mainly plant upgrades (euro 47 million), environmental protection, safety and environmental regulation compliance (euro 39 million), extraordinary maintenance (euro 29 million) and upkeeping (euro 28 million).

Engineering & Construction. In 2008, capital expenditures in the Engineering & Construction division (euro 2,027 million) mainly related to the start up of the construction of the deepwater field development ship FDS 2 as well as the ongoing construction of the pipelayer, the semisubmersible platforms Scarabeo 8 and 9 and the deepwater drilling ship Saipem 12000. In 2008, the construction of the FPSO vessel Gimboa and of the jack-up Perro Negro 7 has been completed.

In 2007, capital expenditures in the Engineering & Construction segment (euro 1,410 million) mainly related to: (i) ongoing construction of the new semisubmersible platform Scarabeo 8, a new pipelayer and a new deepwater drilling ship Saipem 12000; and (ii) the conversion of two tanker ships into FPSO vessels that will operate in Brazil on the Golfinho 2 field and in Angola.

 

 

Recent Developments

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

		Three months ended March 31,		One month ended April 30,

		2008		2009		2008		2009

Average price of Brent dated crude oil in U.S. dollars (1)		96.90		44.40		108.97		50.34
Average price of Brent dated crude oil in euro (2)		64.60		34.10		69.19		38.17
Average EUR/USD exchange rate (3)		1.500		1.302		1.575		1.319
Average European refining margin in U.S. dollars (4)		3.81		5.34		8.34		4.06
EURIBOR - three month euro rate % (3)		4.5		2.0		4.78		1.42

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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.

 

Eni’s Results of Operations for the First Quarter 2009

Net profit for the first quarter of 2009 was down 42.7% compared to the first quarter of 2008. Reported operating profit was down 35.8% as a result of lower profit in the Exploration & Production and Gas & Power segments due to lower oil prices and falling gas demand amidst the current economic downturn. The Company also reported lower profit from equity-accounted entities. This decrease in net profit was also due to a higher tax rate (up 2.7 percentage points from 45.6% to 48.3%).

Eni’s results were positively influenced by the depreciation (down 13.2%) of the euro vs. the dollar. The trading environment was characterized by lower oil realizations in the quarter declining by 50.9% in dollar terms, driven by falling Brent prices (down 54.2% from the first quarter of 2008). Natural gas realizations increased by

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3.8% due to the time lag between movements in oil prices and their effect on gas prices. Gas marketing margins increased from a the first quarter of 2008 due to favorable trends in energy parameters used in determining purchase and selling prices of natural gas.

Realized refining margins were slightly impacted by the favorable trading environment as measured by movements in the relative prices of products compared to the cost of the oil feedstock (the margin on Brent was 5.34 $/BL, up 40.2% from the first quarter of 2008), mainly due to narrowing differentials between light and heavy oil that penalized Eni’s results on complex cycles. Retail marketing margins were lower. Selling margins of commodity chemicals were sharply due to higher costs of oil-based feedstock that were not fully recovered in sales prices.

At March 31, 2009 net borrowings declined by 10.1% from December 31, 2008, due to cash inflows provided by operating activities, offset in part by financing requirements for capital expenditures.

In the first quarter of 2009, hydrocarbon production decreased by 0.9% compared with the first quarter of 2008 mainly due to OPEC production cuts, unplanned facility downtime in Nigeria and mature field declines (for further detailed information see "Item 4 – Exploration & Production"). These negatives were partially offset by continuing production ramp-up in Angola, Congo, Egypt and Venezuela. Lower oil prices resulted in higher volume entitlements in Eni’s Production Sharing Agreements (PSAs) and similar contractual schemes.

Natural gas sales were up 4.7% as compared to the first quarter of 2008 reflecting contribution from the Distrigas acquisition. This increase was partly offset by significantly lower gas sales on the Italian market due to the economic downturn.

 

Significant Transactions

On April 7, 2009 Gazprom exercised its call option to purchase the 20% interest in OAO Gazprom Neft held by Eni following agreements between the two partners. The 20% interest in Gazprom Neft was acquired by Eni on April 4, 2007 as part of a bid procedure for the assets of bankrupt Russian company Yukos. The exercise price of the call option is equal to the bid price (U.S. $3.7 billion) as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and additional financing expenses. On April 24, 2009 Eni collected from Gazprom the cash consideration for the exercise of the call option amounting to U.S. $4.2 billion. Terms of the call option granted to Gazprom to purchase a 51% interest in the share capital of OOO SeverEnergia, which owns 100% of the three abovementioned Russian companies engaging in gas development, are currently under review by Eni, Enel and Gazprom.

On March 19, 2009, a mandatory tender offer to the minority shareholders of Distrigas was completed. Shareholders representing a 41.61% of the share capital of Distrigas tendered 292,390 shares on Eni’s offer. Publigaz Scrl tendered its entire interest (31.25%). The transaction has been accounted for in Eni financial statements as at March 31, 2009. On April 8, 2009 Eni paid to those shareholders cash consideration amounting to euro 1,991 million. Following the tender offer, Eni owned 98.86% of the share capital of Distrigas. The squeeze-out on the residual 1.14% was completed in early May. Consequently Eni holds all the shares of Distrigas except for one share belonging to the Belgian State with special powers. Distrigas shares have been delisted from Euronext Brussels. For further details on this transaction see "Item 4 – Significant business and Portfolio Developments".

On February 12, 2009, Eni’s Board of Directors approved the divestment of 100% of Italgas SpA and Stoccaggi Gas Italia SpA (Stogit) to Snam Rete Gas (50.03% owned by Eni) for total cash consideration of euro 4,720 million (euro 3,070 million and euro 1,650 million, respectively). The transaction will be financed by Snam Rete Gas through: (i) a rights issue for up to euro 3.5 billion (Eni has already committed to subscribe its share of the rights issue); and (ii) new medium to long-term financing for euro 1.3 billion. The main effects expected on Eni’s consolidated financial statements when the transaction closes will be: (i) a decrease of euro 1.5 billion in net borrowings and a corresponding increase in total equity as a consequence of the pro-quota subscription of the Snam Rete Gas capital increase by the minority shareholders; and (ii) a decrease in Eni’s net profit equal to 45% of the aggregate net profit of Italgas and Stogit, with a corresponding increase in net profit attributable to minority shareholders. From an industrial perspective the transaction, expected to close in July 2009, will create significant synergies in the regulated businesses segment and maximize the value of Italgas and Stogit due to the higher visibility of regulated businesses as a part of Snam Rete Gas. For further details on this transaction see "Item 4 – Significant business and Portfolio Developments".

By the end of May 2009, based on the approval of the full year dividend proposal made by the Company’s Annual General Shareholders Meeting on April 30, 2009, Eni expects to pay the balance of the dividend for fiscal year 2008 amounting to euro 0.65 per share. Total cash out is estimated at euro 2.36 billion.

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Management’s Expectations of Operations

Management expects that the macroeconomic environment will remain challenging throughout the whole of 2009. Key management assumptions for the main external variables are an average Brent price of 43 $/BL for the full year 2009 and a decline in European demand for natural gas and fuels. The Brent assumption has been used by management for planning purposes and does not intend to furnish a forecast for what will be the likely Brent market price for the year. In this environment, management plans to achieve the following volumes targets.

Over the next four years, the Company plans to invest euro 48.8 billion in its businesses to support continued organic growth; approximately 67%, 17%, 8% and 6% of planned capital expenditures will be directed to the Exploration & Production, Gas & Power, Engineering & Construction and Refining & Marketing segments, respectively. The main planned projects are as follows: (i) development of reserves of hydrocarbons mainly in Kazakhstan, Norway, Libya, Italy, Angola, Congo, Egypt, Nigeria and the U.S. and; (ii) exploration projects to be executed mainly in the U.S., Libya, Italy, Angola, Indonesia, Nigeria, Norway, and Egypt; (iii) upgrading of national pipelines for transporting natural gas, as well as upgrading of Italian distribution networks; (iv) development of infrastructures to store natural gas in order to support seasonal upswings in natural gas demand; (v) upgrading of the fleet of construction vessels and offshore drilling rigs, as well as logistic centers and other support facilities in the Engineering & Construction segment; (vi) refinery upgrading, mainly targeting an increase in conversion capacity and flexibility of Eni’s main refineries; and (vii) upgrading of Eni’s networks of service stations for marketing petroleum products.

Eni’s capital expenditure program has remained broadly unchanged with respect to the previous industrial plan for the following reasons: (i) management believes that it has adopted prudent price assumptions in making investment decisions and these assumptions remain intact also in the current economic downturn; and (ii) management estimates that a high number of development projects in the Company’s Exploration & Production business deliver positive returns at current oil prices. Additionally, the Company capital plans present a high exposure to the regulated activities in the Italian gas sector (14% of the total investment program) which bear preset rates of return and are marginally influenced by market conditions. Management also expects that the current economic downturn will cause a reduction in expenditures required to develop reserves, including oilfield service rates and purchase costs of materials and support equipment, when compared to costs incurred during the upward phase of the oil cycle. In the event of a further deterioration in the macroeconomic environment, the Company believes that its capital plans retain an adequate level of flexibility to enable rescheduling of a number of projects as approximately 50% of the planned capital expenditures are yet to be committed. A capital project becomes committed when it receives the appropriate level of internal sanction and relevant contracts with third parties are awarded.

In making its capital expenditure projections for the next four years, management has assumed that the Company will be able to deliver approximately euro 5 billion of savings on planned expenditures benefiting from the expected reduction in oilfield service and materials costs and other cost control initiatives on ongoing projects. See "Item 3 – Risk Factors".

Management intends to pursue strict capital discipline when assessing individual capital projects. Management uses a long-term reference oil price of 57 $/BL from 2013 onwards, in real terms that is adjusted to take account of expected inflation. 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 by taking into account: (i) the weighted average cost of capital to the Group; (ii) a country risk premium which reflects the specific level of risk

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associated with each country of operation in terms of macroeconomic, business and socio-political current conditions and outlook; and (iii) a premium for the business risk.

In the foreseeable future, management is strongly focused on preserving a solid balance sheet and an adequate level of liquidity taking into account macroeconomic uncertainties and tight financial markets. By this means, management expects to maintain its current credit rating. For planning purposes, management assessed the Company’s cash flows against a scenario of Brent prices at 43 $/BL for the year 2009 increasing slightly in the next three years up to 55 $/BL in 2012 and concluded that cash flows from operations would be sufficient to fund planned capital expenditures and dividend payments, while at same time achieving a ratio of net borrowings to total equity "leverage" that management regards as consistent with the priority of preserving the Company’s credit rating. Particularly, for the year 2009, management expects a decrease in capital expenditures as compared to 2008 (euro 14.56 billion in 2008). On the basis of the Company’s projections of cash flow at a price of $43 per Brent barrel for the full year, management expects that the Group’s leverage at year-end 2009 will record a slight increase from 2008 year-end (0.38). Nevertheless, management believes that, based upon its understanding of the criteria used for credit ratings,the Group projected leverage at year-end 2009 will be adequate to support the Company’s current credit rating. For planning purposes, management assumed an average exchange rate of approximately 1.30 U.S. dollars per euro in the 2009-2012 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".

In the next four-year period management intends to pursue a dividend policy designed to ensure competitive dividend yields to Eni’s shareholders. For fiscal year 2008, Eni is paying a dividend per share of euro 1.30, of which euro 0.65 per share was paid in September 2008 as an interim dividend with the balance of euro 0.65 per share to be paid late in May 2009. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full year dividend paid in the following year. The euro 1.3 dividend for 2008 represents a yield of 7.6% as measured against the Eni share price recorded in the month of December 2008 on the Italian stock exchange. See "Item 8 – Dividend Policy" for more details on Eni’s dividend policy and the uncertainties and constraints to which it is subject.

Based on management’s assumptions for oil prices in the next four years, management plans to achieve an average production growth rate of 3.5% in the 2009-2012 period. Oil price assumptions are particularly significant when assessing the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. For the current year, the Company estimates that production entitlements in its PSAs would decrease on average by approximately 1,000 BBL/d for each $1 increase in oil prices compared to Eni’s assumptions for oil prices. This sensitivity analysis relates to the existing Eni portfolio and might vary in the future.

In the next four years, Eni expects its core natural gas business in Italy to face increasing competitive pressure as a result of: (i) the current economic downturn that has significantly impacted management’s growth expectations of the Italian gas market for the year 2009 and possibly beyond as there is limited visibility on time and strength of the recovery; also future growth rates for European gas demand have been subject to downward revisions (see "Item 4 – Gas & Power"); (ii) an expected increase in supplies of natural gas to the Italian market as new import capacity comes on line in connection with already started-up projects and completion of ongoing projects designed to upgrade import infrastructures to Italy. Specifically, the Company expects additional import capacity to supply up to 10 BCM in 2009 as Eni’s upgrades of its main TTPC and TAG pipelines from Algeria and Russia respectively reach full operations. In addition, Eni is completing another leg of expansion at the TAG pipeline and is planning to upgrade its pipeline from Libya. A competitor has commenced commissioning operations at a new LNG terminal in the Adriatic Sea. Overall the Company expects that import capacity will increase by 25 BCM by 2012 of which 90% will be available by 2010; and (iii) the need on the part of Eni to comply with the mandatory ceilings provided for by Italian regulation by selling natural gas volumes available under take-or-pay purchase contracts to certain Italian natural gas importers who resell those volumes on the Italian natural gas market (see "Item 4 – Regulation of the Italian Natural Gas Market" and "Item 3 – Risk Factors"). As a result of these market trends and developments, management expects that competition will increase in the future putting further pressure on selling margins. Eni’s sales volumes in Italy are projected to decline from the 53 BCM level achieved in 2008 to approximately 50 BCM in 2012. Worldwide gas sales are projected to reach 124 BCM by 2012 leveraging on the Company’s expansion in European markets on the backdrop of the expected synergies arising from the integration of Distrigas (see "Item 4 – Gas & Power"). This planned growth will make for reduced growth expectations in the Italian natural gas market.

Management intends to implement a number of marketing actions designed to support the Company’s selling margins in the Italian market in spite of rising competitive pressure. Specifically, management plans to preserve profitability of the Company’s gas operations in Italy by focusing on the most profitable customer segments. Tailored marketing policies will be deployed to retain and develop the main customers throughout all market segments. These policies include the offer of pricing formulas and services that are designed to best satisfy the customers’ needs. Also the Company intends to strengthen its market position in the residential sector by leveraging on the development of the combined offer of gas and electricity (the dual offer). Streamlining business support activities and reducing marketing and general and administrative costs will also drive margin improvements.

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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 – Liberalization of the Italian Natural Gas Market".

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, 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.

 

Off-Balance Sheet Arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in Note 29 to the Consolidated Financial Statements. Eni’s principal financial obligations, including commitments under take-or-pay or ship-or-pay clauses, are described under "Contractual Obligations" below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses.

Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the company’s financial condition, results of operations, liquidity or capital resources.

Eni has provided various forms of guarantees on behalf of non-consolidated 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. The aggregate amount of these guarantees is euro 20.6 billion, euro 7.1 billion of which relate to non-consolidated entities. In addition, Eni has commitments and contingencies relating to purchases of assets an other risks for a total of euro 1.9 billion. See "Item 4 – Acquisition of Distrigas". These arrangements are described in Note 29 to the Consolidated Financial Statements.

 

 

 

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Contractual Obligations

The following table summarizes the principal financial obligations which are described in "Item 18 – Financial Statements – Notes 16, 21, 22, 29 and 31".

Amounts in the table refer to expected payments by period under contractual obligations commitments shown an undiscounted basis as of the balance sheet date.

	Maturity year

	Total		2009		2010		2011		2012		2013		2014 and thereafter

(euro million)

Total debt		20,837		6,908		3,630		797		2,687		1,981		4,834
Long-term debt		14,478		549		3,630		797		2,687		1,981		4,834
Short-term debt		6,359		6,359
Interest payments on debt		2,893		502		469		412		383		336		791
Noncancelable operating lease obligations (1)		4,287		618		1,025		697		468		395		1,084
Asset retirement obligations (2)		9,469		269		35		61		18		256		8,830
Environmental liabilities		1,988		396		421		284		223		221		443
Purchase obligations (3)		259,973		17,938		13,777		14,326		14,405		14,112		185,415
Natural gas to be purchased in connection with take-or-pay contracts (4)		248,329		15,694		13,041		13,574		13,610		13,343		179,067
Natural gas to be transported in connection with ship-or-pay contracts (4)		5,849		539		537		545		549		528		3,151
Other take-or-pay and ship-or-pay obligations		1,455		139		135		126		111		106		838
Other purchase obligations (5)		4,340		1,566		64		81		135		135		2,359
Other commitments		180		8		5		5		5		5		152
of which:
- Memorandum of intent relating to Val d’Agri		180		8		5		5		5		5		152
TOTAL		299,627		26,639		19,362		16,582		18,189		17,306		201,549

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(1)	i	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)	i	Represents the estimated future costs for the decommisioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3)	i	Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(4)	i	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 off-taking 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.
(5)	i	Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S.

The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects at 31 December 2008. 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		2009		2010		2011		2012		2013 and subsequent years

Capital expenditure commitments
Committed on major projects	23,159		4,938		3,831		2,697		1,837		9,856
Other committed projects	24,910		5,147		4,342		3,186		2,389		9,846
TOTAL	48,069		10,085		8,173		5,883		4,226		19,702

 

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 the 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

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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 the difficult and ongoing 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 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 above mentioned actions aimed at ensuring availability of suitable sources of funding to fulfill short-term commitments and due obligations also preserving the necessary financial flexibility to support the Group’s development plans. In doing so, the Group has pursued an efficient balance of finance debt in terms of maturity and composition leveraging on the structure of its lines of credit particularly the committed ones.

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.

As of December 31, 2008, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 11,009 million, of which euro 3,313 million were committed, and long-term committed unused borrowing facilities of euro 1,850 million. These facilities were under interest rates that reflected market conditions. Fees charged for unused facilities were not significant.

Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 10 billion, of which euro 6,391 million were drawn as of the balance sheet date.

The Group has debt ratings of AA- and A-1+ respectively for the long and short-term debt assigned by Standard & Poor’s and Aa2 and P-1 assigned by Moody’s; the outlook is stable for both. A security is not a recommendation to buy, sell or hold securities. A security rating may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.

 

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. The Group manages credit risk differently depending on whether it arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business 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. The monitoring activity of credit risk exposure is performed at the Group level according to certain guidelines and measurement techniques that establish counterparty limits and systems to monitor exposure against limits and report regularly on those exposures. Specifically, credit risk exposure to multi-business clients and exposures higher than the limit set at euro 4 million are closely monitored. Monitoring activities do not include retail clients and public administrations. The assessment methodology assigns a score to individual clients based on publicly available financial data and capital, profitability and liquidity ratios. Based on these scores, counterparties are assigned an internal credit rating and classified based on their risk category. The Group risk categories are comparable to those prepared by external credit rating agencies. The Group’s internal ratings are also benchmarked against ratings prepared by such agencies. 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 credit rating agencies. Credit risk arising from financial counterparties is managed by the Group central finance departments, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions.

Those are the sole Group entities entitled to be party to a financial transactions due to the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty 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.

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Actions implemented also have been intended to limit incentrations of credit risk by maximizing counterparty diversification and turnover. Counterparties have been also selected on a more stringent criteria particularly in transactions on derivatives instruments and with maturity longer than a three-month period. Eni has not experienced material non-performance by any counterparty. As of December 31, 2007 and 2008, Eni had no significant concentrations of credit risk.

 

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 vs. other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For an in-depth analysis of market risks exposure and policies used by Eni to manage its exposure to market risk see "Item 11 - Qualitative and Quantitative Disclosures About Market Risk".

 

Research and Development

For a description of Eni’s research and development operations in 2008, see "Item 4 – Research and Development".

 

 

 

Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

In accordance with Article 17.3 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members. The Board of Directors currently in office was elected by the ordinary shareholders’ meeting held on June 10, 2008, that established the number of Directors at nine for a three financial year term. The Board will therefore expire at the date of the Shareholders’ Meeting approving Eni’s financial statements for year ended December 31, 2010.
The table below sets forth the names of the Board of Directors members appointed, their positions, the year when each was initially appointed as a Director and their ages

Name		Position		Year first appointed to Board of Directors		Age
Roberto Poli		Chairman		2002		71
Paolo Scaroni		CEO		2005		63
Alberto Clô		Director		1999		62
Paolo Andrea Colombo		Director		2008		49
Paolo Marchioni		Director		2008		40
Marco Reboa		Director		2005		54
Mario Resca		Director		2002		64
Pierluigi Scibetta		Director		2005		50
Francesco Taranto		Director		2008		69

Roberto Poli, Paolo Scaroni, Paolo Andrea Colombo, Paolo Marchioni, Mario Resca and Pierluigi Scibetta were candidates included in the list of the Ministry for Economy and Finance. Alberto Clô, Marco Reboa and Francesco Taranto were candidates included in the list presented by institutional investors.

While it remains a significant shareholder, the Ministry of Economy and Finance intends to continue to participate in the nomination and election of Eni’s Board of Directors in order to protect its investment as a shareholder.

On the basis of Italian laws regulating the special powers of the State (see "Item 10 – Limitations on Voting and Shareholdings"), the Minister of Economy and Finance in agreement with the Minister of 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 for Economy and Finance opted not to exercise that power.

Moreover, according to Italian law and jurisprudence, until the Ministry of Economy and Finance remains a relevant shareholder, Eni’s accounts will be subject to the review of the Italian Court of Accountants ("Corte dei Conti") in order to protect the financial interest of the State. A Magistrate appointed by the Court of Accounts consequently attends Eni’s Board of Directors, Board of Statutory Auditors and Internal Control Committee meetings (without any voting right) and Eni has the obligation to send to the Court of Accountants its financial

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statements together with the reports of the Board of Directors, the Board of Statutory Auditors and its external auditors. The Magistrate delegated to control is currently Lucio Todaro Marescotti (alternate Amedeo Federici).

The table below sets forth the composition of Eni’s senior management, including the CEO who is also General Manager of the Eni SpA, the Chief Operating Officers of Eni’s three divisions, and those senior managers who attended on a permanent basis the meetings of Eni’s Management Committee and other senior managers who report to the CEO. This table indicates their positions within Eni, the year they were appointed to such positions, their total years of service at Eni and their ages. Chief Operating Officers are appointed by the Board of Directors, upon 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.

Name		Management position		Year first appointed to current position		Total number of year of service at Eni		Age
Paolo Scaroni		Chief Operating Officer of Eni		2005		4		63
Claudio Descalzi (*)		Chief Operating Officer for the Exploration & Production Division		2008		28		54
Domenico Dispenza		Chief Operating Officer for the Gas & Power Division		2005		35		63
Angelo Caridi		Chief Operating Officer for the Refining & Marketing Division		2007		39		62
Alessandro Bernini (**)		Chief Financial Officer		2008		13		49
Salvatore Sardo		Chief Corporate Operations Officer		2005		4		57
Massimo Mantovani		The Group Senior Executive Vice President for Legal Affairs		2006		16		46
Rita Marino		The Group Senior Executive Vice President for Internal Audit		2008		4		45
Leonardo Maugeri		The Group Senior Executive Vice President for Strategies and Development		2000		14		44
Stefano Lucchini		The Group Senior Executive Vice President for Public Affairs and Communication		2005		4		47
Roberto Ulissi		The Group Senior Executive Vice President for Corporate Affairs and Governance		2006		3		47
Raffaella Leone		Executive Assistant to the Chief Executive Officer		2005		4		47

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(*)	i	Appointed by the Board of Directors on July 30, 2008.
(**)	i	Appointed on August 1, 2008.

The biographies of Eni’s directors and senior managers are set out below.

Roberto Poli was appointed Chairman of Eni SpA in May 2002. He is currently President of Poli e Associati SpA, a consulting firm specialized in corporate finance, mergers, acquisitions and reorganizations. From 1966 to 1998 he was Professor of Business Finance at the Università Cattolica of Milan. He is a partner of a leading firm for corporate finance and legal affairs. He is director in important companies such as Fininvest SpA, Mondadori SpA, Merloni Termosanitari SpA, Coesia SpA, Maire Technimont SpA and Perennius Capital Partners SGR SpA. He has been an advisor for extraordinary finance operations for some of the most important companies in Italy. He has also been Chairman of Rizzoli-Corriere della Sera SpA and Publitalia SpA.

Paolo Scaroni was appointed CEO of Eni SpA in June 2005. He obtained an economics degree from Milan’s Bocconi University in 1969 and an MBA from Columbia Business School in 1973. For a year following business school, he was an associate at McKinsey & Co. From 1973 until 1985, he held a series of positions with Saint Gobain, culminating with his appointment as President of the Saint Gobain flat glass division. From 1985 to 1996 he was Deputy Chairman and CEO of Techint. During his time at Techint, he was also Vice President of Falck and executive Vice President of SIV, a joint venture between Techint and Pilkington plc. He joined Pilkington in 1996 and was group CEO until May 2002. From May 2002 to May 2005 he was CEO of Enel, Italy’s leading electricity utility. Paolo Scaroni is a member of the Board of Assicurazioni Generali SpA, of LSEG plc (London Stock Exchange Group), of Veolia Environment (Paris), of the Board of Overseers of Columbia Business School (New York) and of the Board of Fondazione Teatro alla Scala. He was Chairman of Alliance Unichem plc (UK) from 2005 to July 2006. In November 2007 he was made a member of the Légion d’honneur of France.

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Alberto Clô graduated in Political Science. He is Associate Professor of Industrial Economics at the University of Bologna and from 1995 to 1996 he was Minister of Industry and interim Minister of Foreign Trade ad interim in 1995 and 1996. During the Italian presidency of the European Union he was Chairman of the Council of Ministers of Industry and Energy of the European Union. In 1996 he was awarded the title of Cavaliere di Gran Croce al Merito of the Republic of Italy. Until December 31, 2007 he was director of ASM Brescia SpA. Currently he is non-executive director of Atlantia SpA, Italcementi SpA and De Longhi SpA. He has been an independent Director of Eni SpA since May 1999.

Paolo Andrea Colombo graduated in Business Economics from the Bocconi University and qualified as a professional accountant and auditor in 1985. He is professor of Accounting and Financial Reporting at the Bocconi University, Milan. He is partner of Borghesi Colombo & Associati, a consultancy firm specialized in corporate finance, mergers and acquisitions, strategy and corporate governance. He is a member of the Board of Directors of Mediaset, Interbanca, Ceresio Sim and Versace, and member of the Board of Statutory Auditors of Interbanca, Aviva Vita, Sirti, A. Moratti Sapa, Humanitas Mirasole, Credit Agricole Assicurazioni Italia. In Eni, he was member of the Board of Statutory Auditors/Audit Committee (2002-2005) and Chairman of the same Board for a three year period until June 2008. He has been Chairman of Eni’s audit committee since May 2005. He has been an independent Director of Eni since June 2008.

Paolo Marchioni is a qualified lawyer specialising in penal and administrative law. He acts 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. He served in various positions within government agencies. From October 2001 to April 2004 he was a director of Cim SpA of Novara (merchandise interport center), from December 2002 to December 2005 a director and executive committee member of Finpiemonte SpA and from June 2005 to June 2008 director of Consip SpA. He has been an independent Director of Eni since June 2008.

Marco Reboa graduated in Business Administration from the Bocconi University, Milan. He is a chartered accountant and public auditor. He is Professor of law at the Libero Istituto Universitario Carlo Cattaneo in Castellanza and author of essays on corporate governance, economic and legal issues. He is the editor of "Rivista dei Dottori Commercialisti" and is a professional advisor in Milan. He is a member of the Board of Directors of Seat PG SpA, Interpump Group SpA, IMMSI SpA and Intesa Private Banking SpA. He is Chairman of the Board of Statutory Auditors of Luxottica Group SpA and Mediobanca SpA. He is an auditor of Gruppo Lactalis Italia SpA and Egidio Galbani SpA. He has been an independent Director of Eni SpA since May 2005.

Mario Resca graduated in Economics from the Bocconi University, Milan. He is Chairman of Italia Zuccheri SpA (formerly Eridania SpA), Casinò di Campione SpA and Confimprese. He is Director of Mondadori SpA, ARFIN SpA (insurances) and Finance Leasing SpA. He is Vice Chairman and venture partner of McDonald’s Development Italia, Inc and advisor of British Telecom Italia. As a graduate he worked for the Chase Manhattan Bank. In 1974 he was appointed director of Biondi Finanziaria (Fiat Group) and from 1976 to 1991 he was partner of Egon Zehnder. In this period he was appointed director of Lancôme Italia and of companies belonging to the Rizzoli-Corriere della Sera Group and Versace Group. He was Chairman of the American Chamber of Commerce. He also served as Chairman of Sambonet SpA, Kenwood Italia SpA and was a founding partner of Eric Salmon & Partners. In 2008, he was appointed General Director of Italian Museums by the Government. He has been an independent Director of Eni SpA since 2002.

Pierluigi Scibetta graduated in Economics from the University La Sapienza, Rome. He is a chartered accountant and auditor and has been appointed director and auditor of a number of public bodies and companies. In 2003 he was appointed director of the Istituto Superiore per la Previdenza e la Sicurezza sul Lavoro - ISPESL (the State Agency for Employee Safety) and of Gestore del Mercato Elettrico SpA. He lectures in Environmental Economics at the University of Perugia. He has been an independent Director of Eni SpA since May 2005.

Francesco Taranto graduated in Economics from the Catholic University of Milan. He began working in 1959, in a stock brokerage in Milan; from 1965 to 1982 he worked at Banco di Napoli, as deputy director of the stock market and securities office. He was director of securities funds at Eurogest from 1982 to 1984, general director and chief executive officer 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. He has also been a member of the steering council of Assogestioni and of the corporate governance committee for listed companies formed by Borsa Italiana. He was a director of Enel SpA from October 2000 to June 2008, and is currently a member of the Board of directors of Banca Carige, Cassa di Risparmio di Firenze, Unicredit Xelion Banca, Pioneer Global Asset Management (Unicredito group) and Kedrios. He has been an independent Director of Eni since June 2008.

Claudio Descalzi graduated in Physics from the University of Milan and attended specialist courses in Petroleum Engineering in France and USA. He joined the Eni Group in 1981 as oil & gas field petroleum engineering and project manager. He served in various managing positions in the Exploration & Production Division. In 2006 he was appointed Deputy Chief Operating Officer of the Exploration & Production Division and

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Chairman of Assomineraria. In 2008 he was appointed Chief Operating Officer of Eni’s Exploration & Production Division.

Domenico Dispenza graduated in Aeronautical Engineering from the Politecnico of Milan and obtained a Master’s Degree in Advanced Technologies. He joined Snam’s study department in 1974. He served in various managing positions in Eni Group companies engaged in natural gas activities. In 2004 he was elected Chairman and CEO of Snam Rete Gas SpA and in 2006 he was appointed Chief Operating Officer of Eni’s Gas & Power Division.

Angelo Caridi graduated in Civil Engineering from the Politecnico of Turin. He joined Snamprogetti in 1970. He served in various managing positions within Eni’s Group companies. In 2002 he was appointed Managing Director and CEO of Snamprogetti in 2005. In August 2007 he was appointed Chief Operating Officer of Eni’s Refining & Marketing Division. He is non-executive director of Saipem SpA.

Alessandro Bernini started his career in 1979 at the auditing firm Neutra Revisioni Sas. In 1981, he joined Ernst & Young and in 1995 he was appointed Partner. On September 1, 1996 he joined the Eni Group in the quality of Chief Financial Officer of Saipem SpA, and was appointed Group Chief Financial Officer for Saipem Group. He has been appointed Chief Financial Officer of the Eni Group in August 2008.

Massimo Mantovani is an attorney at law and worked as a legal counsel for international activities before joining Snam’s legal office in 1993. He was responsible for legal affairs at Eni’s Gas & Power Division until he was appointed Eni’s Senior Vice President for legal affairs in 2005.

Rita Marino has a degree cum laude in Economics from the LUISS and worked in Stet and then in Telecom Italia where she spent most her professional career, carrying out several managerial assignments in the Planning and Control Department. She has also achieved a well-established experience in the Merger & Acquisition Department, managing several and important corporate transactions. In March 2003 she started working for Enel where she was Head of the Strategy, Control and Procurement Processes Area and Corporate Procurement. She was also Chief Operating Officer in a company of the Enel Group and member of the board of several companies of Telecom Italia Group and Enel Group. She has been Chief of the Internal Auditing Department since July 1, 2005 when she joined Eni.

Stefano Lucchini graduated in Economics from the LUISS in Rome and joined the study department of Montedison. After a period in the United States, where he was assistant to the Chairman of the Energy and Commerce Commission of the U.S. Congress, he was head of communications at Montedison USA. In 1993 he returned to Italy and was head of the investor relations department for the Ferruzzi and Montedison Group. He was then Director for external relations at Enel and later at Confindustria and Banca Intesa. He joined Eni as Senior Executive Vice President for Public Affairs and Communication in 2005. He is also a professor at the School for Journalism of the Università Cattolica in Milan.

Leonardo Maugeri has two degrees and a research doctorate, after extensive academic experience acquired in Italy and abroad, joined the Eni Group in 1994, holding various positions mainly as counsel for strategic decisions before being appointed as Senior Executive Vice President for Strategies and Development Department. Maugeri is also a director of Polimeri Europa SpA, Italgas and the Fondazione Mattei. He is member of the Energy Advisory Board and the World Economic Laboratory of the Massachusetts Institute of Technology (MIT), as well as the International Councillor Board of the Center for Strategic and International Studies (CSIS - Washington, D.C.), the Energy Advisory Board of Accenture, the Foreign Policy Association (New York) and the Rand Business Forum (Los Angeles).

Salvatore Sardo graduated in Economics from the University of Turin and started his career as an auditor for Coopers & Lybrand. He later joined Telecom Italia where, after the privatization of the company, he was responsible for administration and control. He was Chairman of Pagine Gialle from 1998 to 2001 and returned to Telecom Italia as manager of the Group’s real estate and general services. From 2003 he was procurement and security manager at Enel until 2005 when he joined Eni to become Senior Vice President for Human Resources & Business Services. In 2008 he has been appointed Chief Corporate Operations Officer of Eni.

Roberto Ulissi is an attorney at law. After some years at the Banca d’Italia as an in-house legal counsel he became Director General of the Ministry of Economy and Finance, head of the "Banking and Finance System and Legal Affairs Department". He was Director of state-owned companies, such as Telecom Italia, Ferrovie dello Stato, Alitalia, Fincantieri, and Government representative in the Bank of Italy’s governing council. He was member of several national and European committees as a representative of the Italian Ministry of Economy including, at a national level, the Commission for the Reform of Corporate Law and, at an 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 has also been special professor of banking law at the University of Cassino. He is a Grande Ufficiale della Repubblica Italiana. Since 2006 he has been appointed Senior Executive Vice President for Corporate Affairs and Governance Department at Eni and a member of the board of Eni International BV. He also holds the position of Company Secretary on the Board of Directors of Eni.

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Raffaella Leone worked for Techint SpA, Pilkington Plc and Enel SpA before joining Eni in 2005 as Executive Assistant to the CEO. She is Vice President of Eni Foundation and member of the Board of Fondazione Eni Enrico Mattei, as well as member of the Board of other Eni companies.

 

Board Practices

Eni’s governance structure follows the traditional model defined by the Italian Civil Code and the Eni’s Corporate Governance Code (adopted in line the provisions of the Borsa Italiana Corporate Governance Code) with managerial functions entrusted to the Board of Directors, as the central body of the corporate governance system, for the purpose of achieving the Company’s purpose.

Monitoring functions are entrusted to the Board of Statutory Auditors while accounting control and the audit of the financial statements is entrusted to external auditors appointed by the Shareholders’ Meeting.

According to Eni’s By-laws, the Board of Directors delegates specific powers to the CEO who is responsible for the management of the Company, with the exception of those powers that cannot be delegated according with current legislation and of those retained exclusively by the Board of Directors on the matter regarding major strategic, operational and organizational decisions. Furthermore, the Board of Director has delegated the Chairman powers for researching and promoting integrated projects and strategic international agreements.

Eni’s governance model, therefore, states a clear separation between the role of the Chairman, and that of the CEO. According to Article 25 of Eni’s By-laws, the Chairman and the CEO represent the Company. In accordance with Article 27 of Eni’s By-laws, the Chairman also chairs the Shareholders’ Meeting, calls and chairs meetings of the Board of Directors and controls the application of decisions made by the Board. The Board of Directors has also established committees with consulting and advisory functions.

The Board of Directors also appointed three Chief Operating Officers responsible for the three operational divisions of Eni SpA and – in accordance with internationally-accepted principles of corporate governance – set up internal committees of the Board with advisory and consultative powers.

Duties and Responsibilities

A review of the Board’s power is represented below. The following duties and responsibilities are in addition to those that cannot be delegated under applicable laws.

1.		Establishes the Company and Group Corporate Governance system and rules. In particular, after consulting the Internal Control Committee, the Board approves the rules that ensure the substantial and procedural transparency and correctness of the transactions carried out with related parties and those in which a Director holds an interest, on his behalf or on behalf of third parties. The Board adopts a procedure for the management and disclosure to third parties of documents and information concerning the Company, having special regard to price sensitive information.
2.		Establishes among its members one or more committees with advisory and consulting tasks, appoints their members, establishes their responsibilities, determines their compensation and approves their regulations.
3.		Confers and revokes the powers of the CEO and the Chairman; establishes terms, limits and operating methods of the exercise of such powers and determines the compensation related to the powers, on the basis of proposals from the Compensation Committee and after consulting the Board of Statutory Auditors. The Board may issue instructions to the CEO and the Chairman and reserve to itself any operations that pertain to its powers.
4.		Establishes the guidelines of the organizational, administrative and accounting structure of the parent Company, including the internal control system, the main subsidiaries and the Group; evaluates the adequacy of the organizational, administrative and accounting structure designed by the CEO in particular with regard to the management of conflicts of interest.

5.

Establishes, in particular, based on the recommendations of the Internal Control Committee, the guidelines of the internal control system, in order to ensure the identification, measurement, management and monitoring of the main risks faced by the Company and its subsidiaries. It evaluates adequacy, effectiveness and effective functioning of the internal control system managed by the Chief Executive Officer on an annual basis.

6.		Establishes, based on the recommendation of the Chief Executive Officer, Company and Group strategic guidelines and targets, including Sustainability policies. It reviews and approves the Company’s and Group’s strategic, operational and financial plans and the strategic agreements to be entered into by the Company. It examines and approves the Company’s non-profit activities plan and approves unplanned expenditures that amount to more than euro 500,000.
7.		Examines and approves annual budgets for Eni’s Divisions and the Company, as well as the Group’s consolidated budget.

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8.		Examines and approves the Company’s and Group’s interim financial report and quarterly consolidates accounts, as per current regulations. Examines and approves the sustainability report, submitted also to the Shareholders’ Meeting.
9.		Receives from Board members with delegated powers, at every Board meeting or at least every two months, reports informing the Board of activities carried out in exercising the delegated powers as well as updates on activities carried out by the Group and on atypical or unusual transactions or transactions with related parties that were not previously submitted to the evaluation and approval of the Board. In particular,

it receives a half-year report on the changes of approved capital projects indicated under 12 (b) and 12 (c) below on the basis of criteria defined by the Board itself.

10.		Receives half-year updates on the Board Committees’ activities.
11.		Evaluates the general performance of the Company and the Group, on the basis of information received from Board members with delegated powers, with particular attention to situations of conflicts of interest and compares results achieved as contained in the annual report and interim and quarterly reports, with the budget.

12.

Evaluates and approves any transaction executed by the Company and its subsidiaries that have a significant impact on the company’s results of operations and liquidity. Particular attention is paid to situations in which Board members hold an interest on their own behalf or on behalf of third parties, and to related parties transactions. The Board ensures the principle of not interfering in the decision making process of the Group listed subsidiaries and subsidiaries subject to unbundling regulation. It also ensures the confidentiality of trade relations between said subsidiaries and Eni or third parties for the protection of the subsidiaries’ interests. Transactions with a significant impact on the Company’s results of operations and liquidity include the following:

(a)

acquisition and disposal of investments, businesses and individual properties, contributions in kind, business combinations, mergers and de-mergers, winding-up of businesses, in each case exceeding euro 100 million, notwithstanding Article 23.2 of the By-laws;

		(b)		capital expenditures exceeding euro 300 million, or less if of particular strategic importance or particularly risky;
		(c)		any exploration initiatives and portfolio operations in the E&P sector in new areas;
		(d)		sale and purchase contracts relating to goods and services other than capital goods, for an amount exceeding euro 1 billion or a duration exceeding twenty years or gas supply contracts for at least 3 billion cubic meter per year for a ten-year term;
		(e)		financing to entities other than subsidiaries: (i) for amounts exceeding euro 200 million, if the amount is proportionate to the interest held or, (ii) in any case, if in favor of non-related companies or the amount is not proportionate to the interest held; and
		(f)		issuing by the Company of personal and real guarantees to entities other than subsidiaries: (i) for amounts exceeding euro 200 million, if in the interest of the Company or of Eni subsidiaries, or associates, as long as the guarantee is proportionate to the interest held or, (ii) in any case, if the guarantees are issued in the interest of associates and the amount is not proportionate to the interest held. In order to issue the guarantees indicated in section (i) of letter f), if the amount ranges between euro 100 million and euro 200 million, the Board confers powers to the CEO and the Chairman, to be exercised jointly in case of urgency.

13.		Appoints and revokes, on recommendation of the CEO and in agreement with the Chairman, the General Managers of Divisions and attributes powers to them. In case of the Chief Executive Officer’s appointment as General Manager, the Chairman makes the proposal.
14.		Appoints and revokes, on recommendation of the CEO and in agreement with the Chairman, and with the approval of the Board of Statutory Auditors, the Manager charged with preparing the Company’s financial reports as per Legislative Decree No. 58/1998. Moreover the Board of Directors verifies the adequacy of his powers and resources in order to fulfill this task and the observance of relevant administrative and accounting procedures prepared by him.
15.		Appoints and revokes, on recommendation of the CEO and in agreement with the Chairman, after consulting the Internal Control Committee, the person in charge of internal control and the Internal Audit Manager, determining his/her compensation in line with the Company’s remuneration policies, and approves the guidelines set for those activities.

16.		Ensures a person is identified as responsible for handling the relationships with the Shareholders.
17.		Establishes, on the basis of the proposals received from the Compensation Committee, the criteria for top management compensation and implements the stock incentive plans approved by the Shareholders’ Meeting.
18.		Examines and decides on proposals submitted by the CEO with respect to voting powers and to the appointment of members of the management and control bodies of the main subsidiaries. With specific regard to the shareholders’ meetings of listed companies of the Eni’s Group, the Board ensures the observance of the Corporate Governance Rules regarding the Shareholders’ Meetings.
19.		Prepares the proposals to be submitted to the Shareholders’ Meeting.
20.		Examines and resolves on other matters that the CEO deems appropriate to submit to the Board because of their importance and sensitivity.

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Pursuant to Article 23.2 of the By-laws, the Board resolves on: mergers by incorporation and proportional demergers of at least 90% of directly owned subsidiaries; establishment and winding up of branches; amendments to the By-laws in order to comply with applicable legislation.

During the fiscal year the Board can approve the distribution of interim dividends to shareholders, as per Article 29.3 of Eni’s By-laws.

In its meeting of June 11, 2008, the Board of Directors approved internal rules for the calling and functioning of its meetings.

In 2008, the Board of Directors met 19 times (of which 15 ordinary meetings and 4 extraordinary meetings) for an average duration of 2 hours and 40 minutes. The average attendance rate to Board meetings was 98.66%, the attendance rate of independent non-executive Board members was 98.54%. The attendance rate for the Board currently in office was 98% both for the delegated Director and the independent delegated Director. The Eni Corporate Governance Code (the Eni Code) provides that independent Directors may hold meetings attended exclusively by non-executive independent members. This power was exercised in the meeting of February 22, 2009.

The market is informed, with advance notice normally before the closing of the year, of the dates of meetings convened for the approval or review of annual, semi-annual, full-year preliminary accounts and quarterly accounts, as well as resolution and proposal of interim dividends and final dividends, and related ex-dividend and payment dates. The financial calendar is available on Eni’s website.

In line with international best practices and as provided for by the Eni Code and the Borsa Italiana Code, the Board of Directors performs its self assessment ("Board review") of size, composition and functioning and of the activities of the Board and Board committees, with the support of a specialized consulting firm.

Appointment

See "Item 10 – Limitations on Voting and Shareholdings – Minority protection provisions".

Directors’ independence and integrity requirements

Legislative Decree No. 58 of February 24, 1998 (TUF), as amended by Legislative Decree No. 303 of December 29, 2006 states that at least one member, or two members if the Board is composed by more than seven members must possess the independence requirements provided for Statutory Auditors of listed companies, as per Article 148, paragraph 3, of same rule.

Article 17.3 of Eni’s By-laws states that at least one member, if the Board is made up by up to five members, or three Board members, in case the Board is made up by more than five members, shall have those independence requirements. This rule actually increases the number of independent Directors in Eni’s Board, as compared to what is required by the law. In addition Eni’s By-laws provide for a mechanism that supports Eni’s voting system by ensuring in any case the presence of the minimum number of independent directors in the Board. Eni’s Code contemplates further independence requirements, in line with those provided by the Corporate Governance Code promoted by Borsa Italiana.

The TUF, as implemented in Article 17.3 of Eni’s By-laws, provides that the persons acting as Directors and Chief Operating Officers of listed companies shall possess the integrity requirements prescribed to members of control entities of listed companies. Directors must comply with additional specific requirements.

In accordance with Article 17.3 of Eni’s By-laws, the Board periodically evaluates independence and integrity of Directors and the absence of reasons for ineligibility and incompatibility. The Eni Code also provides for the Board of Statutory Auditors to verify the proper application of criteria and procedures adopted by the Board to evaluate the independence of its members.

In accordance with Article 17.3 of Eni’s By-laws, should the independence and integrity requirements be impaired or cease or should other reasons of ineligibility arise, the Board declares the termination of office of the member lacking said requirements and provides for his substitution or, alternatively, allows any impaired director to eliminate any reasons for incompatibility within a fixed deadline. Board members are expected to inform the Company if they lose their independence and integrity requirements or of any reasons for ineligibility or incompatibility that might arise.

On February 26, 2009 as part of the periodic assessment of each Board member’s requirements provided by the law and Eni’s By-laws, the Board of Directors has verified that all its members possess the integrity requirement, on the basis of individual statements received. In addition, the Board has declared seven out of its nine members as independent, in accordance with applicable laws, Eni’s By-laws and the Eni Code, with specific reference to non

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executive directors: Alberto Clô, Paolo Andrea Colombo, Paolo Marchioni, Marco Reboa, Mario Resca, Pierliugi Scibetta and Francesco Taranto.

The Board of Statutory Auditors verified in its meeting of March 3, 2009, the proper application of criteria and procedures adopted by the Board to evaluate the independence of its members.

Admissible positions in other companies

In its meeting of June 11, 2008, the Board of Directors expressed its opinion on the matter of the admissible number of positions held by Directors in other companies, as required by the Eni Code, confirming the opinion of the preceding Board, as follows:

•

an executive director should not hold: (i) the position of executive director in any other Italian or foreign listed company, or in any finance, banking or insurance company or any company with a net equity exceeding euro 10 billion; and (ii) the position of non-executive director or statutory auditor (or member of any other advisory committee) in more than three of said companies; and

•

a non-executive director, should not hold further positions than the one held in Eni, as: (i) executive director in more than one of the companies mentioned above and non-executive director or statutory auditor (or member of any other control body) in more than three of the mentioned companies, or as (ii) non-executive director or statutory auditor in more than six of the mentioned companies.

All the positions held in Eni’s subsidiaries are excluded for the purposes described above.

In case a director exceeds said limits in terms of positions held, he should timely inform the Board, who shall judge the situation taking into account the interest of the Company and call upon the interested director to make a decision on the matter. In any case, before accepting the office of director or statutory auditor (or member of any other control entity) of a company not related to Eni, the executive director informs the Board of Directors that evaluates its compatibility with his office at Eni and the interests of Eni. This rule applies also to the Chief Operating Officers of Eni’s divisions.

The Board’s resolution on this matter is published on Eni’s website in the Corporate Governance section.

On the basis of available information, at the Board’s meeting of February 26, 2009, the Board of Directors verified that the number of positions held in other companies by each Board member complies with the above mentioned limits.

Transaction in which a director has an interest and related parties transactions

As requested by the Eni Code, in accordance with the Borsa Italiana Code, the Board of Directors, with the opinion of Internal Control Committee, has adopted on February 12, 2009, the internal guidelines on transactions in which a Director (or a Statutory Audit) has an interest and on transactions with related parties⁴, with the aim to ensure the observance of transparency and fairness principles requested by the applicable laws and regulations for the above mentioned transactions.

In particular in its guidelines the Board:

Therefore, these guidelines define Eni’s Group policy on these matters (for detailed information on 2008 operations, see "Item 7.B – Related party transactions").

As provided for by the Eni Code, these guidelines also regulate the transactions in which a Director and Statutory Auditor has an interest, providing, in particular that:

 

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(4)

i

Until the approval of said guidelines, relevant transactions with related parties (excluding standard ones) – as identified according to IAS 24 and according to the specific internal financial reporting regulation of July 4, 2006 and of December 20, 2007 – have been submitted to the Board of Directors, even if their amount was lower than the threshold defined for its competence.

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Board Committees

The Board has instituted, as provided for by the Eni Code, three internal committees with advisory and consulting tasks: (a) the Internal Control Committee, (b) the Compensation Committee and (c) the Oil-Gas Energy Committee. Their composition, tasks and functioning are defined by the Board of Directors, with specific regulations, in respect of the criteria established by the Eni Code.

The committees provided by the Eni Code (the Internal Control Committee and the Compensation Committee) are made up of at least three members and in no case by a number higher than the majority of Board members. All committees must be composed exclusively of non executive directors, the majority of whom are independent.

In its meeting of June 11, 2008, the Board appointed the following non executive directors, all of them independent, as members of the Committees:

Internal Control Committee

The Internal Control Committee was established in Eni in 1994 and is entrusted with advisory and consulting tasks in respect of the Board in the matter of internal control system. It is composed exclusively of independent directors, provided with the professional qualification required by the Eni Code⁵ and reports to the Board at least every six months at the date of the approval of the annual and semi-annual financial statements on the activity performed as well as on the adequacy of the internal control system.
The Committee performs the following main tasks:

In 2008, the Internal Control Committee convened 18 times, with an average attendance rate of 92%, and reviewed the following items: (i) the 2007 audit activities report and the 2008 audit plan and its periodic progress; (ii) the 2007 audit activities report and 2008 audit plan prepared by the internal audit functions of Saipem and Stogit functions; (iii) outcomes of planned and unplanned Eni’s internal audit activities, as well as results of monitoring activities on progresses made by operating units in implementing planned remedial actions in order to eliminate

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(5)	i	Unlike the Code of Borsa Italiana, the Eni Code requires that at least two (and not only one) Board members have adequate expertise in accounting and financial matters.
(6)	i	Eni entrusted to the Board of Statutory Auditors the role of Audit Committee under the SOA and therefore of assessing the proposals of external auditors and the monitoring of their activity.

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deficiencies highlighted by internal audit activities with special attention to specific issues; (iv) outcomes from Eni’s internal auditing interventions as specifically required by Eni’s control bodies; (v) the periodic reports concerning complaints collected; (vi) the report on Eni’s internal control system prepared by the Manager delegated for the internal control and the compliance with the independence requirements of this Manager; (vii) the future role, tasks and responsibilities of the Manager delegated for the internal control and of Eni’s Internal Audit function and the guidelines approved by the Board of Directors concerning internal audit activities; (viii) updating of the Eni’s Internal Audit operating handbook; (ix) disclosures of information or notification regarding certain inquiries conducted by both Italian or foreign judicial and administrative authorities with reference to crimes or other kind of infringements which involve Eni and all its subsidiaries, in Italy or abroad, and their directors and employees; (x) disclosures on the development of pending litigation; (xi) the essential features of the 2007 Eni’s financial statements, on a consolidated and individual basis, through meetings with top level representatives of Eni’s and its subsidiaries’ administrative functions, and with Chairmen (or others members) of Boards of Statutory auditors and responsible partners from independent audit companies for each subsidiary; accounting treatment adopted for specific transactions; the draft 2008 interim consolidated report prepared on the basis of the EU transparency directive and relevant opinion of external auditors confirming the compliance of this report with IAS 34; (xii) procedures and systems used for evaluating, classifying and reporting hydrocarbon reserves; (xiii) the essential features of Eni’s Annual Report on Form 20-F, progress on implementation of SOA activities and updating on programs and controls for 2008 to prevent and detect frauds; (xiv) the report on the administrative and accounting setup of the Manager responsible for the preparation of the Company’s financial report and the report on the internal control system over financial reporting; (xv) the implementation plan regarding Article 36 of Consob Decision No. 16191/2007; (xvi) the report on the internal control system, that was included in the Corporate Governance section of the 2007 Annual Report; (xvii) guidelines on financial statements auditing, the report on audit reports for 2007 prepared by external auditors, auditing strategies for 2007 and 2008; (xviii) updating of Eni’s Model 231 and the periodic report presented on activities performed by the Company Watch Structure, also by meetings with its members as provided for the new version of Model 231 (the Company’s internal control structure) approved by Eni’s Board of Directors in March 2008; (xix) update on Eni’s guideline for management and control of financial risk; (xx) information on Circular No. 330 of October 14, 2008 concerning Group’s procedures for the procurement of works, goods and services; the main aspects of a Company’s project of process reengineering (BPR) concerning group procurement and updating of the procedures for reviewing suppliers selection following detection of illegal behaviors; (xxi) periodic report in the procedure for the ascertainment of alleged illicit behavior on the part of Eni employees, as per Circular No. 301 of December 14, 2007; (xxii) information of Circular No. 305 of December 20, 2007 concerning dissemination and reception of laws and regulations; (xxiii) review of the draft report of directors under Article 2433-bis of the Civil Code on interim dividends for 2008; (xxiv) information on the development plan of Eni Trading & Shipping activities; and (xxv) logical-operational flows of Eni communication activities.

Compensation Committee

The Committee is entrusted with proposing tasks on the matters of compensation of the Chairman and the CEO as well as the Board Committees members, and examining the indication of the CEO, on the following: (i) long-term incentive plans including stock-based compensation; (ii) criteria for the compensation of the managers with strategic responsibilities; and (iii) the setting of objectives and the assessment of results of performance and incentive plans.

In 2008, the Compensation Committee met 4 times with a 100% attendance, and accomplished the following: (i) examined the 2007 results and the objectives for 2008 in view of defining annual and long-term incentives; (ii) reviewed the bonuses of the Chairman and CEO based on 2007 performance; (iii) reviewed the benchmarks for the managers with strategic responsibilities remuneration and the criteria of the annual remuneration policy; (iv) remuneration and rules applying to the CEO and General Manager Paolo Scaroni and remuneration for the powers delegated to the Chairman; and (v) the implementation of the long-term incentive plans for the year 2008 and relevant grants to the CEO.

Board of Statutory Auditors

In line with Italian legislation, as specified in Article 28 of Eni’s By-laws, the Board of Statutory Auditors consists of five effective members (and two alternate) who must comply with specific expertise and integrity requirements.

The following table sets forth the names, positions and year of appointment of the members of the Board of Statutory Auditors elected by the Ordinary Shareholders’ Meeting held on June 10, 2008 for a three year term, until the Shareholders’ Meeting approval of financial statements for year ended at December 31, 2010.

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Name		Position		Year first appointed to Board of Statutory Auditors
Ugo Marinelli		Chairman		2008
Roberto Ferranti		Auditor		2008
Luigi Mandolesi		Auditor		2008
Tiziano Onesti		Auditor		2008
Giorgio Silva		Auditor		1999
Francesco Bilotti		Alternate Auditor		2005
Pietro Alberico Mazzola		Alternate Auditor		2005

Roberto Ferranti, Luigi Mandolesi, Tiziano Onesti and Francesco Bilotti were candidates in the list presented by the Ministry of Economy and Finance; Ugo Marinelli, Giorgio Silva and Pietro Alberico Mazzola were candidates in the list presented by institutional investors coordinated by institutional investors.

Tasks

The Board of Statutory Auditors, in accordance with the TUF provisions, monitors: (i) the compliance with the laws and with Eni’s By-laws; (ii) the observance of the principles of correct administration; (iii) the adequacy of the Company’s organizational structure, for matters within the scope of its authority, of the internal control system and of the administrative and accounting system as well as the reliability of the latter in fairly representing the Company’s transactions; (iv) the actual implementation of corporate governance rules foreseen by the Borsa Italiana Code to which the Company adheres; and (v) the adequacy of instructions conveyed by the Company to its subsidiaries to ensure fulfillment of reporting obligations provided by applicable laws.

Moreover, according to the TUF and the Eni Code, the Board of Statutory Auditors oversight the appointment, retention and work of the Company’s principal external auditors: to this extent the Board of Statutory Audit (i) submit to the Shareholders’ Meeting called for its approval, a motivated proposal for the appointment of the principal external auditors and for their fees and (ii) monitors the independence of the principal external auditors, verifying both the compliance with the provisions of applicable laws and regulations governing the matter, and the nature and extent of services other than the audit services provided to Eni Group companies (also through entities belonging to the auditors’ network).

As provided for Article 23.3 of Eni’s By-laws, the Board of Statutory Auditors is timely informed, at least on a quarterly basis, by the Board of Directors, on the activities and on the most relevant operations regarding the operational, economic and financial management of the Company and of its subsidiaries.

Statutory Auditors are required to attend the Shareholders’ Meeting and the meetings of the Board of Directors and must promptly notify Consob, the public Authority responsible for regulating the Italian securities market of irregularities found in the performance of their oversight activity.

In 2008, the Board of Statutory Auditors met 22 times. Average duration of meetings was 3 hours and 30 minutes. In 2008 attendance rate was 95% of its members and 93% at Board of Directors’ meetings. The current Board showed attendance rate of 98.4% of members in its own meetings and 92.8% at Board of Directors’ meetings.

Board of Statutory Auditors as Audit Committee

The Board of Directors, in its meeting of March 22, 2005, in accordance with the provision of the U.S. Securities Exchange Commission (SEC) for non-U.S. private issuers (SEC rule 10A-3), identified in the Board of Statutory Auditors the body that, meeting the requirements provided for the above mentioned rule, starting from June 1, 2005, performs, to the extent permitted by Italian legal or listing requirements, the functions assigned by SEC rules and the Sarbanes-Oxley Act (SOA) to the Audit Committee of U.S. registrant.

On June 15, 2005, the Board of Statutory Auditors approved its chart for carrying out the tasks attributed to the audit committee under mentioned U.S. laws and regulations⁷. This charter is published 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 proposals presented by the external auditors for their appointment and making its promted recommendation to the Shareholders’ Meeting about the proposal for the appointment or the retention of the external auditor;

 

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(7)

The chart was amended on March 30, 2007, taking into account changes introduced by Legislative Decree No. 303 of 2006 on Article 159, paragraph 1 of TUF, and by the Eni’s Code, as well as to take into account the variations adopted in the organization structure, in respect to the one existing on June 15, 2005, when the previous chart was approved.

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•		performing the activities of oversight of the work of the external auditor engaged for the audit or performing other audit, review or attest 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 admissible non-audit services, analytically identified, and examine the information on the execution of the authorized services;
•		evaluating any request to have recourse to the external auditor engaged for the audit for admissible non audit services and expresses its opinion to the Board of Directors;
•		examining the periodical communications 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 the management;

•

examining complaints received by 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 complaints received by 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.

Appointment, requirements and other duties

Like the Directors and in accordance with applicable regulations, the Statutory Auditors are appointed by means of a list vote as provided for by Eni’s By-laws. At least two Auditors and one alternate are elected from lists presented by minorities and the Chairman of the Board of Statutory Auditors shall be elected from a list other than the one obtaining the majority of votes (for a detailed description of the procedure, see "Item 10 – Minority protection provisions").

As stressed in the Code, the Statutory Auditors shall act with autonomy and independence also towards the shareholders who elected them and, in accordance with the TUF, they shall possess the independence, expertise and integrity requirements prescribed by a regulation of the Minister of Justice. As for the professional qualifications of the candidates, Article 28 of Eni’s By-laws, in line with the said Decree of the Minister of Justice, foresees that the professional requirements can also be acquired with at least three years of professional experience or by teaching business law, business administration and finance, as well as at least a three year experience in a managerial position in geological or engineering businesses. Eni’s Auditors are all chartered auditors.

Statutory Auditors declared consequently to possess independence, integrity and expertise requirements as foreseen by the applicable law. In compliance with the Eni Code prescriptions designed to ensure that auditors are independent subsequently to their appointment based also on the Code provisions for the same matter in the case of directors, the Board of Statutory Auditors in its meeting of January 21, 2009 verified that all its members possess such requirements (independence, integrity and expertise) and the Board of Directors in its meeting of February 26, 2009 verified this certification.

With reference to positions held in other companies, until coming into force of new Consob regulation on this matter, Eni’s By-laws prohibited the appointment as statutory auditor of persons that were already statutory auditors or members of the supervisory board or members of the management control committee of at least five companies in regulated markets other than listed subsidiaries of Eni SpA. In light of that, appointed Auditors communicated to the Company their positions in other entities and subsequently the Board of Statutory Auditors verified compliance with the said limit as provided by Eni’s By-laws. As of June 30, 2008, accordingly with the By-laws provisions, Statutory Auditors may assume positions in governing or controlling bodies in companies other than Eni within the limits set by the mentioned Consob regulation. In September 2008 Eni’s Statutory Auditors communicated to Consob their compliance with said limits.

External Auditors

As provided for by Italian law, the auditing of financial statements is entrusted to external auditors registered on the register held by Consob. The external auditor is appointed and its fee is determined by the Shareholders’ Meeting on reasoned proposal of the Board of Statutory Auditors.

Eni’s external auditor, PricewaterhouseCoopers SpA, was appointed for the first time on June 1, 2001 and was reappointed by the ordinary Shareholders’ Meeting on May 28, 2004, for a term of three financial years. The

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Shareholders’ Meeting of May 24, 2007 resolved to renew the appointment for the 2007-2009 period in accordance with Legislative Decree No. 303/2006, as it did not yet complete the maximum nine financial year engagement allowed by the law.

At the end of this engagement, PricewaterhouseCoopers SpA will cease to act as Eni’s external auditors.

In 2008, Eni’s External Auditors met with Eni Statutory Auditors in order to discuss: (i) critical accounting policies and practices applied for the purpose of a proper representation of Eni’s results of operations and financial condition; (ii) alternative accounting treatments provided for by generally accepted accounting principles concerning material items discussed with management, including ramifications of the use of, the impact deriving from the application of said alternative disclosures and treatments and relevant information, as well as the treatments preferred by external auditors; and (iii) the contents of any other material written communication between external auditors, and management.

For a description of the special powers of the State, see "Item 10 – Memorandum and Articles of Association – Limitations on Voting and Shareholdings – Special Powers of the State" below.

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.

Main elements of the compensation of the Chairman, the CEO, other Board members and Eni’s three General Managers are described below.

CHAIRMAN
The compensation of the Chairman of the Board of Directors has been resolved by Eni’s Shareholders’ Meeting and includes:

(a)		a base salary of euro 265,000 and reimbursement of out of pocket expenses; and
(b)		a bonus which amount is determined in accordance with the performance of Eni shares in the reference year as compared with the performance of the seven largest international oil companies for market capitalization, taking account of the dividend paid. This bonus will amount to euro 80,000 or euro 40,000, depending on whether the performance of Eni shares is rated first or second, or third or fourth in the reference year, respectively. No bonus is paid in case Eni scores a position lower than the fourth one. In 2007, Eni rated seventh and in 2008 the bonus was not paid.

With regard to the powers delegated to the Chairman, the Board of Directors determined further compensation, as follows:

(a)		an annual emolument of euro 500,000; and
(b)		an annual performance bonus based on the achievements of the Company’s target determined in the same way as for the CEO (see below). In 2008, based on 2007 Eni’s results, a bonus equal to 115% of the target level was determined, within an interval ranging from 85% to 130% of said target level. The target level of the bonus is 60% of the annual emolument. In 2008, this bonus amounted to euro 345,000.

Compensation of the Chairman also includes an insurance against death or permanent inability caused by injury or sickness in the exercise of his duties or under certain other circumstances as stipulated collectively for all managers of Italian companies producing goods and services. In particular, a specific insurance policy has been underwritten which guarantees euro 500,000 to survivors.

CEO
Compensation for the CEO has been resolved by the Board of Directors of Eni in connection with his position both as CEO and as General Manager of the parent company Eni SpA.

As General Manager of Eni SpA, his terms of employment are regulated by the "Contratto collettivo nazionale di lavoro per i dirigenti di aziende produttrici di beni e servizi" (the Italian national collective contract for managers of companies producing goods and services), as well as by any internal agreement stipulated by the representatives of managers and Eni SpA.

The CEO compensation includes the following items:

(a)

an annual fixed amount of euro 1,430,000, including a base salary of euro 1,000,000 for the services as General Manager and an emolument of euro 430,000 for the services as CEO;

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(b)		an annual performance bonus based on the achievement of the Company targets. These targets are approved by the Board of Directors on proposal of the Compensation Committee and defined consistently with the targets of the strategic plan and yearly budget. In 2007, said targets included a set level of cash flow from operations (with a 30% weight), divisional operating performances (30%), strategic projects (20%) and corporate efficiency (20%). Results achieved have been assessed assuming a constant trading environment and have been verified by the Compensation Committee and approved by the Board of Directors. The target and maximum amount of this bonus corresponds respectively to 77% and 100% of the fixed amount under a) above. In 2008, based on 2007 Eni’s results, a bonus equal to 115% of the target level was determined, within an interval ranging from 85% to 130% and a bonus of euro 1,267,000 was paid;
(c)		a long-term incentive under the incentive scheme as approved in March 2006 by the Board of Directors as proposed by the Compensation Committee. This incentive scheme provides: (i) a deferred monetary incentive, linked to the achievement of certain Company’s financial performance annual targets; and (ii) stock option awards linked to the achievement of certain performance targets of the Eni share measured in terms of total shareholder return that considers both the stock appreciation and the dividend (see below for a more detailed description of Eni’s long-term incentive schemes applicable to top and senior managers). Under this scheme the CEO received:

(i)

an annual award of a deferred monetary bonus with a target level corresponding to 55% of the fixed amount under a) above. In 2008, this award amounted to euro 1,022,500 that will be paid after three years in connection with the achievement of certain preset Company annual targets in terms of EBITDA (earnings before interest, taxes, depreciation and amortization); and

(ii)

an annual award of stock options for 2008 for a face value corresponding to 10 times the fixed amounts under section a) above. In 2008, a total of 573,000 options were awarded with a vesting period of three years and an exercise price of euro 22.540 corresponding to the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the award;

(d)

severance payments as regulated by Italian laws, which consist of a lump sum to be paid to the employee upon retirement. To this end, the Company recognizes yearly accruals computed by dividing the total remuneration earned as General Manager (base salary, bonuses and stock compensation) by 13.5. The amounts accrued are revaluated yearly at a fixed rate of 1.5% plus the 75% of the yearly official consumer price index increase;

(e)		as an integration to the severance payment described above, should the employment contract of Mr. Scaroni as General Manager of Eni SpA be terminated upon expiry of the term of his office as CEO or upon earlier termination of such office, he will be entitled to receive a payment of euro 3,200,000 plus an amount corresponding to the average performance bonus earned in the three-year period 2008-2010, in lieu of notice thus waiving both parties from any obligation related to notice. This amount will not be paid if the termination of office meets the requirement of due cause as per Article 2119 of the Italian Civil Code, in case of death and in case of resignation from office other than as the result of a reduction in the powers currently attributed to the CEO. Furthermore, upon expiry of the contract as employee of Eni, the CEO in his capacity as General Manager of the parent company is entitled to receive an indemnity that is accrued along the service period by taking into account social security contribution rates and post-retirement benefit computations applied to the CEO annual emolument and 50% of the maximum bonuses earned as a Director. Taking into account that the CEO has been appointed on June 11, 2008, a provision of euro 134,139.23 has accrued in 2008. A sum of euro 644,179.60 corresponding to the global amount accrued over the preceding three-year period of office was paid;
(f)		competition clause: the CEO agrees not to be engaged, on his own account and directly, in any business that may be in competition with the businesses of Eni, as per its By-laws, in Italy, Europe and North America for a year after termination of office. Based on this arrangement, Eni will pay a fee corresponding to euro 2,219,000. As a consequence of any breach of this clause, the CEO would lose the right to such fee and reimburse any amount already paid, and shall pay to Eni damages in an amount agreed among the parties to correspond to twice such non-competition fee;
(g)		the pension scheme corresponds to the scheme applied to Eni managers and provided by INPS (the Italian state social security entity) to all Italian workers. In addition, the CEO is included in an additional pension scheme under the form of an Eni Group pension fund agreed collectively by Eni and Eni managers which provides integration, in the form of a lump sum payment or perpetuity, to the pension paid by the State. This integration is proportional to contributions to the fund made by both the manager and the Company in equal amounts. The integration is awarded to the manager when eligible for the payment of the pension from the State, provided that a minimum time period has elapsed according to the Fund By-laws. An agreement signed on March 20, 2006, established that the Company’s and the manager’s payment to this Fund amounts to 3.5% of total emoluments earned by the CEO in his position as General Manager (i.e. the aggregate of the annual salary and bonuses up to a maximum of euro 200,000);
(h)		like all other Eni managers, Mr. Scaroni is entitled to participate in a health insurance fund financed by Eni managers and Eni which provides reimbursement of certain medical expenses on the basis of rules and parameters as provided by the Fund’s By-laws; and
(i)		insurance against death or permanent inability caused by injury or disease in the exercise of his duties or under certain other circumstances as stipulated collectively for all managers of Italian manufacturing

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companies. In particular a specific insurance policy has been underwritten on behalf of Mr. Scaroni which guarantees euro 7.5 million to beneficiaries in case of death or disability, however determined.

MEMBERS OF THE BOARD OF DIRECTORS
The compensation of members of the Board of Directors has been determined by Eni’s Shareholders’ Meeting and includes:

(a)		an annual emolument of euro 115,000 and reimbursement of out of pocket expenses; and
(b)		a bonus determined in accordance with the performance of the Eni share in a given year as compared with the performance of the seven largest international oil companies for market capitalization, taking account of the dividend paid. Said bonus amounts to euro 20,000 or euro 10,000 depending on whether the performance of Eni shares is rated first or second, or third or fourth in the reference year, respectively. In 2007, Eni rated seventh and in 2008 the bonus was not paid.

The Board of Directors in the meeting of June 11, 2008, as proposed by the Compensation Committee and advised by the Board of Statutory Auditors, confirmed the additional element of remuneration for the Board members holding positions in Board’s committees, with the exclusion of the Chairman and CEO. Said fee amounts to euro 30,000, and euro 20,000 for the position of chairman of a committee and of member of a committee, respectively. This amount decreases to euro 27,000 and euro 18,000 in case a member holds positions in more than one committee.

GENERAL MANAGERS
The terms of employment of the General Managers of Eni’s Divisions are regulated by the "Contratto collettivo nazionale di lavoro per i dirigenti di aziende produttrici di beni e servizi" (the Italian national collective contract for managers of companies producing goods and services), as well as by any internal agreement stipulated by the representatives of managers and Eni SpA. The General Managers of Divisions may be appointed as members of the Board of Directors of Eni subsidiaries and affiliates; compensation deriving from such appointments as provided for by Article 2389 of the Italian Civil Code is to be repaid to Eni as it is included in their remuneration under section a) below.

Their remuneration includes:

(a)		a base salary, defined considering the position held and their specific responsibilities, with reference to appropriate market levels as benchmarked against national and international companies of comparable size, complexity and scope in the oil and gas, industrial and service sectors. Base salaries are reviewed and adjusted on a yearly basis considering individual performance and career progression;
(b)		a performance bonus paid yearly, based on the achievement of specific financial, operational and strategic targets and of individual performance goals pertaining to each business units defined consistently with the Company’s targets in the strategic plan and yearly budget. The target level of the bonus corresponds to 60% of the base salary;

(c)

long-term incentives in the form of a deferred monetary bonus and stock options according to the same scheme as the CEO. Under this scheme the three General Managers have received:

		(i)		a yearly award of a deferred monetary bonus at target level of 40% of the base salary. In 2008, based on 2007 Eni results, the basic deferred bonus awarded was equal to 130% of the target level, within an interval ranging from 70% to 130%; and
		(ii)		a yearly award of stock options for a face value corresponding to 4.5 times the base salary. Options awarded in 2008 have a vesting period of three years and an exercise price of euro 22.540 corresponding to the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the award;

(d)		a severance payment as regulated by Italian laws, which consists of a lump sum to be paid to the employee upon retirement. To this end, the Company recognizes yearly accruals computed by dividing the yearly remuneration (base salary, bonuses and stock compensation) by 13.5. These amounts are revaluated yearly at the rate of 1.5% plus the 75% of the official yearly consumer price index increase;
(e)		the pension scheme corresponds to the scheme applied to Eni managers and provided by INPS to all Italian workers. In addition, the General Managers are included in the additional pension scheme of Eni managers which provides an integration to the public pension. For further details see section g) of the description of compensation of the CEO;
(f)		like all other Eni managers, they are entitled to participate in a health insurance Fund financed by Eni managers and Eni which provides reimbursement of certain medical expenses on the basis of rules and parameters as provided for by the Fund’s By-laws. For further details see section h) of the description of compensation of the CEO; and
(g)		an insurance against death or permanent inability caused by injury or disease in the exercise of his duties or under certain other circumstances as stipulated collectively for all managers of Italian manufacturing companies.

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.

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Remuneration earned for 2008 by members of the Board of Directors, including the CEO and the Chairman, the three Chief Operating Officers and Eni’s senior managers attending on a permanent basis the meetings of the Steering Committee of Eni (total amount) is reported in the table below. Emoluments earned by the Statutory Auditors of Eni are also included.

Below is a description of each column of the following table:

 

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Name

Position

Emoluments for service at Eni SpA

Non-cash benefits

Bonus and other incentives (a)

Salaries and other elements

Total

(thousand euro)

Board of Directors
Roberto Poli		Chairman		768		18		345						1,131
Paolo Scaroni		CEO		430		17		1,267			1,363	(b)		3,077
Alberto Clô		Director		157										157
Paolo Andrea Colombo (c)		Director		64										64
Renzo Costi (d)		Director		85										85
Dario Fruscio (e)		Director		19										19
Paolo Marchioni		Director		64										64
Marco Pinto (d)		Director		85										85
Marco Reboa		Director		157										157
Mario Resca		Director		143										143
Pierluigi Scibetta		Director		149										149
Francesco Taranto		Director		64										64
Board of Statutory Auditors
Paolo Andrea Colombo (d)		Chairman		51							33	(f)		84
Ugo Marinelli		Chairman		64										64
Filippo Duodo (d)		Auditor		35							71	(g)		106
Roberto Ferranti		Auditor		44										44
Edoardo Grisolia (d) (h)		Auditor		35										35
Luigi Mandolesi		Auditor		44										44
Tiziano Onesti		Auditor		44							40	(i)		84
Riccardo Perotta (d)		Auditor		35							32	(l)		67
Giorgio Silva		Auditor		80							24	(m)		104
Chief Operating Officers
Stefano Cao (n)		Exploration & Production				1		2,294	(o)		3,825	(p)		6,120
Claudio Descalzi (q)		Exploration & Production				1					268			269
Domenico Dispenza		Gas & Power				1		856	(r)		710			1,567
Angelo Caridi		Refining & Marketing				2		268			565			835
Other managers with strategic responsibilities (s)						12		3,137			6,475	(t)		9,624
				2,617		52		8,167			13,406			24,242

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(a)	i	Based on performance achieved in 2007.
(b)	i	Including the base salary of euro 1 million paid to the CEO, in his quality of General Manager, indemnities and other elements for a total amount of euro 363,000 accrued along the service period (from 2005 to 2008), net of the indemnities described under the paragraph "post-retirement benefit of the directors".
(c)	i	Chairman of the Board of Statutory Auditors until June 9, 2008.
(d)	i	In office until the Shareholders’ Meeting approving financial statements for the year ending December 31, 2007.
(e)	i	On January 30, 2008 Dario Fruscio resigned from the Board of Directors.
(f)	i	Includes the compensation obtained as Chairman of the Board of Statutory Auditors of Saipem and EniServizi.
(g)	i	Includes the compensation obtained as Statutory Auditor in Snamprogetti SpA and in Polimeri Europa and as Chairman of the Board of Statutory Auditors of CEPAV Uno and CEPAV Due.
(h)	i	Compensation for the service is paid to the Ministry for Economy and Finance.
(i)	i	Includes the compensation obtained as Chairman of the Board of Statutory Auditors of AGI and Servizi Aerei.
(l)	i	Includes the compensation obtained as Chairman of the Board of Statutory Auditors of Snam Rete Gas SpA.
(m)	i	Includes the compensation obtained as Statutory Auditor in Snamprogetti SpA and as Chairman of the Board of Statutory Auditors of TSKJ Italia Srl.
(n)	i	In office until July 31, 2008.
(o)	i	Includes the pro-quota portion of deferred bonus awarded for the 2006-2008 three-year period.
(p)	i	Includes indemnities paid upon termination.
(q)	i	Appointed on August 1, 2008.
(r)	i	Includes long-term incentives awarded by Snam Rete Gas in 2005, for the position of Chairman of Snam Rete Gas held until December 23, 2005.
(s)	i	Managers, who during the year with the CEO and the General Managers of Eni divisions, have been member of the Eni Directors Committee (8 managers).
(t)	i	Includes indemnities paid upon termination.

For the year ended December 31, 2008, the overall compensation of persons responsible of key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive directors, Chief Operating Officers and Eni’s senior managers amounted to euro 25 million. The break-down is as follows:

	2008
	(euro million)

Fees and salaries		17
Post employment benefits		1
Other long-term benefits		3
Fair value stock grants/options		4
		25

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

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their capacity as such are not entitled to receive such severance pay. At December 31, 2008, 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 general managers and Eni’s senior managers was euro 1,548 thousand. The break-down of this amount is presented in the table below:

Name	(euro thousand)

Paolo Scaroni		CEO and Chief Operating Officer of Eni		164
Claudio Descalzi		Chief Operating Officer of the E&P Division		299
Domenico Dispenza		Chief Operating Officer of the G&P Division		418
Angelo Caridi		Chief Operating Officer of the R&M Division		148
Senior managers (a)				519

1,548

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(a)

i

No. 7 managers.

Long-term Incentive Schemes

In March 2006, the Board of Directors approved a new long-term incentive scheme for the managers of Eni and its subsidiaries (excluding listed subsidiaries), as proposed by the Compensation Committee. This new scheme is designed to motivate more effectively and retain managers, linking incentives to targets and performance achieved in a tighter way than previous incentives schemes. This new incentive scheme applies to the 2006-2008 three year period and is composed of a deferred monetary bonus, linked to the achievement of certain business growth and operating efficiency targets, and stock option grants based on the achievement of certain targets of total shareholder return. This scheme has a structure intended to balance monetary and stock-based components of the remuneration, as well as to link economic and operating performance to share performance in the long-term.

Deferred monetary bonus

This leg of the long-term incentive scheme provides a basic bonus paid after three years according to a variable amount equal to a percentage ranging from 0 to 170% of the amount established for the target performance in relation to the performances achieved in a three-year period as approved by the Board of Directors. Performances are measured in terms of achievement of preset annual EBITDA targets, as assessed by comparing actual results with set targets under a constant trading environment.

The following table sets out the basic bonus awarded in the year 2008 to the CEO and to the Chief Operating Officers of Eni’s Divisions, and the total amount awarded to Eni’s senior managers.

Name	Deferred bonus awarded
	(euro thousand)

Paolo Scaroni		CEO and Chief Operating Officer of Eni		1,023
Stefano Cao (a)		Chief Operating Officer of the E&P Division		494
Claudio Descalzi (b)		Chief Operating Officer of the E&P Division		215
Domenico Dispenza		Chief Operating Officer of the G&P Division		385
Angelo Caridi		Chief Operating Officer of the R&M Division		312
Senior managers (c)				1,732	(d)

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(a)	i	Position held until July 31, 2008.
(b)	i	Appointed on August 1, 2008.
(c)	i	No. 8 managers.
(d)	i	Including the deferred bonus granted by Saipem to a manager with strategic responsibilities, appointed in Eni on August 1, 2008.

 

Stock Options

Eni can award share options to managers holding strategic positions or positions of significant responsibility for the achievement of the Company’s results. This incentive scheme is designed to ensure that managers’ interests are aligned with those of shareholders and to stimulate entrepreneurial behavior on part of managers. Differently from previous schemes, the 2006-2008 stock option plan introduced a performance condition upon which grants can be exercised. At the end of each vesting period with a three-year duration, the Board of Directors determines the number of exercisable options, in a percentage ranging from 0% to 100% of the total amount awarded for each year

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of the scheme, depending on the performance of Eni shares measured in terms of annual Total Shareholders Return as compared to that achieved by a panel of major international oil companies in terms of market capitalization. Options can be exercised for a three year period. Under this plan, the Board resolved to make available 7,415,000 options pertaining to 2008 with a strike price equal to euro 22.540 and 6,128,500 options pertaining to 2007 with a strike price equal to euro 27.451.

At December 31, 2008, a total of 23,557,425 options were outstanding for the purchase of an equal amount of ordinary shares nominal value euro 1 of Eni SpA, carrying an average strike price of euro 23.540. The weighted average remaining contractual life of options outstanding at December 31, 2007 and 2008 was 4 years and 7 months and 5 years and 7 months respectively.

The following is a summary of stock option activity for the years 2007 and 2008:

	2007		2008

	Number of shares		Weighted average exercise price (euro)		Market price (a) (euro)		Number of shares		Weighted average exercise price (euro)		Market price (a) (euro)

Options as of January 1		15,290,400			21.022		25.520		17,699,625			23.822		25.120
New options granted		6,128,500			27.451		27.447		7,415,000			22.540		22.538
Options exercised in the period		(3,028,200	)		16.906		25.338		(582,100	)		17.054		24.328
Options cancelled in the period		(691,075	)		24.346		24.790		(975,100	)		24.931		19.942
Options outstanding as of December 31		17,699,625			23.822		25.120		23,557,425			23.540		16.556
of which exercisable at December 31		2,292,125			18.440		25.120		5,184,250			21.263		16.556

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(a)

Market price relating to new rights assigned, rights exercised in the period and rights cancelled in the period corresponds to the average market value (arithmetic average of official prices recorded on Mercato Telematico Azionario in the month preceding: (i) the date of assignment; (ii) the date of the recording in the securities account of the managers to whom the options have been assigned; (iii) the date of the unilateral termination of employment for rights cancelled). Market price of shares referring to options as of the beginning and the end of the year, is the price recorded at December 31.

The fair value of stock options granted during the years ended December 31, 2007 and 2008 of euro 2.98 and euro 2.60, respectively, was calculated applying the Black-Scholes method and using the following assumptions:

			2007		2008

Risk-free interest rate		(%)		4.7		4.9
Expected life		(year)		6		6
Expected volatility		(%)		16.3		19.2
Expected dividends		(%)		4.9		6.1

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The following table presents the amount of stock options awarded to Eni’s CEO, the three Chief Operating Officers and Eni’s senior managers.

  

CEO and COO of Eni

COO of E&P Division

COO of E&P Division

COO of G&P Division

COO of R&M Division

Senior managers (a)

Paolo Scaroni (b)

Stefano Cao (c)

Claudio Descalzi (d)

Domenico Dispenza

Angelo Caridi

Options outstanding at the beginning of the period:
- number of options				1,953,000		406,500		178,500		232,500		269,500	(e)		30,500		122,000	(f)		1,353,000		110,000	(g)
- average exercise price		(euro)		24.165		24.655		24.713		25.159		3.988			22.509		21.098			23.985		18.953
- average maturity in months				63		62		62		60		61			67		60			61		56
Options granted during the period:
- number of options				634,500		-		85,500		147,500					120,000		-			584,000		-
- average exercise price		(euro)		22.540		-		22.540		22.540					22.540		-			22.540		-
- average maturity in months				72		-		72		72					72		-			72		-
Options exercised at the end of the period:
- number of options				-		-		-		-		127,500	(e)		-		-			68,500		29,500	(g)
- average exercise price		(euro)		-		-		-		-		3.530			-		-			16.576		11.881
- average market price at date of exercise		(euro)		-		-		-		-		4.095			-		-			23.996		24.541
Options expired during the period:
- number of options						206,375		-		-		-			-		-			167,550		-
Options outstanding at the end of the period:
- number of options				2,587,500		200,125		264,000		380,000		142,000	(e)		150,500		122,000	(f)		1,700,950		80,500	(g)
- average exercise price		(euro)		23.767		24.060		24.009		24.142		4.399			22.534		21.098			23.670		21.545
- average maturity in months				55		51		55		56		54			65		48			55		48

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(a)	i	No. 8 managers.
(b)		The assignment to the CEO have been integrated by a monetary incentive to be paid after three-year in relation to the performance of Eni shares, and is equal to 96,000 options granted in 2006, with a strike price of euro 23.100 and 80,500 options granted in 2007, with a strike price of euro 27.451.
(c)	i	In office until July 31, 2008.
(d)	i	Appointed on August 1, 2008.
(e)	i	Options on Snam Rete Gas shares: assigned by the company to Domenico Dispenza who held the position of Chairman of Snam Rete Gas until December 23, 2005.
(f)	i	Options on Saipem shares: assigned by the company to Angelo Caridi who held the position of CEO of Snamprogetti until August 2, 2007.
(g)	i	Options on Saipem shares.

Employees

At December 31, 2008, Eni’s employees totaled 78,880, with an increase of 3,018 employees from December 31, 2007, up 4%, reflecting a 2,965 increase in employees hired and working outside Italy and an increase of 53 employees hired in Italy.

Employees hired in Italy were 39,480 (50.1% of all Group employees). Of these, 35,929 were working in Italy, 3,381 outside Italy and 170 on board of vessels, with a 53 unit increase from 2007.

The process of improvement in the quality mix of employees continued in 2008 with the hiring of 2,517 persons, of which 781, were with fixed-term contracts. A total of 1,736 persons were hired with open-end and with apprenticeship contracts, most of them with university qualifications (1,048 persons) and 650 persons with a high school diploma. During the year 2,549 persons left their job at Eni, of these 1,903 had an open-end contract and 646 had a fixed-term contract.

Employees hired and working outside Italy were 38,400 (49.9% of all Group employees), with a 2,965 persons increase, of these approximately 1,800 employees were hired with fixed-term contracts in the Engineering & Construction segment due mainly to new contracts in the Caspian area (Kazakhstan, Kashagan project) and Peru/Venezuela (drilling projects), and 1,642 persons in the Exploration & Production segment, mainly following the purchase of Burren and First Calgary Petroleums (1,150 persons). In the Gas & Power segment, the acquisition of Distrigas concerned 135 persons and in the Refining & Marketing segment, Agip España (850 persons) and Galp Energia were sold.

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Employees at year end		2006		2007		2008

(units)

Exploration & Production		8,336		9,334		11,194
Gas & Power		12,074		11,582		11,389
Refining & Marketing		9,437		9,428		8,327
Petrochemicals		6,025		6,534		6,274
Engineering & Construction		30,902		33,111		35,629
Other activities		2,219		1,172		1,070
Corporate and financial companies		4,579		4,701		4,997
		73,572		75,862		78,880

The table below sets forth Eni’s employees at December 31, 2006, 2007 and 2008 in Italy and outside Italy:

		2006		2007		2008

(units)

Exploration & Production		Italy		5,273		5,535		5,771
		Outside Italy		3,063		3,799		5,423
				8,336		9,334		11,194
Gas & Power		Italy		9,602		9,114		8,810
		Outside Italy		2,472		2,468		2,579
				12,074		11,582		11,389
Refining & Marketing		Italy		7,196		7,101		6,641
		Outside Italy		2,241		2,327		1,686
				9,437		9,428		8,327
Petrochemicals		Italy		4,948		5,476		5,230
		Outside Italy		1,077		1,058		1,044
				6,025		6,534		6,274
Engineering & Construction		Italy		6,164		6,618		7,316
		Outside Italy		24,738		26,493		28,313
				30,902		33,111		35,629
Other activities		Italy		2,219		1,172		1,070
		Outside Italy		-		-		-
				2,219		1,172		1,070
Corporate and financial companies		Italy		4,363		4,411		4,642
		Outside Italy		216		290		355
				4,579		4,701		4,997
Total		Italy		39,765		39,427		39,480
Total		Outside Italy		33,807		36,435		39,400
				73,572		75,862		78,880
of which senior managers				1,603		1,585		1,658

Share Ownership

As of April 30, 2009, the cumulative number of shares owned by the Eni’s directors, statutory auditors and senior managers, including the three Chief Operating Officers, was 242,769 equal to approximately 0.006% of Eni’s share capital outstanding as of the same data. In this time frame, no further options to purchase Eni shares were granted by the Company to those persons (see tables in the section "Stock Option Plans"). 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.

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Name	Position	Number of shares owned

Board of Directors				-
Roberto Poli		Chairman		58,549
Paolo Scaroni		CEO and COO of Eni		-
Alberto Clô		Director		-
Paolo Andrea Colombo		Director		1,650
Paolo Marchioni		Director		-
Marco Reboa		Director		-
Mario Resca		Director		-
Pierluigi Scibetta		Director		-
Francesco Taranto		Director		500
Chief Executive Officers
Claudio Descalzi		Chief Operating Officer of the E&P Division		24,455
Domenico Dispenza		Chief Operating Officer of the G&P Division		99,715
Angelo Caridi		Chief Operating Officer of the R&M Division		40,595
Board of Statutory Auditors				1,000
Senior managers				16,305

 

 

Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

As of May 4, 2009, the following persons were known by Eni to own more than 2% of any class of Eni SpA’s voting securities. At such date, 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		813,443,277		20.3
Cassa Depositi e Prestiti		400,288,338		10.0
BNP Paribas Group		93,822,428		2.3

The Ministry of Economy and Finance, in agreement with the Ministry of Economic Development, retains certain special powers over Eni. See "Item 10 – Additional Information – Memorandum and Articles of Association – Limitations on Voting and Shareholdings – Special Powers of the State". For a discussion of the Eni share buy-back program see "Item 16E – Purchases of Equity Securities by the Issuer and Affiliated Purchasers". As of May 4, 2009 there were 44,072,282 ADRs, each representing two Eni ordinary shares outstanding corresponding to 2.2% 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 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 Note 37 to the Consolidated Financial Statements.

 

 

Item 8. FINANCIAL INFORMATION

Consolidated Statements and Other Financial Information

See Item 18 – Financial Statements.

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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.

 

Environment

Criminal proceedings

ENI SPA
Subsidence. The Court of Rovigo conducted investigations concerning a subsidence phenomenon allegedly caused by hydrocarbon exploration and extraction activities in the Ravenna and North Adriatic area both on land and in the sea. Eni appointed an independent and interdisciplinary scientific commission, composed of prominent and highly qualified international experts of subsidence caused by hydrocarbon exploration and extraction activities, with the aim of verifying the magnitude and effects and any actions appropriate to reduce or to neutralize any subsidence phenomenon in the area. This commission produced a study which excludes the possibility of any risk to human health or damage to the environment. The study also states that worldwide there are no instances of accidents of harm to public safety caused by subsidence induced by hydrocarbon production. It also shows that Eni employs the most advanced techniques for monitoring, measuring and controlling the soil. This proceeding is in the first level hearing stage. The Veneto Region, other local bodies and two private entities have been acting as plaintiffs. Eni was admitted as a defendant. The Court decided that the proceeding must be heard by the Court of Ravenna.

Alleged damage. In 2002, the public prosecutor of Gela commenced a criminal investigation to ascertain alleged damage caused by emissions of the Gela plant, owned by Polimeri Europa SpA, Syndial SpA (formerly EniChem SpA) and Raffineria di Gela SpA. The judge for the preliminary hearing dismissed the accusation of adulteration of food products, while the proceeding for the other allegations regarding pollution and environmental damage remains underway. The trial ended in acquittal with regard to the general manager and officer pro tempore of the refinery. The sentence of the Gela Tribunal stated that the charges were lacking factual basis.

Alleged negligent fire in the refinery of Gela. In June 2002, in connection with a fire at the refinery of Gela, a criminal investigation began concerning alleged negligent fire, environmental crimes and crimes against natural beauty. First degree proceedings ended with an acquittal sentence. In November 2007, the public prosecutors of Gela and of Caltanissetta filed an appeal against this decision.

Investigation of the quality of ground water in the area of the refinery of Gela. In 2002, the public prosecutor of Gela commenced a criminal investigation concerning the refinery of Gela to ascertain the quality of ground water in the area of the refinery. Eni is charged of having breached environmental rules concerning the pollution of water and soil and of illegal disposal of liquid and solid waste materials. The preliminary hearing phase was closed for one employee who would stand trial, while the preliminary hearing phase is ongoing for other defendants. During the hearings the judge admitted as plaintiffs three environmental associations.

Alleged negligent fire (Priolo). The public prosecutor of Siracusa commenced an investigation regarding certain Eni managers who were previously in charge of conducting operations at the Priolo refinery (Eni divested this asset in 2002) to ascertain whether they acted with negligence in connection with a fire that occurred at the Priolo plants on April 30 and May 1-2, 2006. After preliminary investigations and based on the outcome of preliminary hearing the public prosecutor requested the opening of a proceeding against the mentioned managers for negligent behavior.

Groundwater at the Priolo site. 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 are being investigated who were 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), Syndial and Polimeri Europa. Probes on technical issues are ongoing as required by the Prosecutor.

ENIPOWER SPA
Alleged unauthorized waste management activities. In 2004, the public prosecutor of Rovigo commenced an investigation for alleged crimes related to unauthorized waste management activities in Loreo relating to the samples of soil used during the construction of the new EniPower power station in Mantova. The prosecutor requested the CEO of EniPower and the managing director of the Mantova plant at the time of the alleged crime to stand trial.

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Air emissions. The public prosecutor of Mantova commenced an investigation against two managers of the Mantova plant in connection with air emissions by the new power plant.

SYNDIAL SPA
Porto Torres. In March 2009, the Public Prosecutor of Sassari (Sardinia) resolved to commence a criminal trial against a number of executive officers and managing directors 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. The charge involves environmental damage and poisoning of water and stuff destined to feeding. A preliminary hearing is scheduled in July 2009.

 

Civil and administrative proceedings

SYNDIAL SPA (FORMER ENICHEM SPA)
Alleged pollution caused by the activity of the Mantova plant. In 1992, the Ministry of Environment summoned EniChem SpA (now Syndial SpA) and Edison SpA before the Court of Brescia. The Ministry requested, primarily, environmental remediation for the alleged pollution caused by the activity of the Mantova plant from 1976 until 1990, and provisionally, in case there was no possibility to remediate, the payment of environmental damages. Edison agreed on a settlement with the Ministry whereby Edison quantified compensation for environmental damage freeing from any obligation Syndial, which purchased the plant in 1989. Parties are working through a possible settlement of the matter.

Summon before the Court of Venice for environmental damages allegedly caused to the lagoon of Venice by the Porto Marghera plants. On December 13, 2002, EniChem SpA (now Syndial SpA), jointly with Ambiente SpA (now merged into Syndial SpA) and European Vinyls Corporation Italia SpA, was summoned before the Court of Venice by the Province of Venice. The province requested compensation for environmental damages that were not quantified, allegedly caused to the lagoon of Venice by the Porto Marghera plants, which were already the subject of two previous criminal proceedings against employees and managers of the defendants. EVC Italia and Ineos presented an action to be indemnified by Eni’s Group companies in case the alleged pollution is proved. The environmental damage has been assessed by an independent consultant who filed his advice to be discussed in a hearing set in October 2009.

Claim of environmental damages, allegedly caused by industrial activities in the area of Crotone, commenced by the President of the Regional Council of Calabria. On April 14, 2003, the President of the Regional Council of Calabria, as Delegated Commissioner for Environmental Emergency in the Calabria Region, commenced an action against EniChem SpA (now Syndial SpA) with reference to environmental damages for approximately euro 129 million and damages for euro 250 million (plus interest and compensation) in connection with loss of income and damage to property allegedly caused by industrial activities in the area of Crotone. In addition, the Province of Crotone is acting as plaintiff, claiming damage for euro 300 million. With a decision in May 2007, the Court of Milan declared the invalidity of the power of proxy conferred to the Delegated Commissioner to act on behalf of the Calabria Region with the notice served to Syndial SpA and decided the liquidation of expenses born by the defendant. The Province of Crotone appealed this decision. The second instance court accepted this appeal and Syndial repealed this determination. On October 21, 2004, Syndial was convened before the Court of Milan by the Calabria Region which is seeking to obtain a condemnation of Syndial for a damage payment, should the office of the Delegated Commissioner for Environmental Emergency in the Calabria Region cease during this proceeding. The Calabria Region requested a damage payment amounting to euro 800 million as already requested by the Delegated Commissioner for Environmental Emergency in the Calabria Region in the proceeding commenced in 2003. This new proceeding is in the preliminary investigation stage. This proceeding was unified with the one opened by the Ministry of the Environment. Syndial filed a new project for the environmental remediation of the site to be approved by the Ministry and the body of public administrations and entities involved in the matter that expressed a first partial consent in January 2009. The environmental provision was consequently increased. In 2006, the Council of Ministers, Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the Calabria Region represented by the State Lawyer requested Syndial to appear before the Court of Milan to obtain the ascertainment, quantification and payment of damage (in the form of land, air and water pollution and therefore of the general condition of the population) caused by the operations of Pertusola Sud SpA in the Municipality of Crotone and in surrounding municipalities. The local authorities requested the ascertainment of Syndial’s responsibility as concerns expenses borne and to be borne for the cleanup and reclamation of sites, currently quantified at euro 129 million. This proceeding concerns the same matter and damage claim as the proceedings commenced by the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region against Syndial in 2003 and 2004, respectively.

Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore. With a temporarily executive decision dated July 3, 2008 the District Court of Turin sentenced the subsidiary Syndial SpA (former EniChem) to compensate for environmental damages that were allegedly caused when EniChem managed an industrial plant at Pieve Vergonte during the 1990-1996 period. Specifically, the Court sentenced Syndial to pay the Italian Ministry of the Environment compensation amounting to euro 1,833.5 million, plus legal interests that

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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 ill-founded 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. As no development of the proceeding has occurred since the filing of the Court’s decision, management has confirmed its stance of making no provision for this proceeding in accordance with accounting principles. Syndial will appeal against the ruling on Pieve Vergonte site of the District Court of Turin as soon as possible. Another administrative proceeding is ongoing regarding a ministerial decree enacted by the Italian Ministry for the Environment. The decree provides that Syndial executes the following tasks: (i) the upgrading of a hydraulic barrier to protect the site; and (ii) the design of a project for the environmental remediation of Lake Maggiore. The Administrative Court of Piemonte rejected Syndial’s opposition against the outlined environmental measures requested by the Ministry of the Environment. However, the Court judged the prescriptions of the Ministry regarding the remediation of the site to be plain findings of an environmental enquiry to ascertain the state of the lake. Syndial has filed an appeal against the decision of the Court before an upper degree body, also requesting suspension of the effectiveness of the decision. The appeal has been put on hold considering that a plan to ascertain the environmental status of the site is going to be approved by all interested parties, including the Ministry and local municipalities.

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 certain environmental damage which cannot be cleaned up as well as further damages of various types (e.g. damage to the natural beauty of this site). 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 of 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. Syndial summoned Rumianca SpA, Sir Finanziaria SpA and Sogemo SpA, who ran the plant in previous years, in order to be guaranteed. A report produced by an independent expert appointed by the judge was filed with the Court. The findings of this report quantify the residual environmental damage at euro 15 million. With a sentence of March 2008, the Court of Genova rejected all claims made by the Municipality of Carrara and the Ministry of environment. Both plaintiffs filed an appeal against this decision in June 2008, requesting to all defendants cumulative damage amounting to euro 189.9 million. Syndial filed in the appeal hearing, disputing the plaintiffs’ claims.

Ministry for the Environment Augusta harbor. The Italian Ministry for the Environment with various administrative acts ordered 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 Polimeri Europa and Syndial. 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. Polimeri Europa opposed said administrative actions, objecting in particular to the way in which remediation works have been designed and information on concentration of pollutants has been gathered. The Regional Administrative Court of Catania with its decision of July 2007 annulled the decision made by the Service Conference of the Ministry of the Environment concerning Priolo and the Augusta harbor. The Ministry and the municipalities of Augusta and Melilli filed a claim with an Administrative Court of the Sicily Region which accepted the claim. In January 2008 the Regional Court of Catania accepted two further claims on this matter, remitting to the European Union Court of Justice the correct application of the debated community principle on the matter of environmental responsibility. In June 2008 the Ministry for the Environment and the Municipalities of Melilli and Augusta filed and appeal against the decision of the Regional Court of Catania with the Administrative Justice Council. Syndial challenged the administrative acts of December 20, 2007 and March 6, 2008, also requesting the Court of Justice of the EU to decide on the correct application of the debated community principle. A review of the issue made by an independent consultant has been filed showing evidence supporting the thesis of the plaintiffs. The proceedings are still pending before the Administrative Court of Lazio.

ENI SPA
Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe. On March 2009 Eni was notified 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 its subsidiary Sofid 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.

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Other judicial or arbitration proceedings

SYNDIAL SPA (FORMER ENICHEM SPA)
Serfactoring: disposal of receivables. In 1991, Agrifactoring SpA commenced proceedings against Serfactoring SpA, a company 49% owned by Sofid SpA and which is controlled by Eni SpA. The claim relates to an amount receivable of euro 182 million for fertilizer sales (plus interest and compensation for inflation), originally owed by Federconsorzi to EniChem Agricoltura SpA (later Agricoltura SpA - in liquidation), and Terni Industrie Chimiche SpA (merged into Agricoltura SpA - in liquidation), that has been merged into EniChem SpA (now Syndial SpA). Such receivables were transferred by Agricoltura and Terni Industrie Chimiche to Serfactoring, which appointed Agrifactoring as its agent to collect payments. Agrifactoring guaranteed to pay the amount of such receivables to Serfactoring, regardless of whether or not it received payment on the due date. Following payment by Agrifactoring to Serfactoring, Agrifactoring was placed in liquidation and the liquidator of Agrifactoring commenced proceedings in 1991 against Serfactoring to recover such payments (equal to euro 182 million) made to Serfactoring based on the claim that the foregoing guarantee became invalid when Federconsorzi was itself placed in liquidation. Agricoltura and Terni Industrie Chimiche brought counterclaims against Agrifactoring (in liquidation) for damages amounting to euro 97 million relating to acts carried out by Agrifactoring SpA as agent. The amount of these counterclaims has subsequently been reduced to euro 46 million following partial payment of the original receivables by the liquidator of Federconsorzi and various setoffs. These proceedings, which have all been joined, were decided with a partial judgment, deposited on February 24, 2004; the request of Agrifactoring has been rejected and the company has been ordered to pay the sum requested by Serfactoring and damages in favor of Agricoltura, to be determined following the decision. A final verdict on this issue is pending. Agrifactoring appealed this partial decision, requesting in particular the annulment of the first step judgment, the reimbursement of euro 180 million from Serfactoring along with the rejection of all its claims and the payment of all proceeding expenses. On June 2008, the trial was decided with a partial judgment that, reforming the previous judgment of the Court of Rome, granted the requests of Agrifactoring and condemned Serfactoring to reimburse to Agrifactoring in liquidation the amount of the receivables due from Federconsorzi and not collected as Federconsorzi went bankrupt. The Court resolved to appoint an independent accounting consultant to quantify the amount paid by Agrifactoring to Serfactoring and amounts paid by Federconsorzi to Agrifactoring. The hearing has been rescheduled to February 2010 in order to allow the Court to review the independent accounting consultant’s advice. Syndial and Serfactoring have appealed the sentence with the Supreme Court of Appeal. Agrifactoring has presented a counter-recourse. Eni accrued a provision with respect to this proceeding.

ENI SPA
Fintermica. Fintermica presented a claim against Eni concerning the management of the Jacorossi joint venture with reference to an alleged abuse of key roles played by Eni SpA in the joint venture, thus damaging the other partner’s interest and the alleged dilatory behavior of Syndial in selling its interest in the joint venture to Fintermica. The parties decided to commence arbitration on the matter. The examining phase is ongoing and an independent assessment of this matter is being executed. The Board of Arbitrators issued a decision on November 26, 2008 condemning Eni and Syndial to compensate Fintermica for the damages suffered amounting to euro 5 million including monetary revaluation and accrued interest as of April 3, 2001.

SNAMPROGETTI SPA
CEPAV Uno and CEPAV Due. Eni holds interests in the CEPAV Uno (50.36%) and CEPAV Due (52%) consortia that in 1991 signed two contracts with TAV SpA for the construction of two railway tracks for high speed/high capacity trains from Milan to Bologna (under construction) and from Milan to Verona (in the design phase). With regard to the project for the construction of the line from Milan to Bologna, an Addendum to the contract between CEPAV Uno and TAV was signed on June 27, 2003, redefining certain terms and conditions of the contract. Subsequently, the CEPAV Uno consortium requested a time extension for the completion of works and a claim amounting to euro 800 million. CEPAV Uno and TAV failed to solve this dispute amicably. CEPAV Uno opened an arbitration procedure as provided for under terms of the contract on April 27, 2006. With regard to the project for the construction of a high-speed railway from Milan to Verona, in December 2004, CEPAV Due presented the final project, prepared in accordance with Law No. 443/2001 on the basis of the preliminary project approved by an Italian governmental authority (CIPE). As concerns the arbitration procedure requested by CEPAV Due against TAV for the recognition of costs incurred by the Consortium in the 1991-2000 ten-year period plus suffered damage, in January 2007, the arbitration committee determined the Consortium’s right to recover the costs incurred in connection with the design activities performed. A technical independent survey is underway to assess the amount of compensation to be awarded to the Consortium as requested by the arbitration committee. TAV appealed the arbitration committee’s determination. In April 2007, the Consortium filed with the second instance court of Rome an appeal against Law Decree No. 7 of December 31, 2007, that revoked the concessions awarded to TAV resulting in the annulment of arrangements signed between TAV and the Consortium to build the high-speed railway section from Milan to Verona. The European Court of Justice was requested to judge on this matter. In the meantime, TAV decided to not request the reimbursement of advances paid to the Consortium. Subsequently, Law 133/2008 re-established the concessions awarded to TAV resulting in the continuation of the arrangements between the consortium CEPAV Due and a new entity in charge of managing the Italian railway system.

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Antitrust, EU Proceedings, Actions of the Authority for Electricity and Gas and of Other Regulatory Authorities

Antitrust

ENI SPA
Abuse of dominant position of Snam alleged by the Italian Antitrust Authority. In March 1999, the Italian Antitrust Authority concluded its investigation started in 1997 and: (i) found that Snam SpA (merged in Eni SpA in 2002) abused its dominant position in the market for the transportation and primary distribution of natural gas relating to the transportation and distribution tariffs applied to third parties and the access of third parties to infrastructure; (ii) fined Snam for euro 2 million; and (iii) ordered a review of the practices relating to such abuses. Snam believes it has complied with existing legislation and appealed the decision with the Regional Administrative Court of Lazio requesting its suspension. On May 26, 1999, stating that these decisions are against Law No. 9/1991 and the European Directive 98/30/EC, this Court granted the suspension of the decision. The Authority did not appeal this decision. The decision on the merit of this dispute is still pending before the same Administrative Court.

Formal assessment commenced by the Commission of the European Communities for the evaluation of alleged participation to activities limiting competition in the field of paraffin. On April 28, 2005, the Commission of the European Communities commenced a formal assessment to evaluate the alleged participation of Eni and its subsidiaries in activities limiting competition in the field of paraffin. The alleged violation of competition is for: (i) the determination of and increase in prices; (ii) the subdivision of customers; and (iii) exchange of trade secrets, such as production capacity and sales volumes. After, the Commission requested information on Eni’s activities in the field of paraffin and certain documentation acquired by the Commission during an inspection. Eni filed the requested information. On October 2008, the Commission of the European Communities issued the final decision on the matter condemning Eni to the payment of a sanction amounting to euro 29,120,000. Eni has filed for recourse against this decision that is fully covered by the accrued risk provision.

Ascertainment by the European Commission of the level of competition in the European natural gas market. As part of its activities to ascertain the level of competition in the European natural gas market, with Decision No. C (2006)1920/1 of May 5, 2006, the European Commission informed Eni that the Group companies were subject to an inquiry under Article 20, paragraph 4 of the European Regulation No. 1/2003 of the Council in order to verify the possible existence of any business conducts breaching European rules in terms of competition and intended to prevent access to the Italian natural gas wholesale market and to subdivide the market among few operators in the activity of supply and transport of natural gas. Similar actions have been performed by the Commission also against the main operators in natural gas in Germany, France, Austria and Belgium. In April 2007, the European Commission made public its decision to start a further stage of inquiry, as the elements collected supported its suspicion that Eni adopted behaviors leading to "capacity hoarding and strategic, in its view, underinvestment in the transmission system leading to the foreclosure of competitors and harm for competition and customers in one or more supply markets in Italy". On March 9, 2009 Eni received a Statement of Objections related to a proceeding under Article No. 82 of the EU Treaty and Article No. 54 of the SEE agreement with reference to an alleged unjustifiable refusal of access to the TAG and TENP/Transitgas gas pipelines, that are interconnected with the Italian gas transport system through actions intended to "capacity hoarding, capacity degradation and strategic limitation of investment" with the effect of "hindering the development of a real competition in the downstream market and [...] harming the consumers". The European Commission envisages the possible imposition of a fine and of structural remedies. The Company is currently assessing the reasoning underlying the Commission’s objections in order to ascertain whether the challenged actions are supported by evidence and may be qualified as infringement of the European competition rules. The Company will file its defensive memories within the proceeding. In addition, and following the aforementioned assessment, the Company may consider whether to voluntarily file a set of remedies to settle the proceeding as provided by Article No. 9 of the European Regulation No. 1/2003. Taking into account the numerous elements to be considered in determining the amount of the fine, the complex checks to carry out with respect to the Statement of Objections, and also the circumstance that the Commission’s approval of the possible remedies, presented by Eni pursuant to European Regulation No. 1/2003, would settle the matter without imposing a fine, management believes that the liability is contingent upon the future events described and cannot be measured with reasonable reliability.

TTPC. In April 2006, Eni filed a claim before the Regional Administrative Court of Lazio against the decision of the Italian Antitrust Authority of February 15, 2006 stating that Eni’s behavior pertaining to implementations of plans for the upgrading of the TTPC pipeline for importing natural gas from Algeria represented an abuse of dominant position under Article 82 of the European Treaty and fined Eni. The initial fine amounted to euro 390 million and was reduced to euro 290 million in consideration of Eni’s commitment to perform actions favoring competition including the upgrade of the gasline. Eni accrued a provision with respect to this proceeding. With a decision filed on November 29, 2006, the Regional Administrative Court of Lazio partially accepted Eni’s claim, annulling such part of the Authority’s decision where the fine was quantified. Eni is waiting for the filing of the motivations of the Court decision to ascertain the impact of said decision. Pending this development, the payment of the fine has been voluntarily suspended. In 2007, the Regional Administrative Court of Lazio accepted in part Eni’s claim and cancelled the quantification of the fine based on the Antitrust Authority’s inadequate evaluation of the

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circumstances presented by Eni. Eni filed an appeal with the Council of State, as did the Antitrust Authority and TTPC. Pending the final outcome, Eni awaits for the determination of the amount of the fine to be paid.

Italian natural gas market. On May 7, 2009, the Italian Antitrust Authority started a preliminary investigation against the Company and its fully-owned subsidiary Italgas and other operators engaging in the gas retail market in Italy. The investigation targets an alleged abuse of dominant position in the gas retail market in Italy associated with commercial practices intended to make it difficult for retail clients to change the supplier and the retrieval of data on volumes.

POLIMERI EUROPA SPA AND SYNDIAL SPA
Inquiries in relation to alleged anti-competitive agreements in the area of elastomers. In December 2002, inquiries were commenced concerning alleged anti-competitive agreements in the field of elastomers. These inquiries were commenced concurrently by European and U.S. authorities. At present, proceedings are pending before the European Commission regarding the CR and NBR products. In March 2007, the Commission sent to Eni, Polimeri Europa and Syndial a statement of objections, thus opening the second phase of this proceeding. In December 2007, the European Commission dismissed Syndial’s position on CR and imposed on Eni and Polimeri a fine amounting to euro 132.16 million. The two companies have filed an appeal with the EU Court of First Instance against this decision and, at the same time, paid the fine in March 2008. Investigations relating to other elastomers products resulted in the ascertainment of Eni having infringed European competition laws in the field of synthetic rubber production (BR and ESBR). On November 29, 2006, the Commission fined Eni and its subsidiary Polimeri Europa 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 Commission filed a counter appeal. Pending the outcome, Polimeri Europa presented a bank guarantee for euro 200 million and paid the residual amount of the fine. In August 2007, 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 manufacturers. With regard to NBR, an inquiry is underway also in the U.S., where class actions have also been commenced. On the federal level, the class action was abandoned by the plaintiffs. However, the federal judge has yet to acknowledge this abandonment. With regard to other products under investigation in the U.S., settlements were reached with both relevant U.S. antitrust authorities and the plaintiffs acting through a class action. Eni recorded a provision for these matters.

 

Regulation

TOSCANA ENERGIA CLIENTI SPA
Eni’s subsidiary Toscana Energia Clienti SpA started an action against a customer regarding alleged lack of measurement of gas consumption due to inability to access a measurement facility at the customer’s site, also in connection with the application of Resolution No. 229/2001 of the Italian Authority for Electricity and Gas. This customer has annual consumption in excess of 5,000 CM. The defendant has filed a counter-claim in relation to this proceeding. In the hearing of November 12, 2008 the judge resolved to partially accept the Eni’s subsidiary reasons and to limit compensation to be paid to the defendant to only euro 1,475 with interests amounting to euro 90. The sum was paid while the defendant is evaluating the opportunity to appeal the sentence.

DISTRIBUIDORA DE GAS CUYANA SA
Formal investigation of the agency entrusted with the regulations for the natural gas market in Argentina. Enargas started a formal investigation on some operators, among them Distribuidora de Gas Cuyana SA, a company controlled by Eni. Enargas stated that the company improperly applied conversion factors to volumes of natural gas invoiced to customers and requested the company to apply the conversion factors imposed by local regulations from the date of the default notification (March 31, 2004) without prejudice to any damage payment and fines that may be decided after closing the investigation. In April 2004 the company filed a defensive memorandum. On April 28, 2006, the company formally requested the acquisition of documents from Enargas in order to have access to the documents on which the allegations are based.

 

Tax Proceedings

ENI SPA
Dispute for the omitted payment of the municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. With a formal assessment presented by the Municipality of Pineto (Teramo) in December 1999, Eni SpA has been accused of not having paid 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 in front of the coast of Pineto. Eni was requested to pay a total of approximately euro 17 million including interest and a fine. Eni filed a claim against this request stating that the sea where the platforms are located is not part of the municipal territory and the tax application as requested by the municipality lacked objective fundamentals. The claim has been accepted in the first two degrees of judgment at the Provincial and Regional Tax Commissions. However, the 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

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to judge on the matters of the proceeding. This commission nominated a Board of Consultants, in order to make all the accounting/technical verifications necessary for the judgment. On December 28, 2005, the Municipality of Pineto presented the same request for the same platforms for the years 1999 to 2004. The total amount requested from Eni is euro 24 million including interest and penalties. Eni filed a claim against this request which was accepted by the first degree judge with a decision of December 4, 2007. Similar formal assessments related to Eni oil and gas offshore platforms were presented by the Municipalities of Falconara Marittima and Pedaso. The total amounts of those claims were approximately euro 6 million. The company filed appeal or is planning to appeal.

AGIP KARACHAGANAK BV
Claims concerning unpaid taxes and relevant payment of interest and penalties. In July 2004, relevant Kazakh Authorities informed Agip Karachaganak BV and Agip Karachaganak Petroleum Operating Co BV, shareholder and operator of the Karachaganak contract, respectively, on the final outcome of 2000 to 2003 tax audits. Both companies counterclaimed against the assessment and a preliminary agreement was reached on November 18, 2004. Final assessments have now been issued by the Kazakh Authorities, and payment has been made. The final amount assessed and paid was $39 million net to Eni; this figure included taxes and interest. The companies continue to dispute the assessments and reserve the right to challenge their findings further.

 

Court Inquiries

EniPower. 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 (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 its meeting of August 10, 2004, Eni’s Board of Directors examined the aforementioned situation and Eni’s CEO approved the creation of a task force in charge of verifying the compliance with Group procedures regarding the terms and conditions for the signing of supply contracts by EniPower and Snamprogetti and the subsequent execution of works. The Board also advised divisions and departments of Eni to cooperate fully in every respect with the Court. From the inquiries performed, no default in the organization emerged, nor deficiency in internal control systems. External experts have performed inquiries with regard to certain specific aspects. In accordance with its transparency and firmness guidelines, Eni will take 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.

Trading. An investigation is pending regarding two former Eni managers who were allegedly bribed by third parties to favor the closing of 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 preliminary hearings rejected most of the dismissal request, forcing the public prosecutor to continue with the criminal case.

TSKJ Consortium Investigations of the SEC and other Authorities. The U.S. Securities and Exchange Commission (SEC), the U.S. Department of Justice (DoJ), and other authorities are investigating alleged improper payments made by the TSKJ Consortium to certain Nigerian public officials in relation to the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti Netherlands BV had a 25% participation in the TSKJ companies, with the remaining participations held by subsidiaries of Halliburton/KBR, Technip, and JGC. 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 resulting from the investigations into the TSKJ matter. In February 2009, KBR and its former parent company, Halliburton, announced that they had reached a settlement with the SEC and DoJ with respect to the TSKJ matter as well as other unspecified matters. In connection with the settlement, KBR pleaded guilty to Foreign Corrupt Practices Act (FCPA) charges stemming from the TSKJ matter. KBR and Halliburton also agreed to pay a substantial fine and entered into civil settlements with the SEC. We understand that the DoJ and the SEC believe that representatives of the other members of the TSKJ Consortium were involved in the conduct that gave rise to the FCPA charges against KBR. Since June 2004, Eni and Saipem/Snamprogetti have been in discussions with, and have provided information in response to requests by, various regulators, including the SEC, the DoJ and the Public Prosecutor’s office of Milan, in connection with the investigations.

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Gas Metering. On May 28, 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 Courts 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, interalia, 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. The Group companies are cooperating with the Supervising Authorities in the investigations.

Agip KCO NV. In November 2007, the public prosecutor of Kazakhstan informed Agip KCO of the start of an inquiry for an alleged fraud in the award of a contract to the Overseas International Constructors GmbH in 2005.

 

Settled Proceedings

ENI SPA
Inquiry of the Italian Authority for Electricity and Gas regarding information to clients about the right to pay amounts due for natural gas sales in installments. With Decision No. 228/2007, the Italian Authority for Electricity and Gas commenced a formal inquiry regarding information to clients about the right to pay amounts due for the natural gas sales in installments in order to possibly put a stop to the alleged infringement of the clients’ rights and to impose a fine. In April 2008, the Authority concluded its inquiry and fined the Company by euro 3.2 million.

SYNDIAL SPA (FORMER ENICHEM SPA)
Criminal action commenced by the public prosecutor of Brindisi. In 2000, the public prosecutor of Brindisi commenced a criminal action against 68 persons who are employees or former employees of companies that owned and managed plants for the manufacture of dichloroethane, vinyl chloride monomer and vinyl polychloride from the early 1960s to date, some of which were managed by EniChem from 1983 to 1993. At the end of the preliminary investigation the public prosecutor asked for the dismissal of the case in respect of the employees and the managers of EniChem. Plaintiffs presented oppositions, but the prosecutor confirmed the request to dismiss the case with a decision of June 2008, the public prosecutor dismissed the accusation as unfounded and requested the closing of the proceeding.

AGIP KCO NV
In December 2007 the Kazakh tax authority filed a notice of tax assessment for fiscal years 2004 to 2006 to Agip KCO, operator of the Kashagan contract. Allegedly unpaid taxes, including interest and penalties, amounted to approximately U.S. $235 million net to Eni and related to unpaid amounts and inapplicable deductions on value added tax and the default in applying certain withholding taxes on payments to foreign suppliers. The same notice also informed the companies party to the Kashagan contract that further assessments were pending on non-deductible costs for U.S. $188 million net Eni and higher taxable income on Kazakh branches for U.S. $48 million net to Eni. The further assessments were subsequently issued, the company filed an appeal and a settlement was reached in October 2008 with the following outcome: the unpaid taxes net to Eni were agreed at U.S. $24 million (U.S. $235 million assessed). An adjustment to deductible costs was agreed at U.S. $38 million net to Eni (U.S. $188 million assessed) and it was further agreed that there would be no income taxable on Kazakh branches (U.S. $48 million assessed).

 

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, subject to such factors, in the next four-year period management intends to pursue a dividend policy designed to ensure competitive dividend yields to Eni’s shareholders. On April 30, 2009, Eni’s Shareholders' Meeting approved a dividend, for fiscal year 2008, of euro 1.30 per share, of which euro 0.65 per share was paid in September 2008 as an interim dividend with the balance of euro 0.65 per share to be paid late in May 2009. Total cash outlay for the 2008 dividend is expected at approximately euro 4.7 billion (including the euro 2.36 billion already paid in September 2008). 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.

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Significant Changes

See "Item 5 – Recent developments" for a discussion of significant events occurred after 2008 year-end up to the latest practicable date, including a review of Eni’s performance in the first quarter of 2009, the exercise by Gazprom of the call option to purchase the 20% interest in the Russian company OAO Gazprom Neft held by Eni, the divestment of 100% of Italgas SpA and Stoccaggi Gas Italia SpA to Snam Rete Gas and the finalization of the mandatory tender offer on the minority shareholders of Distrigas.

 

 

Item 9. THE OFFER AND THE LISTING

Offer and Listing Details

The principal trading market for the ordinary shares of Eni SpA ("Eni"), nominal value euro 1.00 each (the "Shares"), is the Mercato Telematico Azionario or MTA ("Telematico"), the Italian regulated electronic share market, which is the principal trading market for shares in Italy. The Shares are traded on the Blue Chip segment of Telematico, which includes shares of the companies whose market capitalization amounts to more than euro 1,000 million. 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 Telematico and of ADRs on the New York Stock Exchange, respectively. Due to the ratio change, the historical prices of ADRs have been adjusted by an adjustment factor of 2.5. See "Item 3 – Key Information – Exchange Rates" regarding applicable exchange rates during the periods indicated below.

	Telematico		New York Stock Exchange

	High		Low		High		Low

(euro per share)

(U.S. $ per ADR)

2003		15.746		11.881		37.992		26.460
2004		18.748		14.723		50.580		36.940
2005		24.960		17.930		60.540		47.400
2006		25.730		21.820		67.690		54.650
2007		28.330		22.760		78.290		60.220
2008		26.930		13.798		84.140		37.220
2007
First quarter		25.720		22.760		66.720		60.220
Second quarter		27.150		24.130		72.840		64.710
Third quarter		28.330		23.310		78.290		63.160
Fourth quarter		26.680		23.320		75.660		67.220
2008
First quarter		25.580		20.870		75.130		61.790
Second quarter		26.930		21.820		84.140		68.570
Third quarter		23.450		18.263		73.930		51.410
Fourth quarter		19.350		13.798		52.600		37.220
2009
First quarter		17.830		12.300		49.440		31.070
January 2009		17.830		16.210		49.440		42.390
February 2009		17.630		15.740		45.690		39.200
March 2009		15.240		12.300		41.380		31.070
April 2009		16.450		14.510		43.010		37.240
May 2009 (through May 4, 2009)		16.930		16.930		45.550		44.040

JPMorgan Chase Bank NA (the "Depositary") functions as depositary bank issuing ADRs pursuant to the Deposit Agreement among Eni, the Depositary and the beneficial owners ("Beneficial Owners") and registered holders from time to time of ADRs issued thereunder.

At May 4, 2009 there were 44,072,282 ADRs outstanding, representing 88,144,564 ordinary shares or 2.2% of all Eni’s shares outstanding, held by 107 holders of record (including the Depository Trust Company) in the United

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States of America, 105 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 S&P/MIB, the primary Italian stock exchange index that measures the performance of the 40 leading companies in leading industries listed on the markets organized and managed by Borsa Italiana SpA ("Borsa Italiana"). The constituents of the S&P/MIB are selected according to the following criteria: sector representation, market capitalization of free-float shares and liquidity. Since September 20, 2004 S&P/MIB is the principal indicator used to track the performance of the Italian stock market and is the basis for future and option contracts traded in the Italian Derivatives Market ("IDEM") managed by Borsa Italiana. Eni’s Shares are the largest component of the S&P/MIB, with a weighting of approximately 14.7%. as established by Standard & Poor’s and Borsa Italiana after the quarterly rebalancing for S&P/MIB effective March 23, 2009.

Trading in the Telematico is allowed in any quantity of shares or 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. Starting from May 15, 2000, the Shares have been also trading on a special market, named After Hours trading market or TAH ("After Hours"), after the closure of the day time of Telematico under special rules. 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). Outside Regulated Markets, block trading is permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana.

 

 

Markets

Telematico is organized and administered by Borsa Italiana subject to the supervision and control of the Commissione Nazionale per le Società e la Borsa (the National Commission for Companies and the Stock Exchange or "Consob"), the public authority charged, interalia, with regulating the Italian securities market to ensure the transparency and regularity of the dealings and protect investors. Borsa Italiana is a joint stock company (Società per Azioni) that was established to manage the Italian regulated financial markets (including Telematico) as part of the implementation in Italy of the EU Investment Services Directive ("ISD"). Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it regulates, which are Telematico (shares, convertible bonds, pre-emptive rights, warrants, and Funds), After Hours, Mercato Expandi (small companies), ETFplus (Exchange Traded Funds and Exchange Traded Commodities market), IDEM (index and stock derivatives market), SeDeX (covered warrants and certificates), and MOT (bond market), as well as the admission to listing on and trading on these markets. Borsa Italiana is part of the London Stock Exchange Group, following the agreement signed in June 2007.

For the purposes of the automatic control of the regularity of trading on Telematico, the following price variation limits shall apply to contracts concluded on shares making up the S&P/MIB: (i) ± 7.5% (or such other amount established 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) with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). The reference price is the closing-auction price. 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.

Effective November 1, 2007, following the national implementation of the EU Markets in Financial Instruments Directive (2004/39/EC) ("MiFID"), the so called ’concentration rule’ has been superseded. The MiFID, that replaces the ISD, establishes the legal framework governing investment services and financial markets in Europe. With the new regulatory regime of MiFID, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities ("MTF"s) or Systematic Internalisers. An 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 an MTF.

Italian exchanges and securities are primarily regulated by Legislative Decree No. 58 of February 24, 1998 ("Decree No. 58"). According to Decree No. 58, the provision of investment services and activities to the public on a professional basis is reserved to banks and investment firms ("intermediaries"), which are firms authorized to provide investment services or activities. In addition, banks and investment firms organized in a member nation of the EU are permitted to operate in Italy provided that the intent of the bank or investment firm to operate in Italy is communicated to Consob by the competent authority of the member state. Non-EU banks and non-EU investment

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firms may operate in Italy subject to the specific authorization of Consob, in agreement with the Bank of Italy. Pursuant to Decree No. 58, Consob shall be responsible for the transparency and correctness of conduct of intermediaries and the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries. 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).

 

 

Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

The full text of the memorandum and articles of association of Eni is attached as an exhibit to this annual report. See "Exhibit 1".

Eni is incorporated under the name "Eni SpA" resulting from the transformation of Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953. The Company’s purpose is the direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the field of hydrocarbons and natural vapors, such as exploration and development of hydrocarbon fields, construction and operation of pipelines for transporting the same, processing, transformation, storage, utilization and trade of hydrocarbons and natural vapors, all in compliance with concessions required by law.

The Company also has the purpose of direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the fields of chemicals, nuclear fuels, geothermy and renewable energy sources, in the sector of engineering and construction of industrial plants, in the mining sector, in the metallurgy sector, in the textile machinery sector, in the water sector, including derivation, drinking water, purification, distribution and reuse of waters; in the sector of environmental protection and treatment and disposal of waste, as well as in every other business activity that is instrumental, supplemental or complementary with the aforementioned activities.

The Company also has the purpose of managing the technical and financial co-ordination of subsidiaries and affiliated companies as well as providing financial assistance on their behalf.

The Company may perform any operations necessary or useful for the achievement of its purpose; by way of example, it may initiate operations involving real estate, moveable goods, trade and commerce, industry, finance and banking asset and liability operations, as well as any action that is in any way connected with the Company purpose with the exception of public fund raising and the performance of investment services as regulated by Decree No. 58 of February 24, 1998.

The Company may take shareholdings and interests in other companies or businesses with objects similar, comparable or complementary to its own or those of companies in which it has holdings, either in Italy or abroad, and it may provide real and or personal bonds for its own and others’ obligations, especially guarantees.

 

Directors

The Board of Directors is invested with the fullest powers for 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 Company purpose, except for the acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting. The Board of Directors has appointed a Chief Executive Officer and delegated to him all necessary powers for the administration 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 on Directors on the matters regarding major strategic, operational and organizational decisions.

For a complete description of the powers of the Board, the CEO and the Chairman, appointments, role of the Board and rules and procedures of the meetings of the Board see "Item 6 – Board Practices".

There are no provisions as to retirement based on age-limit requirements, or requirement of share ownership for a director’s qualification in Eni’s By-laws.

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Stock ownership limitation and voting rights restrictions

General

There are no limitations imposed by Italian law or by the Eni’s By-laws on the rights of non-residents of Italy or foreign persons to hold or vote the shares other than the limitations described below (which are equally applicable to residents and non-residents of Italy).

In accordance with Article 6 of Eni’s By-laws and in accordance with the special provision of Article 3 of Law Decree No. 332/1994 as converted into Law No. 474/1994 ("Law No. 474 of 1994"), no shareholder can directly or indirectly own a shareholding higher than 3% of Eni’s share capital. This limitation does not apply to shares held by the State, the Public Entities or entities controlled by them. The law states in addition that this limitation is waived in case of a public offer to buy Eni’s shares whereby the bidder will hold at least the 75% of share capital giving the right to vote on the appointment or revocation of the Board of Directors.

Such maximum limit at 3% is calculated taking into account the aggregate shareholding of a controlling entity, whether an individual or a legal entity (each a "person"); its directly or indirectly controlled entities, as well as entities controlled by the same controlling entity; affiliated entities, as well as relatives within the second degree by blood or marriage (except for a legally separated spouse).

Control exists with reference also to entities other than companies in the cases envisaged by in the cases envisaged by Article 2359, paragraphs 1 and 2 of the Civil Code. Affiliation exists as set forth in applicable Italian legislation, as well as between entities that, directly or indirectly, through controlled entities (other than those managing investment funds) are bound, even with third parties, by agreements relating to the exercise of voting rights or the transfer of shares or interests in third-party companies or other agreements relating to third-party companies as specified by applicable Italian legislation if such agreements relate to at least 10% of the voting share capital of a listed company or 20% of the voting share capital of a non-listed company. For purposes of calculating the 3% limit, shares held through a fiduciary nominee or a broker are taken into account.

Any voting rights attributable to shares held or controlled in excess of such 3% limit cannot be exercised, and the voting rights of each entity to whom such limit on shareholding applies are reduced proportionately, unless otherwise jointly disposed of in advance by the parties involved. In the event that shares exceeding this limit are voted, any shareholders’ resolution adopted pursuant to such a vote may be challenged if the majority required to approve such resolution would not have been reached without the vote of the shares exceeding such maximum limit. Shares not entitled to be voted are nevertheless counted for the purpose of determining the quorum at a Shareholders’ Meeting.

For other limitations that may affect voting rights, see "– Reporting Requirements and Restrictions on Acquisitions of Shares".

Special Powers of the Italian State

Under Italian laws, the Italian State, acting through the Minister of Economy and Finance in agreement with the Minister of Economic Development (the "Ministers"), holds certain special powers in connection with any transfer of a controlling interest in certain State-owned companies operating in public service sectors, including Eni. The law places no limit on the duration of such special powers. Such powers are to be exercised in accordance with specific criteria provided for by the regulation and EU principles.

Article 6.2 of Eni’s By-laws, in accordance with the special law referred to as Law No. 474 of 1994, attribute to the Minister of Economy and Finance, in agreement with the Minister of Economic Development, the following special powers to be used in compliance with the criteria indicated in the Decree of the President of the Council of Ministers of June 10, 2004 and, synthetically:

(a)

opposition with respect to the acquisition of material shareholdings representing 3% of the Eni’s share capital having the right to vote at ordinary Shareholders’ Meeting by entities subject to such ownership limitations pursuant to Article 6.1. Such opposition is required to be duly motivated and expressed within 10 days of the date of the notice to be filed by the Board of Directors at the time a request is made for registration in the Shareholders’ register, when the transaction is considered prejudicial to vital interests of the State. Until the ten-day term as expired, the voting rights and the non-asset linked rights connected with the shares representing the material shareholding should not be exercised. If the opposition power is exercised, by a duly motivated act in connection with the prejudice that may be caused by the operation to the vital interests of the Italian State, the purchaser can not exercise the voting rights and the other non-asset linked rights connected with the shares representing the material shareholding and must sell the relevant shares within one year. If the purchase fails to comply, the law court, upon request of the Minister of Economy and Finance, will order the sale of the shares representing a material shareholding according to the procedures set forth in Article 2359-ter of the Civil Code;

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(b)

opposition with respect to the subscription of shareholders’ agreements or other arrangements (as defined by Article 122 of the TUF) whereby 3% or more of the share capital of Eni having the right to vote at ordinary Shareholders’ Meetings is involved. In exercising this opposition power, the public authority responsible for regulating Italian securities and exchanges (Consob) communicates to the Minister of Economy and Finance any significant shareholders’ agreement notified in accordance with Article 122 of the TUF. The opposition power may be exercised within ten days as of the date of the notice by Consob. Until the ten-day term is not lapsed, the voting right and the other non-asset linked rights connected with the shares held by the shareholders who have subscribed the above mentioned agreements can not be exercised. If the opposition power is exercised through a duly motivated act in consideration of the prejudice that may be caused by said agreements to the vital interests of the Italian State, the shareholders agreements shall be null and void. If in the shareholders’ meetings the shareholders who have signed shareholders’ agreements behave as if those agreements disciplined by Article 122 of the TUF were still in effect, the resolutions approved with their vote, if determining for the approval, can be sued;

(c)		veto power – duly motivated in connection with the prejudice to the interests of the State – with respect to Shareholders’ Meeting resolutions to wind-up the company, to transfer the enterprise, to merger or to demerger, to transfer the headquarters of the company abroad, to change the company objects or to amend the By-laws canceling or modifying any of the special powers described in this section (with reference to letters a), b), c) and the following letter d); and
(d)		appointment of a Board member without voting right in the Board resolutions.

The acts whereby these special powers are exercised may be subject to a lawsuit by the legitimate subjects before the Regional Administrative Court of Lazio within 60 days.

These powers have been limited after some decisions of the European Court of Justice. The European Court, on March 23, 2009, declared that Italian Regulation that defined the criteria for exercising such special powers (DPCM of June 10, 2004) violated the provisions of Articles 43 (former Article 52, right of establishment) and 56 (free movement of capitals) of the European Treaty. Management can not foresee developments on this matter: only the Government is responsible for the amendment of the above mentioned regulation.

Law No. 266 of December 23, 2005 (Budget Law for 2006) in Article 1, paragraphs 381 to 384, in order to promote the process of privatization and the diffusion among the public of shareholdings in companies in which the State holds significant stakes, introduced the option to include in the By-laws of such listed companies, like Eni, provisions for the issuance of shares, or securities bearing the same characteristics as shares, which give to the special meeting of their relevant holders, the right to request the issuance on their behalf of new shares, also at par value, or securities bearing the right to vote at both ordinary and extraordinary Shareholders’ Meeting. The introduction of these norms in Eni’s By-laws would entail the cancellation of the 3% threshold to individual shareholdings as contained in the mentioned Article 6.1 of Eni’s By-laws. To date, Eni’s By-laws doesn’t contain this provision.

Minority protection provisions

In order to allow for the presence of representatives elected by minority shareholders, under Italian laws, listed companies such as Eni. must provide for the election of directors and statutory auditors through the "voto di lista" (voting list) system, to ensure that minority shareholders of a company are represented on its Board of Directors and Board of Statutory Auditors. Accordingly, Eni’s By-laws require that the members of the Board of Directors having decisional powers and the Board of Statutory Auditors have to be elected on the basis of candidate lists presented either by one or more shareholders, representing, alone or in aggregate, at least 1% of the Eni’s share capital having the right to vote at ordinary shareholders’ meetings, or by the Board of Directors.

Each shareholder can present or participate in presenting and voting for only one list. Entities controlling a shareholder and companies controlled by a common entity are forbidden from presenting or otherwise concurring to the presentation of additional lists and from voting them, also through broker or fiduciaries.

Such candidate lists, in which the independent candidates are clearly identified, must be deposited at the Eni’s registered office and published in at least three Italian newspapers having general circulation in Italy (two of which must be business dailies). Publication of the candidate list presented by the Board of Directors shall occur at least 20 days before the first call (as defined below) of the Shareholders’ Meeting. Such term is reduced to 10 days in the case of candidate lists proposed by shareholders. Each shareholder may present or participate in the presentation of only one candidate list and each candidate may appear on only one list.

Lists must be also be filed with Borsa Italiana and published on Eni’s website.

All candidates must posses the honorability requirements as provided for by the applicable legislation. Filing a list is a pre-requisite for its validity together with filing of a professional curriculum of each candidate and statements in which each candidate accepts his candidature and attests the lack of situations of ineligibility or incompatibility and the possession of the honorability and, in case, the independence requirements.

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After the votes are cast, appointments take place by extracting seven tenths of directors from the majority list in the order in which they are listed and the remaining directors from the other lists that must not be directly or indirectly connected with the shareholders that filed or voted the list that collected the majority of votes. The list vote is applied only when the whole Board is re-elected. In case of appointment of directors that for whatever reason have not been voted according to the described procedure, the Shareholders’ Meeting decides with the majorities set by the law, so that the composition of the Board complies with the law and Eni’s By-laws.

As per Article 6, paragraph 2, letter d) of Eni’s By-laws, the Minister for Economy and Finance, in agreement with the Minister of Economic Development, may appoint one member of the Board without voting rights in addition to those appointed by the Shareholders’ Meeting. The Ministers chose not to appoint such member (see "Special Powers of the Italian State").

According to Article 28.2 of Eni’s By-laws in accordance with the law, the Shareholders’ Meeting shall elect Chairman of the Board of Statutory Auditors a member elected from a list other than the one obtaining the majority of votes.

Several provisions of Italian legislation are intended to increase the protection of minority shareholders. In particular: (i) shareholders’ meetings must be called also upon request of holders of at least 10% of the outstanding shares (Article 2367 Civil Code); (ii) the attendance quorum required for a valid shareholder meeting at an extraordinary meeting is at least 50% of the outstanding shares on first call, while on second call the attendance quorum is more than 1/3 of the shares outstanding and on third and following calls the attendance quorum is at least 1/5 of the shares outstanding. On first, second and third call, resolutions shall be approved by a majority of 2/3 of the shares represented at the Shareholders’ Meeting (Articles 2368-2369 Civil Code); (iii) in addition to the general action against the Board of Directors approved by the Shareholders’ Meeting, shareholders’ actions against the Board of Directors and the Statutory Auditors may be initiated by shareholders holding at least 2.5% of the outstanding shares (Articles 2393, 2393-bis and 2407 Civil Code); (iv) a single shareholder may sue the directors for individual damages (Article 2395 Civil Code) or complain to the Board of Statutory Auditors about directors’ misconduct; if the complaint is filed by shareholders representing at least 2% of the share capital of a listed company, the Statutory Auditors are required to investigate with no delay and report to the Shareholders’ Meeting (Article 2408 Civil Code); and (v) shareholders holding at least 5% of the outstanding share may report to the Court directors’ serious misconduct. The Court may order the inspection of the management, adopt interim measures and replace directors with a judicial Commissioner (Article 2409 Civil Code). The companies’ By-laws may further lower the thresholds in (iii), (iv) and (v) and increase the voting quorums under (ii).

Reporting requirements and restrictions on acquisitions of shares

Holdings in listed companies. Under law and Consob Regulation⁸, as modified following the implementation of Directive 2004/109/EC (the Transparency Directive⁹) any direct or indirect holding in the voting shares of a listed issuer in excess of 2%, 5%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 66,6%, 75%, 90% and 95% must be promptly disclosed to the investee company and to Consob.

The same disclosure requirements refer to holdings which fall below one of the specified threshold.

As specified in new Article 117-bis of Consob Regulation, these obligations apply also to treasury-shares owned directly or through its subsidiary companies by a listed issuer.

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 to take effect, using the specific forms attached to the above mentioned Regulation. In the event the same relevant participation is directly or indirectly held by two or more entities, the obligation to notify may be satisfied by one of such person, provided that completeness of information is guaranteed.

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 of 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.

Article 119 of Consob Decision No. 11971/1999, provide also for specific disclosure requirements (with partially different thresholds), connected to the potential holdings (such as holdings of derivatives or other equity-linked securities), so that, in calculating the defined threshold, potential holdings shall not be aggregated with actual holding.

 

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(8)	i	Article 119 of Consob Decision No. 11971/1999 and subsequently amendments.
(9)		Directive 2004/109/EC of the European Parliament and of the Council of December 15, 2004 on the harmonisation of transparency requirements in relation to information about issuers whose securities are admitted to trading on a regulated market and amending Directive 2001/34/EC.

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The obligation to notify also applies to any direct or indirect participation owned through ADRs.

Voting rights attached to listed shares which have not been notified pursuant 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 Civil Code, by shareholders or by Consob itself.

Moreover, based on reasoned investor protection and/or market efficiency aims, Consob is entitled to fix the first relevant threshold to a measure lower than 2%, by its decree (as provided for Law Decree No. 5 of February 2, 2009, converted into Law No. 33 of April 9, 2009). This faculty may be exercised only for definite period of time, with regard to public companies with high capitalization level.

Holdings in unlisted companies. Under law and Consob Regulation (Article 125 of the mentioned decision), listed issuers holding more than 10% of the voting capital of an Italian or foreign unlisted company or a "società a responsabilità limitata" as regulated in Italian Civil Code (Articles 2462-2483), shall inform the investee company, within seven days from reaching such threshold (applying, for calculating this thresholds, the some rules established for holding in listed companies).

In the same way, the non-listed company must be notified about any subsequent reduction of such participation below the 10% threshold.

Listed companies are also required to notify Consob of their participation exceeding 10% of the voting share capital of non-listed companies or "società a responsabilità limitata" owned at the closing date of the financial year, within 30 days from the date of approval of the draft annual report.

Cross-holdings rules

In addition to the rules of Article 2359-bis of the Italian civil code governing the acquisition of shares of the parent company by a controlled subsidiary, Decree No. 58/1998 regulates additional cross-ownership matters as follows.

Cross-ownership between listed and non-listed companies may not exceed 2% of the shares of the listed company or 10% of the shares of the non-listed company (applying, for calculating these ownership thresholds, the same rules established for holdings in listed companies).

The company that last exceed the limit of 2% or 10% interest in a listed or unlisted company respectively, may not exercise the voting rights on the shares held in excess of such thresholds and must sell such shares within the following 12 months. In the event of failure to make the disposal within such time limit, the suspension of voting rights shall apply to the entire shareholding, and any resolution or act adopted with the contribution of relevant shares, could be challenged under the Civil Code.

If anyone 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 said holder. If the foregoing limit is exceeded, the holder who last exceeded the foregoing limit (or both the holders, if it is not possible to ascertain which holder exceeded such limit last) may not exercise the voting right related to the shares exceeding the foregoing limit. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended and any resolution or act adopted with the contribution of relevant shares, could be challenged under the Civil Code.

Described limitations are not applicable in case of a tender offer for acquiring at least 60% of the ordinary shares of a listed company. For a description of the limitation on cross-ownership between a company and its subsidiaries, see "Purchase by Eni SpA of its Own Shares".

Shareholders’ agreements

Under Decree No. 58/1998, any agreement, in whatever form, intended to regulate the exercise of voting rights in a listed company or in the companies controlling a listed company, together with any of its subsequent amendments, renewal or termination, must be: (i) notified to Consob, within five days from its execution; (ii) disclosed to the public through the publication, in summary form, in the daily press, within ten days from its execution; and (iii) deposited in the Companies’ Register of the place where such listed company has its registered office within 15 days from its conclusion.

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The same requirements also apply to agreements, in whatever form, that: (a) impose an obligation 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 for 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 equity swap, including commitments relating to non-participation in a takeover bid.

In the event of non-compliance with said requirements, the agreements shall be null and void, the voting rights connected to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares could be challenged under the Civil Code.

If the parties have agreed upon the duration of the agreement, such duration cannot exceed three years. In case of agreements concluded for an indeterminate period, each party may withdraw on giving six months’ notice.

Antitrust rules

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 preventive authorization of Italian Antitrust Authority¹⁰. 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 of the acquisition falls within the exclusive jurisdiction of the European Commission.

Shareholders’ meetings

The Shareholders’ Meeting could be "ordinary" or "extraordinary". In particular, an ordinary meeting appoints and revokes directors and statutory auditors, approves financial statements within 120 days from the end of each fiscal year (December 31) and vote on other issues that can be defined in the By-laws, while an extraordinary meeting approves amendments in By-laws and extraordinary transactions, such as capital increases and mergers.

The notice of a Shareholders’ Meeting may specify two meeting dates ("calls") for ordinary meetings and three calls, in case of listed companies, for extraordinary shareholders’ meetings. Shareholders’ meetings are usually held at the Company registered office unless otherwise resolved by the Board of Directors, provided however they are held in Italy.

Meetings are called by Eni’s Board of Directors when required or deemed necessary, or on request of shareholders representing at least 10% of outstanding shares, who must provide an agenda of the matters to be discussed to the Chairman of the Board of Directors. Meetings may also be called, by the Board of Statutory Auditors or by two auditors, provided that such call has been notified in advance. Shareholders representing at least one fortieth of Eni’s share capital, both on an individual and a cumulative basis, may ask, within five days as of the date of publication of the Shareholders’ Meeting notice, to add other items in the agenda. The request shall contain the matters to be proposed to the Shareholders’ Meeting. Said faculty may not be exercised on the matters upon which, pursuant to the applicable legislation, the Shareholders’ Meeting resolves on the basis of a proposal of the Board of Directors or on the basis of a project or report of the Board. The integrations accepted by the Board shall be published, through a specific notice, at least ten days before the Shareholders’ Meeting date.

The attendance quorum for an ordinary meeting on first call is at least 50% of the outstanding ordinary shares, while on second call there is no attendance quorum requirement. At a duly called ordinary meeting, in both first and second calls, resolutions may be approved by a simple majority of the shares represented at the meeting.

The attendance quorum required for a valid shareholder meeting at an extraordinary meeting is at least 50% of the company’s share capital on first call, or more than 1/3 or at least 1/5 of the company’s share capital, on second call and third call, respectively. On first, second and third call, resolutions may be approved by a majority of 2/3 of the shares represented at the Shareholders’ Meeting.

With the aim of facilitating the attendance of shareholders, according to law and Article 13 of the By-laws, calls for meetings are published, at least 30 days before the date fixed for the meeting on first call, in the Official Gazette of the Italian Republic or in the "Il Sole 24 Ore", "Corriere della Sera" and "Financial Times" newspapers. The notice is filed with Borsa Italiana and published on the Company website, also. The reports and proposals of the Board of Directors for any item on the agenda of the meeting together with the financial statements to be submitted to the shareholders’ approval, must be deposited at the shareholders’ disposal at the Company’s registered office and at Borsa Italiana’s, during the 15 days before the Shareholders’ Meeting.

 

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(10)

Autorità garante per la concorrenza ed il mercato (AGCM - www.agcm.it).

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The shareholders are entitled to attend and vote at ordinary and extraordinary shareholders’ meetings. Each holder is entitled to cast one vote for each share held. Votes may be cast personally, by proxy or by mail, in accordance with applicable regulations.

Admission to the Shareholders’ Meeting is granted to shareholders who deliver the notification of attendance issued by financial intermediaries, under applicable laws, at least two business days prior to the date of the meeting on first call. The communication can be withdrawn, through the financial intermediaries, in which case shareholders lose the right to participate. Shareholders may attend the meeting by proxy. Directors, Statutory Auditors, and employees of Eni or of their subsidiary companies, as well as the External Auditors of Eni, and its subsidiary companies, may not be appointed proxies. Any one proxy may not represent more than 200 shareholders. A proxy may be appointed only for a single meeting, including the first, second and third call thereof, unless the proxy is general or given by a company, association, foundation, other entities or institutions to its employees. Rules relating to proxies solicitation are established by Decree No. 58/1998 and the related Consob Decision No. 11971/1999. Accordingly whereby: (i) proxies may be solicited, collected or exercised by banks, investment firms and shareholders’ associations; (ii) proxies may be granted only in respect of shareholders’ meetings that have been called; and (iii) proxies may be limited to voting on particular proposals.

Decree No. 58 provisions also allow companies to implement vote by mail procedures.

Eni’s By-laws allow vote by mail and the collection of proxies in Articles 13 and 14. Vote by mail can be revoked by express communication sent to the Company at least one day before the meeting. Persons that intend to attend the meeting as legal or voluntary representatives of other shareholders must present the documentation confirming their power to the proper office of the Company according to the dates and forms indicated in the call for the meeting. In addition, as provided by Article 14 of Eni’s By-laws, in order to simplify the collection of proxies issued by shareholders that are also employees of Eni and Group companies and members of associations of shareholders that comply with current regulations, Eni provides areas for communicating and collecting proxies to said associations in ways to be agreed from time to time with their legal representatives.

There are no limitations arising under Italian law or the Eni’s By-laws on the right of non-resident or foreign persons to hold or vote the shares other than limitations that apply generally to all shareholders.

Meetings are conducted according to the "Eni’s Shareholders’ Meeting Regulation" as approved by the ordinary Shareholders’ Meeting of Eni on December 4, 1998 and amended by the ordinary Shareholders’ Meeting held on May 28, 2004 in order to adequate its provisions to new rules introduced in the Civil Code on this matter.

During shareholders’ meetings, the Board of Directors provides wide disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided within the limits of confidentiality, taking account of applicable rules regulating price sensitive information.

Subscription rights

New shares may be issued pursuant to a resolution of shareholders at an extraordinary meeting. Under the Italian law, shareholders have a pre-emptive right to subscribe for new issues of shares and corporate bonds convertible into shares in proportion to their respective shareholdings. Subject to certain conditions, principally designated to prevent dilution of the rights of shareholders, this right may be waived or limited by resolution taken by an extraordinary Shareholders’ Meeting by the affirmative vote of more than 50% of the shares outstanding. Such percentage applies to all calls of the meeting. The preemptive right is waived by the law in specific cases, such as non-cash contributions.

Liquidation rights

Under the Italian law, subject to the satisfaction of the claims of all other creditors, shareholders are entitled to the distribution of the remaining liquidated assets of Eni in proportion to the nominal value of their shares. Holders of savings shares and preferred shares, if foreseen by the By-laws, in the event such shares are issued by Eni, would be entitled to a preferred right to distribution from liquidation up to their nominal value. Thereafter, if there are surplus assets, ordinary shareholders rank equally in the distribution of such assets. Shares rank pari passu among ordinary shareholders in a liquidation.

 

 

Material Contracts

None.

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Documents on Display

It is possible to read and copy documents referred to in this annual report on Form 20-F that have been filed with the SEC at the SEC’s public reference room located at 100 F Street, NE, Room 1580, Washington, DC 20549 and at the SEC’s other public reference rooms in New York City and Chicago. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges. The SEC filings are also available to the public from commercial document retrieval services and in the website maintained by the SEC at 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.

 

 

Exchange Controls

There are no exchange controls in Italy. Residents and non-residents of 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 Ufficio Italiano Cambi (the Italian Exchange Office) 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. The Ufficio Italiano Cambi will maintain reports for a period of ten years and may use them, directly or through other government offices, to police money laundering, tax evasion and any other crime or violation.

 

 

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, in respect of 2008 profits, 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 12.5% 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 2008 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.

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Dividends received by Italian pension funds are included in the overall result of the pension funds subject to an 11% substitute tax. Dividends received by Italian collective investment funds are included in the overall result of the collective investment funds subject to a 12.5% substitute tax. Dividends received by Italian real estate investment funds are not subject to tax in the hands of the real estate investment funds (under certain circumstances a 1% tax on net asset value is applied). Entities exempt from IRES (company income tax) are subject to the substitute tax at the rate of 27%.

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 27%, provided that the interest is not connected to an Italian permanent establishment. Up to four-ninths 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.

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 10% 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 27%. The threshold holding will be increased to 25% following a new tax treaty that has been ratified.

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 27%. 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.

According to the Italian tax law as reflected in the Deposit Agreement, the Company is not involved: (i) in withholding amounts due by holders of ADRs to relevant taxing authorities in connection with any distributions relating to ADRs; or (ii) in the procedures through which certain holders of ADRs may obtain tax rebates, credits, refunds or other similar benefits. Pursuant to the Deposit Agreement, the custodian and the Depositary have undertaken to use reasonable efforts to make and maintain arrangements to enable persons that are considered to be resident in United States for purposes of applicable law to receive any rebates or tax credits (pursuant to treaty or otherwise) relating to distributions on the ADRs to which such persons are entitled. In addition, the Depositary has agreed to establish procedures to enable all holders to take advantage of any rebates or tax credits (pursuant to treaty or otherwise) relating to distributions on the ADRs to which such holders are entitled and to provide, at least annually, a written notice, in a form previously agreed to by the Company, to the holders of ADRs of any necessary actions to be undertaken by such Holders.

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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 12.5% 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:

Gains realized by non-residents from non substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.

On the contrary, gains realized by non-residents from substantial 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.

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 ADRs. This summary is addressed to U.S. Holders that hold Shares or ADRs as capital assets, and does not purport to address all material tax consequences of the ownership of Shares or ADRs. 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, investors that hold Shares or ADRs 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),

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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 ADRs.

As used in this section, the term "U.S. Holder" means a beneficial owner of Shares or ADRs who or 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 United States 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 United States persons have the authority to control all substantial decisions of the trust.

The discussion does not address any aspects of the United States taxation other than 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 the United States federal income tax purposes, U.S. Holders who own ADRs evidencing ADRs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for shares generally will not be subject to the United States 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 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 ADRs, 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 ADRs) 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 in taxable years beginning before January 1, 2011 that constitute qualified dividend income will be taxable to you at a maximum tax rate of 15% provided that you hold the Shares or ADRs 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 ADRs 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/U.S. dollar 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 maximum 15% tax rate. 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, the amount of tax withheld that is refundable will not be eligible for credit against your United States federal income tax liability. See "Italian Taxation – Income Tax" above, for the procedures for obtaining a tax refund. Dividends paid on the Shares will be treated as income from sources outside the United States. For foreign tax credit purposes, dividends will be income from sources outside the United States and will, depending on your circumstances, generally 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 ADRs equal to the difference between the U.S. Holder’s adjusted basis in the shares or ADRs (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 ADRs are held as capital assets and will be a long-term capital gain or loss if the shares or ADRs 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 that is recognized in taxable years beginning before January 1, 2011 is generally subject to a

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maximum tax rate of 15%. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.

PFIC rules

Eni SpA believes that shares and ADRs should not be treated as stock of a PFIC for United States 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 ADRs, gain realized on the sale or other disposition of your shares or ADRs 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 ADRs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, your shares or ADRs 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 ADRs. Dividends that you receive from Eni SpA will not be eligible for the special 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.

 

 

Item 11. QUALITATIVE AND QUANTITATIVE 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/U.S. $ 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/U.S. $ 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.

Please refer to Note 29 to the Consolidated Financial Statements for a qualitative and quantitative discussion of the Company’s exposure to market risks. Please also refer to Notes 7 and 20 to the Consolidated Financial Statements for details of the different derivatives owned by the Company in these markets.

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 and trading activities and, 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.

These instruments and their accounting treatment are detailed in Notes 7 and 25 to the Financial Statements.

 

 

Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

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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, 2008.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on pages F-1 and F-2 of this Annual Report on Form 20-F.

Changes in Internal Control over Financial Reporting

There have not been changes in the Company’s internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Item 16A. Board of Statutory Auditors Financial Expert

Eni’s Board of Statutory Auditors has determined that five members of Eni’s Board of Statutory Auditors, qualify as "audit committee financial expert", as defined in Item 16A of Form 20-F. These five members are: Ugo Marinelli, who is the Chairman of the Board, and Roberto Ferranti, Luigi Mandolesi, Tiziano Onesti 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.it, under the section Sustainability – Corporate Governance and Corporate Ethics – Code of Ethics. 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

PricewaterhouseCoopers SpA has served as Eni principal independent public auditor for fiscal years 2006, 2007 and 2008 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 public auditor PricewaterhouseCoopers and its member firms, with respect to the years indicated:

Year ended December 31,

		2006		2007		2008

(thousand euro)

Audit fees		22,240		26,383		27,962
Audit-related fees		166		169		152
Tax fees		303		81		46
All other fees		6		120		1
Total		22,715		26,753		28,161

Audit Fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting.

Audit Related Fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit Fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due diligence, audit and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards.

Tax Fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities.

All Other Fees include products and services provided by the principal accountant, other than the services reported in Audit Fees, Audit-Related Fees and Tax Fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.

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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 2008, 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 following tables present purchases of own shares by Eni from the beginning of the program through May 4, 2009:

Period		Number of shares (million)		Average price (euro per share)		Total cost (euro million)		Share capital %

2000 (since September 1)		44.38			12.92		574		1.11
2001		110.00			13.58		1,494		2.75
2002		52.26			14.74		771		1.30
2003		23.94			13.76		329		0.60
2004		4.23			16.60		70		0.10
2005		47.06			21.97		1,034		1.18
2006		53.13			23.35		1,241		1.33
2007		27.56			24.69		680		0.68
2008		35.90			21.67		778		0.90
2009, through May 4, 2009		-			-		-		-
Total purchased as of May 4, 2009		398.47			17.49		6,971		9.95
minus:
- stock options exercised and shares granted pursuant to stock option and stock grant plans		(15.51	)
Total shares held in treasury		382.95							9.56

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	Total number of shares purchased		Average price paid per share (euro)		Total number of shares purchased, as part of publicly announced plans or programs		Maximum number of shares that may yet be purchased under the plans or programs.(2)

At December 31, 2007 (1)		362,562,118		17.08		362,562,118		51,474,995
January 2008		2,709,130		22.13		365,271,248		48,873,565
February 2008		3,380,161		22.25		368,651,409		45,504,204
March 2008		2,606,938		22.01		371,258,347		42,908,766
April 2008 (3)		2,242,200		23.41		373,500,547		40,678,566
May 2008		2,728,900		25.74		376,229,447		37,949,666
June 2008		2,982,450		24.50		379,211,897		34,967,216
July 2008		2,823,050		22.37		382,034,947		32,144,166
August 2008		1,839,400		21.48		383,874,347		30,304,766
September 2008		13,426,200		19.79		397,300,547		16,878,566
October 2008		1,166,306		18.38		398,466,853		15,712,260
November 2008		-		-		398,466,853		15,712,260
December 2008		-		-		398,466,853		15,712,260
January 2009		-		-		398,466,853		15,712,260
February 2009		-		-		398,466,853		15,712,260
March 2009		-		-		398,466,853		15,712,260
April 2009		-		-		398,466,853		15,712,260
May 2009 (through May 4, 2009)		-		-		398,466,853		15,712,260

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(1)		From May 2000, Eni’s Ordinary Shareholders’ Meeting has authorized Eni’s Board of Directors to carry out a program for the repurchase of own shares within such limits as established by the Shareholders’ Meeting itself. The shares are to be purchased on the Telematico at a price no lower than their nominal value and no higher than 5% over the reference price recorded on the business day preceding each purchase.
(2)		Based on the authorized purchase ceiling, deducting the total number of shares purchased and adding back the number of stock options exercised by and shares granted to Eni’s managers pursuant to stock option and stock grant plans as of Annual Shareholders’ Meeting date.
(3)		On April 29, 2008 Eni’s Ordinary Shareholders’ Meeting authorized the continuation of the program for the repurchase of own shares for a further 18-month period and up to 400 million ordinary shares, nominal value euro 1 each, corresponding approximately to 10% of Eni’s share capital, for an aggregate amount not exceeding euro 7.4 billion: The 400 million shares and the euro 7.4 billion thresholds take into account the number and amount of Eni shares held in treasury as of April 29, 2008. As of April 29, 2008, Eni held in treasury 359.08 million own shares at a cost of euro 6,236 million. The 18-month period will expire in October 2009. According to applicable regulations, the nominal value of shares so purchased, including shares held by subsidiaries cannot exceed 20% of a company’s share capital. Shares purchased in excess of such 20% limit must be resold within one year from the date of their purchase.

 

 

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 which provides for the Board of Directors as the sole corporate body responsible for management and for the establishment of an Audit Committee within the same Board, for monitoring activities.

Below is a description of the most significant differences between corporate governance practices followed by U.S. domestic companies under the NYSE standards and those followed by Eni, also with reference to Borsa Italiana Corporate Governance Code that Eni adopted.

 

Independent Directors

NYSE standards. Under NYSE standards listed U.S. companies’ Boards must have a majority of independent directors. 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 TUF states that at least one member, or two members if the Board is composed by more than seven members, must possess the independence requirements provided for Statutory Auditors of listed companies.

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In particular, a director may not be deemed independent if he/she or an immediate family member has relationships with the issuer that could influence their autonomous judgment, with its directors or with the companies in the same group of the issuer.
Eni’s By-laws increases the number and states that at least one member, if the Board is made up by up to five members, or three Board members, in case the Board is made up by more than five members, shall have the independence requirement.
Eni’s Code foresees further independence requirements, in line with the ones provided by the Borsa Italiana Code, that recommends that the Board of Directors includes an adequate number of independent non-executive directors in the sense that they do not maintain, nor have recently maintained, directly or indirectly, any business relationships with the issuer or persons linked to the issuer, of such a significance as to influence their autonomous judgment.
In accordance with Eni’s By-laws, the Board of Directors periodically evaluates independence of Directors. Eni’s Code also provides for the Board of Statutory Auditors to verify the proper application of criteria and procedures adopted by the Board of Directors to evaluate the independence of its members.
The results of the assessments of the Board shall be communicated to the market.
In accordance with Eni’s By-laws, should the independence requirements be impaired or cease or the minimum number of independent directors diminish below the threshold set by Eni’s By-laws, the Board declares the termination of office of the member lacking said requirements and provides for his substitution. Board members are expected to inform the Company in case they lose their independence requirements or of any reasons for ineligibility or incompatibility that might arise.

 

Meetings of non Executive Directors

NYSE standards. Non-executive directors, including those who are not independent, must meet at regularly scheduled executive sessions without management.
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. As provided by Eni’s Code the independent Directors may hold meetings without the other Directors: this faculty was exercised on January 22, 2009.

 

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 further provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

Eni standards. In its meeting of March 22, 2005, Eni’s Board of Directors, making use of the exemption provided by Rule 10A-3 for non-U.S. private issuers, 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 paragraph "Board of Statutory Auditors" earlier).
Under Section 303A.07 of the NYSE listed Company Manual audit committees of U.S. companies have further functions and responsibilities which are not mandatory for non-U.S. private issuers and which therefore are not included in the list of functions shown in the paragraph referenced above.

 

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 that are entrusted, among others, with the responsibility to identify individuals qualified to become board members and to select or recommend director nominees for submission to the Shareholders’ Meeting, as well as to develop and recommend to the Board of Directors a set of corporate governance guidelines.

Eni standards. This provision is not applicable to non-U.S. private issuers. The Borsa Italiana Code allows listed companies to have within the Board of Directors a committee for directors’ nominees proposals, above all when the Board of Directors detects difficulties in the shareholders’ submission of nominees proposals, as could happen in publicly owned companies.
Eni has not set up a nominating committee, considering the nature of its shareholding as well as the circumstance that, under Eni’s By-laws, directors are appointed by the Shareholders’ Meeting based on lists presented by shareholders.

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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 promptly disclose any waivers of the code for directors or executive officers.

Eni standards. Eni’s Code of Ethic – adopted on March 14, 2008, replacing the previous version of 1998 – 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 ongoing basis: shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the Countries where Eni operates. These values are stated in the Code of Ethics and all the people working for Eni, without exception or distinction, starting from Directors, senior management and members of Company’s bodies, as also requested by the SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing these principles within their function and responsibility. The Guarantor for the Code of Ethics – that is the Watch Structure of the "Model 231" for the organizational, management and control according to Legislative Decree No. 231/2001 – acts for the protection and promotion of the above mentioned principles and every six months presents a report on the implementation of the Code to the Internal Control Committee, to the Board of Statutory Auditors and to the Chairman and the CEO, who reports on this to the Board of Directors.

 

 

 

 

 

 

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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 at December 31, 2008 and 2007		F-3
Consolidated profit and loss account for the years ended December 31, 2008, 2007 and 2006		F-4
Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2008, 2007 and 2006		F-5
Consolidated Statement of cash flows for the years ended December 31, 2008, 2007 and 2006		F-7
Supplemental cash flow information for the years ended December 31, 2008, 2007 and 2006		F-9
Notes to the Consolidated Financial Statements		F-24

 

 

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)

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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: May 14, 2009

 

 

 

 

 

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

To the Board of Directors and Shareholders of Eni SpA.

 

In our opinion, the accompanying consolidated balance sheets and the related consolidated profit and loss accounts, consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows present fairly, in all material respects, the financial position of Eni SpA and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing in Item 15 Controls and Procedures of the 2008 Annual Report to Shareholders. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

 

F-1

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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.

 

PricewaterhouseCoopers SpA

Rome, Italy
May 14, 2009

 

 

 

 

 

 

 

 

 

F-2

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CONSOLIDATED BALANCE SHEET
(euro million)

		Dec. 31, 2007		Dec. 31, 2008

		Note		Total amount		of which with related parties		Total amount		of which with related parties

ASSETS
Current assets
Cash and cash equivalents		(1)		2,114					1,939
Other financial assets held for trading or available for sale:		(2)
- equity instruments				2,476					2,741
- other securities				433					495
				2,909					3,236
Trade and other receivables		(3)		20,676			1,616		22,222			1,539
Inventories		(4)		5,499					6,082
Current tax assets		(5)		703					170
Other current tax assets		(6)		833					1,130
Other current assets		(7)		1,080					2,349			59
Total current assets				33,814					37,128
Non-current assets
Property, plant and equipment		(8)		46,919					55,833
Other assets		(9)		563
Inventory - compulsory stock		(10)		2,171					1,196
Intangible assets		(11)		7,551					11,037
Equity-accounted investments		(12)		5,639					5,471
Other investments		(12)		472					410
Other financial assets		(13)		923			87		1,134			356
Deferred tax assets		(14)		1,915					2,912
Other non-current receivables		(15)		1,110			16		1,401			21
Total non-current assets				67,263					79,394
Assets classified as held for sale		(26)		383					68
TOTAL ASSETS				101,460					116,590
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		(16)		7,763			131		6,359			153
Current portion of long-term debt		(21)		737					549
Trade and other payables		(17)		17,116			1,021		20,515			1,253
Income taxes payable		(18)		1,688					1,949
Other taxes payable		(19)		1,383					1,660
Other current liabilities		(20)		1,556			4		4,319			4
Total current liabilities				30,243					35,351
Non-current liabilities
Long-term debt		(21)		11,330			16		13,929			9
Provisions for contingencies		(22)		8,486					9,573
Provisions for employee benefits		(23)		935					947
Deferred tax liabilities		(24)		5,471					5,742
Other non-current liabilities		(25)		2,031			57		2,538			53
Total non-current liabilities				28,253					32,729
Liabilities directly associated with the assets classified as held for sale		(26)		97
TOTAL LIABILITIES				58,593					68,080
SHAREHOLDERS’ EQUITY		(27)
Minority interest				2,439					4,074
Eni shareholders’ equity
Share capital				4,005					4,005
Reserves				34,610					40,722
Treasury shares				(5,999	)				(6,757	)
Interim dividend				(2,199	)				(2,359	)
Net profit				10,011					8,825
Total Eni shareholders’ equity				40,428					44,436
TOTAL SHAREHOLDERS’ EQUITY				42,867					48,510
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY				101,460					116,590

F-3

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)

		2006		2007		2008

Note

Total amount

of which with related parties

Total amount

of which with related parties

Total amount

of which with related parties

REVENUES
Net sales from operations		(30)		86,105			3,974			87,256			4,198			108,148			5,048
Other income and revenues				783						827						720			39
Total revenues				86,888						88,083						108,868
OPERATING EXPENSES		(31)
Purchases, services and other				57,490			2,720			58,179			3,777			76,408			6,298
- of which non-recurring charge				239						91						(21	)
Payroll and related costs				3,650						3,800						4,004
- of which non-recurring income										(83	)
Depreciation, depletion, amortization and impairments				6,421						7,236						9,815
OPERATING PROFIT				19,327						18,868						18,641
FINANCE INCOME (EXPENSE)		(32)
Finance income				3,749			58			4,445			49			7,985			42
Finance expense				(3,971	)		(18	)		(4,554	)		(20	)		(8,198	)		(17	)
Derivative financial instruments				383						26			10			(551	)		58
				161						(83	)					(764	)
INCOME FROM INVESTMENTS		(33)
Share of profit (loss) of equity-accounted investments				795						773						640
Other gain (loss) from investments				108						470						733
				903						1,243						1,373
PROFIT BEFORE INCOME TAXES				20,391						20,028						19,250
Income taxes		(34)		(10,568	)					(9,219	)					(9,692	)
Net profit				9,823						10,809						9,558
Attributable to
Eni				9,217						10,011						8,825
Minority interest		(27)		606						798						733
				9,823						10,809						9,558
Earnings per share attributable to Eni (euro per share)		(35)
Basic				2.49						2.73						2.43
Diluted				2.49						2.73						2.43

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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

Other reserves

Cumulative currency translation differences

Treasury shares

Retained earnings

Interim dividend

Net profit for the year

Total

Minority interest

Total shareholders’ equity

Balance at December 31, 2006		4,005			959			7,262			400			(398	)		(5,374	)		25,168			(2,210	)		9,217			39,029			2,170			41,199
Net profit for the year																										10,011			10,011			798			10,809
Gains (losses) recognized directly in equity
Change in the fair value of available-for-sale securities											(4	)																	(4	)					(4	)
Change in the fair value of cash flow hedge derivatives											(1,370	)																	(1,370	)					(1,370	)
Foreign currency translation differences											25			(1,954	)														(1,929	)		(51	)		(1,980	)
											(1,349	)		(1,954	)														(3,303	)		(51	)		(3,354	)
Total recognized income and (expense) for the year											(1,349	)		(1,954	)											10,011			6,708			747			7,455
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.65 per share in settlement of 2006 interim dividend of euro 0.60 per share)																							2,210			(4,594	)		(2,384	)					(2,384	)
Interim dividend distribution of Eni SpA (euro 0.60 per share)																							(2,199	)					(2,199	)					(2,199	)
Dividend distribution of other companies																																(289	)		(289	)
Payments by minority shareholders																																1			1
Allocation of 2006 net profit																				4,623						(4,623	)
Shares repurchased																	(680	)											(680	)					(680	)
Treasury shares sold under incentive plans for Eni managers								(55	)		35						55			11									46						46
Difference between the carrying amount and strike price of stock options exercised by Eni managers																				9									9						9
								(55	)		35						(625	)		4,643			11			(9,217	)		(5,208	)		(288	)		(5,496	)
Other changes in shareholders’ equity
Net effect related to the purchase of treasury shares by Saipem SpA and Snam Rete Gas SpA																																(201	)		(201	)
Cost related to stock option and stock grant																				18									18						18
Foreign currency translation differences on the distribution of dividends and other changes														119						(238	)								(119	)		11			(108	)
														119						(220	)								(101	)		(190	)		(291	)
Balance at December 31, 2007		4,005			959			7,207			(914	)		(2,233	)		(5,999	)		29,591			(2,199	)		10,011			40,428			2,439			42,867

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued
(euro million)

	Eni shareholders’ equity

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Other reserves

Cumulative currency translation differences

Treasury shares

Retained earnings

Interim dividend

Net profit for the year

Total

Minority interest

Total shareholders’ equity

Balance at December 31, 2007		4,005			959			7,207			(914	)		(2,233	)		(5,999	)		29,591			(2,199	)		10,011			40,428			2,439			42,867
Net profit for the year																										8,825			8,825			733			9,558
Gains (losses) recognized directly in equity
Change in the fair value of available-for-sale securities (Note 27)											2																		2						2
Change in the fair value of cash flow hedge derivatives (Note 27)											1,255																		1,255			(52	)		1,203
Foreign currency translation differences														1,066															1,066			11			1,077
											1,257			1,066															2,323			(41	)		2,282
Total recognized income and (expense) for the year											1,257			1,066												8,825			11,148			692			11,840
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.70 per share in settlement of 2007 interim dividend of euro 0.60 per share)																							2,199			(4,750	)		(2,551	)					(2,551	)
Interim dividend distribution of Eni SpA (euro 0.65 per share)																							(2,359	)					(2,359	)					(2,359	)
Dividend distribution of other companies																																(297	)		(297	)
Payments by minority shareholders																																20			20
Allocation of 2007 net profit																				5,261						(5,261	)
Shares repurchased																	(778	)											(778	)					(778	)
Treasury shares sold under incentive plans for Eni managers								(20	)		13						20			(1	)								12						12
Difference between the carrying amount and strike price of stock options exercised by Eni managers																				2									2						2
								(20	)		13						(758	)		5,262			(160	)		(10,011	)		(5,674	)		(277	)		(5,951	)
Other changes in shareholders’ equity
Net effect related to the purchase of treasury shares by Saipem SpA																																(31	)		(31	)
Cost related to stock option and stock grant																				18									18						18
Put option granted to Publigaz (the Distrigas minority shareholder)											(1,495	)																	(1,495	)					(1,495	)
Minority interest recognized following the acquisition of Distrigas NV and Hindustan Oil Exploration Co Ltd																																1,261			1,261
Foreign currency translation differences on the distribution of dividends and other changes											(1	)		198						(186	)								11			(10	)		1
											(1,496	)		198						(168	)								(1,466	)		1,220			(246	)
Balance at December 31, 2008 (Note 27)		4,005			959			7,187			(1,140	)		(969	)		(6,757	)		34,685			(2,359	)		8,825			44,436			4,074			48,510

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)

		Note		2006		2007		2008

Net profit of the year				9,823			10,809			9,558
Depreciation, depletion and amortization		(31)		6,153			7,029			8,422
Revaluations, net				(386	)		(494	)		2,560
Net change in provisions for contingencies				(86	)		(122	)		414
Net change in the provisions for employee benefits				72			(67	)		(8	)
Gain on disposal of assets, net				(59	)		(309	)		(219	)
Dividend income		(33)		(98	)		(170	)		(510	)
Interest income				(387	)		(603	)		(592	)
Interest expense				346			523			809
Exchange differences				6			(119	)		(319	)
Income taxes		(34)		10,568			9,219			9,692
Cash generated from operating profit before changes in working capital				25,952			25,696			29,807
(Increase) decrease:
- inventories				(953	)		(1,117	)		(801	)
- trade and other receivables				(1,952	)		(655	)		(974	)
- other assets				(315	)		(362	)		162
- trade and other payables				2,146			360			2,318
- other liabilities				50			107			1,507
Cash from operations				24,928			24,029			32,019
Dividends received				848			658			1,150
Interest received				395			333			266
Interest paid				(294	)		(555	)		(852	)
Income taxes paid, net of tax receivables received				(8,876	)		(8,948	)		(10,782	)
Net cash provided from operating activities				17,001			15,517			21,801
- of which with related parties		(37)		2,206			549			(62	)
Investing activities:
- tangible assets		(8)		(5,963	)		(8,364	)		(12,082	)
- intangible assets		(11)		(1,870	)		(2,229	)		(2,480	)
- consolidated subsidiaries and businesses				(46	)		(4,759	)		(3,634	)
- investments		(12)		(42	)		(4,890	)		(385	)
- securities				(49	)		(76	)		(152	)
- financing receivables				(516	)		(1,646	)		(710	)
- change in payables and receivables in relation to capital expenditures and capitalized depreciation				(26	)		185			367
Cash flow from investments				(8,512	)		(21,779	)		(19,076	)
Disposals:
- tangible assets				231			165			318
- intangible assets				18			35			2
- consolidated subsidiaries and businesses				8			56			149
- investments				36			403			510
- securities				382			491			145
- financing receivables				794			545			1,293
- change in payables and receivables in relation to disposals				(8	)		(13	)		(299	)
Cash flow from disposals				1,461			1,682			2,118
Net cash used in investing activities (*)				(7,051	)		(20,097	)		(16,958	)
- of which with related parties		(37)		(686	)		(822	)		(1,598	)

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CONSOLIDATED STATEMENT OF CASH FLOWS continued
(euro million)

		Note		2006		2007		2008

Proceeds from long-term debt				2,888			6,589			3,774
Repayments of long-term debt				(2,621	)		(2,295	)		(2,104	)
Increase (decrease) in short-term debt				(949	)		4,467			(690	)
				(682	)		8,761			980
Net capital contributions by minority shareholders				22			1			20
Net acquisition of treasury shares different from Eni SpA				(477	)		(340	)		(50	)
Acquisition of additional interests in consolidated subsidiaries				(7	)		(16	)
Sale of additional interests in consolidated subsidiaries				35
Dividends paid to Eni’s shareholders				(4,610	)		(4,583	)		(4,910	)
Dividends paid to minority interest				(222	)		(289	)		(297	)
Net purchase of treasury shares				(1,156	)		(625	)		(768	)
Net cash used in financing activities				(7,097	)		2,909			(5,025	)
- of which with related parties		(37)		(57	)		20			14
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)				(4	)		(40	)		(1	)
Effect of exchange rate changes on cash and cash equivalents				(197	)		(160	)		8
Net cash flow for the period				2,652			(1,871	)		(175	)
Cash and cash equivalents - beginning of year		(1)		1,333			3,985			2,114
Cash and cash equivalents - end of year		(1)		3,985			2,114			1,939

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SUPPLEMENTAL CASH FLOW INFORMATION
(euro million)

				2006		2007		2008

Effect of investment of companies included in consolidation and businesses
Current assets		68			398			1,938
Non-current assets		130			5,590			7,442
Net borrowings		53			1			1,543
Current and non-current liabilities		(92	)		(972	)		(3,598	)
Net effect of investments		159			5,017			7,325
Minority interests								(1,261	)
Fair value of investments held before the acquisition of control					(13	)		(601	)
Sale of unconsolidated entities controlled by Eni		(60	)
Purchase price		99			5,004			5,463
less:
Cash and cash equivalents		(53	)		(245	)		(1,829	)
Cash flow on investments		46			4,759			3,634
Effect of disposal of consolidated subsidiaries and businesses
Current assets		9			73			277
Non-current assets		1			20			299
Net borrowings		(1	)		26			(118	)
Current and non-current liabilities		(4	)		(94	)		(270	)
Net effect of disposals		5			25			188
Gain on disposal		3			33			25
Minority interest								(1	)
Selling price		8			58			212
less:
Cash and cash equivalents					(2	)		(63	)
Cash flow on disposals		8			56			149

Transactions that did not produce cash flows
Acquisition of equity investments in exchange of businesses contribution:

(euro million)				2006		2007		2008

Current assets		23
Non-current assets		213			38
Net borrowings		(44	)		(4	)
Long-term and short-term liabilities		(53	)
Net effect of contribution		139			34
Minority interest		(36	)
Gain on contribution		18
Acquisition of investments		121			34

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Basis of presentation

The Consolidated Financial Statements of Eni Group for the Annual Report on Form 20-F have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Oil and natural gas exploration and production activity is accounted for in conformity with internationally accepted accounting principles. Specifically, this concerns the determination of the amortization expenses using the unit-of-production method and the recognition of the production-sharing agreements and buy-back contracts. The Consolidated Financial Statements have been prepared on a historical cost basis 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 accounts of Eni SpA and the accounts of controlled subsidiary companies where the company holds the right to directly or indirectly exercise control, determine financial and management decisions and obtain economic and financial benefits.

Immaterial subsidiaries are not consolidated. A subsidiary is generally considered to be immaterial when it does not exceed two of the following three limits: (i) total assets or liabilities: euro 3,125 thousand; (ii) total revenues: euro 6,250 thousand; and (iii) average number of employees: 50 units. Moreover, companies for which consolidation does not produce significant economic and financial effects are not consolidated. These are usually entities acting as sole-operator in the management of oil and gas contracts on behalf of companies participating in a joint venture. These 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 obligations arising from the project, are recognized proportionally in the financial statements of the companies involved. The effects of these exclusions are immaterial¹.

Immaterial subsidiaries excluded from consolidation, jointly controlled entities, associates and other 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 2008 Consolidated Financial Statements approved by Eni’s Board of Directors on March 13, 2009 were audited by the independent auditor PricewaterhouseCoopers SpA (PwC). The independent auditor of Eni SpA, as the main auditor of the Group, is in charge of the auditing activities of the subsidiaries, unless this is incompatible with local laws, and, to the extent allowed under Italian legislation, of the work of other independent auditors.

Amounts in the notes to these financial statements are expressed in millions of euros (euro million).

 

Principles of consolidation

Interest 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 interests in these subsidiaries is eliminated against the corresponding share of the shareholders’ equity by attributing to each of the balance sheet items its fair value at the acquisition date.

When acquired, the net equity of controlled 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 minority shareholders are included in specific lines of the financial statements; this share of equity is determined using the fair value of assets and liabilities, excluding any related goodwill, at the time when control is acquired.

The purchase of additional ownership interests in subsidiaries from minority shareholders is recognized as goodwill and represents the excess of the amount paid over the carrying value of the minority interest acquired.

Gains or losses associated with the sale of interests in consolidated subsidiaries are reflected in the profit and loss account for the difference between proceeds from the sale and the divested portion of net equity.

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Inter-company transactions
Inter-company transactions, balances and unrealized gains on transactions between group companies are eliminated. Unrealized losses are not eliminated since they are considered an impairment indicator of the asset transferred.

Foreign currency translation
Financial statements of foreign companies having a functional currency other than euro are translated into the presentation currency using closing exchange rates for assets and liabilities, historical exchange rates for equity accounts and average rates for the period for the profit and loss account (source: Bank of Italy).

Cumulative exchange differences resulting from this translation are recognized in shareholders’ equity under "Other reserves" in proportion to the group’s interest and under "Minority interest" for the portion related to minority shareholders. Cumulative exchange differences are charged to the profit and loss account when the investments are sold or the capital employed is repaid.

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 adopt euro.

 

Summary of significant accounting policies

The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Current assets
Held for trading financial assets and available-for-sale financial assets are measured at fair value with gains or losses recognized in the profit and loss account under "Financial income (expense)" and as a component of equity within "Other reserves", respectively.

In the latter case, changes in fair value recognized under shareholders’ equity are charged to the profit and loss account when they are impaired or realized. The objective evidence that an impairment loss has occurred is verified considering, interalia, significant breaches of contracts, serious financial difficulties or the high probability of insolvency of the counterparty; asset write downs are included in the carrying amount².

Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets, held-to-maturity financial assets and investments associated with a derivative financial instrument. The latter are stated at fair value with effects of changes in fair value recognized in the profit and loss account rather than in shareholders’ equity (the so-called "fair value option") in order to ensure a match with the recognition in the profit and loss account of the changes in fair value of the derivative instrument³.

The fair value of financial instruments is determined by market quotations or, in their absence, by the value resulting from the adoption of 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 financial assets stated at fair value with gains or losses reflected in the profit and loss account are accounted for on an accrual basis as "Financial income (expense)" and "Income (expense) from investments", respectively. When the purchase or sale of a financial asset under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the market place concerned, the transaction is accounted for on the settlement date. Receivables are carried 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 contract work in progress, are stated at the lower of purchase or production cost and net realizable value. Net realizable value is the estimated selling price less the costs to sell. The cost for inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is

 

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determined by applying the weighted-average cost method on a three-month basis; the cost for inventories of the Petrochemical segment is determined by applying the weighted-average cost on an annual basis.

Contract work in progress is measured using the cost-to-cost method whereby contract revenue is recognized based on the stage of completion as determined by the cost sustained. Advances are deducted from inventories within the limits of contractual considerations; any excess of such advances over the value of the inventories is recorded as a liability. Losses related to construction contracts are accrued for once the company becomes aware of such losses. Contract work in progress not yet invoiced, whose payment will be made in a foreign currency, is translated to euro using the current exchange rates at year end and the effect of rate changes is reflected in the profit and loss account.

Hedging instruments are described in the section "Derivative instruments".

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 borne 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 is 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 taxes due from the lessor 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 and the estimated useful life of the asset.

Expenditures on renewals, improvements and transformations which provide additional economic benefits are capitalized to property, plant and equipment.

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 represented by the book value reduced by 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 but are valued at the lower of book value and fair value less costs of disposal.

Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession and the useful life of the asset.

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 represented by the higher of fair value less costs to sell

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and 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. 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 therefrom) 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. WACC differs considering the risk associated with individual operating segments; in particular for the assets belonging to the Gas & Power and Engineering & Construction segments, taking into account the 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 company assets are not located in a specific country. For the regulated activities, the discount rate to use for the measurement of value in use is equal to the rate of return defined by the Regulator. 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 realizable value 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 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 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 generated by the underlying asset and to restrict the access of others to those cash flows.

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 verified 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 level of the smallest aggregate on which the company, directly or indirectly, evaluates the return on the capital expenditure to which goodwill relates. When the carrying amount of the cash generating unit, including goodwill allocated thereto, exceeds the cash generating unit’s recoverable amount, the excess is recognized as impairment. 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

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pro-rata on the basis of the carrying amount of each asset in the unit. Impairment charges against goodwill are not reversed⁶. Negative goodwill is recognized in the profit and loss account.

Costs of technological development activities are capitalized when: (i) the cost attributable to the development activity can be reasonably determined; (ii) there is the intention, availability of funding and technical capacity 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 in which: (i) the grantor controls or regulates what services the operator must provide with the infrastructure, to whom it must provide them and at what price; and (ii) the grantor controls – through ownership, beneficial entitlement or otherwise – any significant residual interest in the infrastructure at the end of the term of the arrangement. According to the terms of the agreements the operator has the right to operate the infrastructure, controlled by the grantor, in order to provide the public service ^{7 8}.

Exploration and production activities⁹

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 costs are those costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas. They are 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 investments 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.

 

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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 and amortized on a UOP basis, consistent with the policy described under "Property, plant and equipment".

Grants
Grants related to assets are recorded 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.

Financial fixed assets

Investments
Investments in subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for using the equity method¹⁰. Subsidiaries, joint ventures and associates excluded from consolidation 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 accounted for at cost are re-valued within the limit of the impairment made and their effects are included in "Other income (expense) from investments".

Other investments, included in non current assets, are recognized at their fair value and their effects are included in shareholders’ equity under "Other reserves"; this reserve is charged to the profit and loss account when it is impaired or realized. When investments are not traded in a public market and fair value cannot be reasonably determined, investments are accounted for at cost, adjusted for impairment losses; impairment losses may not be reversed¹¹.

The risk deriving from losses exceeding shareholders’ equity is recognized in a specific provision to the extent the parent company is required to fulfill legal or implicit obligations towards the subsidiary 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 capital repayments, devaluations and amortization of the difference between the reimbursement value and the initial carrying value. Amortization is carried out on the basis of the effective internal rate of return represented by the rate that equalizes, at the moment of the initial revaluation, the current value of expected cash flows to the initial carrying value (so-called amortized cost method). Any impairment is recognized by comparing the carrying value with the present value of the expected cash flows discounted at the effective interest rate defined at the initial recognition, or at the

 

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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 excess allowance for impairment losses is reversed. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as "Financial income (expense)".

Financial liabilities
Debt is carried at amortized cost (see item "Financial fixed assets" above).

Provisions for contingencies
Provisions for contingencies are liabilities for risks 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 current 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. 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 restoration and abandonment), the provision is stated with a corresponding entry to the asset to which it refers; charges to the profit and loss account charge 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 formally defines the plan and the interested parties have developed the reasonable expectation that the restructuring will happen.

Provisions are periodically updated to show the variations of estimates of costs, production times and actuarial rates; the estimated revisions to the 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 restoration and abandonment) with a corresponding entry to the assets to which they refer.

In the notes to the consolidated financial statements the following potential liabilities are described: (i) possible, but not probable obligations deriving from past events, whose existence will be confirmed only when one or more future events beyond the company’s control occur; and (ii) current obligations deriving from past events whose amount cannot be reasonably estimated or whose fulfillment will probably not result in an outflow of resources embodying economic benefits.

Employee benefits
Post-employment benefit plans, including constructive obligations, 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 actuarial gains and losses unrecognized at the end of the previous reporting period exceed the greater of 10% of the present value of the defined benefit obligation and 10% of the fair value of the plan assets, over the expected average remaining working lives of the employees participating to 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.

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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 are taken to profit or loss in their entirety.

Treasury shares
Treasury shares are recorded at cost and as a reduction of equity. Gains resulting from subsequent sales are recorded in equity.

Revenues and costs
Revenues associated with sales of products and services are recorded when significant risks and rewards of ownership pass to the customer or when the transaction can be considered settled and 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 are generally recognized upon shipment;
• 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 in 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 basis¹².

Requests of additional revenues, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount; claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them.

Revenues are stated net of returns, discounts, rebates, bonuses and direct taxation. 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, consumed or allocated, or when their future benefits cannot be determined. Costs associated with emission quotas, determined on the basis of the average prices of the main European markets at period end, are reported in relation to the amount of the carbon dioxide emissions that exceed the amount assigned; related revenues are recognized upon sale. Costs related to the purchase of the emission rights are taken to intangible assets net of any negative difference between the amount of emissions and the quotas assigned.

Operating lease payments are recognized in the profit and loss account over the length of the contract.

Labor costs include stock grants and 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. 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 the stock grants and stock options is recorded as a charge to "Other reserves".

 

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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 borne for other scientific research activities or technological development, which cannot be capitalized, 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 the 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 assets that are re-measured to fair value, recoverable amount or realizable value are translated at the exchange rate applicable at the date of re-measurement.

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 tax payables". Current tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the tax authorities, using tax laws that have been enacted or substantively enacted at the balance sheet date and the tax rates estimated on an annual basis. Deferred tax assets or liabilities are provided on temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates (tax laws) that have been enacted or substantively enacted for future years. Deferred tax assets are recognized when their realization is considered probable. Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to offsettable taxes. The balance of the offset, if positive, is recognized in the item "Deferred tax assets"; if negative, in the item "Deferred tax liabilities". When the results of transactions are recognized directly in shareholders’ equity, current taxes, deferred tax assets and liabilities are also charged to the shareholders’ equity.

Derivatives

Derivatives, including embedded derivatives which are separated from the host contract, are assets and liabilities recognized at their fair value which is estimated by using the criteria described in the section "Current assets". When there is objective evidence that an impairment loss has occurred (see "Current assets" paragraph) derivatives are recognized net of the allowance for impairment losses.

Derivatives are classified as hedging instruments when the relationship between the derivative and the subject of the hedge is formally documented and the effectiveness of the hedge is high and is checked periodically. When hedging instruments cover the risk of variation of the fair value of the hedged item (fair value hedge, e.g. hedging of the variability of the fair value of fixed interest rate assets/liabilities) the derivatives are stated at fair value and the effects charged to the profit and loss account. Hedged items are consistently adjusted to reflect the variability of fair value associated with the hedged risk. When derivatives hedge the cash flow variation 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), changes in the fair value of the derivatives considered effective are initially stated in equity and then recognized in the profit and loss account consistent with the economic effects produced by the hedged transaction. The changes in the fair value of derivatives that do not meet the conditions required to qualify for hedge accounting are shown in the profit and loss account.

Economic effects of transactions, which relate to purchase or sales contracts for commodities entered into to meet the entity’s normal operating requirements and for which the settlement is provided with the delivery of the goods, are recognized on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

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Financial statements
Assets and liabilities of the balance sheet are classified as current and non-current. Items of the profit and loss account are presented by nature¹⁴.

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.

 

Use of accounting estimates

The company’s Consolidated Financial Statements are prepared in accordance with IFRS. These require 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 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 can be produced with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Although there are authoritative guidelines regarding the engineering 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 and 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 will be classified as proved undeveloped. Volumes will subsequently be reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings will 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 as regards the initial estimate and, in the case of Production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered.

Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense.

Depreciation 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

 

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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
Eni assesses its tangible assets and intangible assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate the carrying values of the assets are not recoverable.

Such 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 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.

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 costs and 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 reviews 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. The estimated future level of production is based on assumptions concerning: future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.

Oil, natural gas and petroleum products prices 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, market demand and to 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 such assets at the cash-generating unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value below its carrying amount. In particular, goodwill impairment is based on the determination of the fair value of each cash-generating unit to which goodwill can be attributed 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 on a pro-rata basis 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 increased with the passage of time (i.e. interest

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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 acquisitions, typically engages an independent appraisal firm 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 legislation 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 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 Decree No. 471/1999 of the Ministry of Environment concerning the remediation of contaminated sites; (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, as against other potentially responsible parties with respect to such litigations and the possible insurance recoveries.

Employee benefits
Defined benefit plans and other long-term benefits 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 pensions and other post-retirement benefits 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 rates of annuity contracts and rates of return on high quality fixed-income investments. 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, based principally on available actuarial data; 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, equities 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 10% of the greater 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 effect of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to profit or loss in their entirety.

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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 appropriate amounts for accrual is a complex estimation process that includes subjective judgments.

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, 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. Requests of additional income, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them.

 

Recent accounting principles

Accounting standards and interpretations issued by IASB /IFRIC
IFRS 8 "Operating Segments" replaced IAS 14 "Segment Reporting". IFRS 8 sets out requirements for disclosure of information about the group segments that management uses to make decisions about operating matters. The identification of operating segments is based on internal reports that are regularly reviewed by the chief operating decision maker in order to allocate resources to the segments and assess their performances. IFRS 8 comes into effect starting on January 1, 2009.

The revised IAS 1 "Presentation of Financial Statements" requires, among other things, a statement of comprehensive income that begins with the amount of net profit for the year adjusted with all items of income and expenses directly recognized in equity, but excluded from net income, in accordance with IFRS. The revised standard comes into effect starting on January 1, 2009.

The revised IAS 23 "Borrowing Costs" requires the removal of the option of immediately recognizing as an expense borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset that take a substantial period of time to get ready for use or sale. The company is required to capitalize such borrowing costs as part of the cost of the asset. The revised standard comes into effect starting on January 1, 2009.

The revised IFRS 2 "Share-based payment" specifies the accounting treatment of all cancellations of a grant of equity instruments to employees. It also imposes that vesting conditions are only service and performance conditions required in return for the equity instruments issued. The revised standard comes into effect starting on January 1, 2009.

IFRIC 13 "Customer Loyalty Programmes" addresses how companies, which grant their customers loyalty, award credits when buying goods or services, should account for their obligation to provide free or discounted goods or services if and when the customers redeem the credits. In particular IFRIC 13 requires companies to allocate some of the consideration received from the sales transaction to the award credits and their recognition at fair value. This interpretation came into effect for annual periods beginning on or after July 1, 2008 (for Eni: 2009 financial statements).

Amendments to IAS 1 "Presentation of Financial Statements" and to IAS 32 "Financial Instruments: Presentation" define the conditions that the puttable instruments issued by companies have to meet in order to be classified as equity. Moreover it allowed the classification as equity of instruments issued by the company that impose on the company an obligation to deliver to another party a pro rata share of the net assets of the entity only on liquidation. The amendments to IAS 1 and IAS 32 come into effect starting on January 1, 2009.

"Improvements to IFRSs", defined in the context of the annual process of "Improvements to IFRS" regards only changes to the existing standards with a technical and editorial nature. The provisions come into effect starting on January 1, 2009.

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On January 10, 2008, IASB issued a revised IFRS 3 "Business Combinations" and an amended version of IAS 27 "Consolidated and Separate Financial Statements". The revisions to IFRS 3 require, among other things, (i) the acquisition-related costs to be accounted for separately from the business combination and then recognized as expenses rather than included in goodwill, (ii) the recognition in the income statement of any change to contingent consideration, and (iii) the choice of the full goodwill method which means to treat the full value of the goodwill of the business combination including the share attributable to minority interest. In the case of step acquisitions, the revisions also relate to the recognition in the profit and loss account of the difference between the fair value at the acquisition date of the net assets previously held and their carrying amounts.

The amendments of IAS 27 require, among other things, that acquisitions or disposals of non-controlling interests in a subsidiary that do not result in the loss of control, shall be accounted for as equity transactions. By contrast, disposal of any interests that the parent retains in a former subsidiary may result in a loss of control. In this case, at the date when control is lost the remaining investment retained is increased/decreased to fair value with gains or losses arising from the difference between the fair value and carrying amount of the held investment recognized in the profit or loss account. The revised Standards shall be applied for annual periods beginning on or after July 1, 2009 (for Eni: 2010 financial statements).

On July 3, 2008, IFRIC issued IFRIC 16 "Hedges of a Net Investment in a Foreign Operation" which defines the criteria for recognition and evaluation of hedges of a net investment in a foreign operation. In particular the interpretation defines, among other things, that the object of the hedge is the exchange differences between the functional currency of the foreign operation and the parent’s functional currency and that the hedge instrument can be held by any Group company with the exception of the hedged foreign operation. This interpretation shall be applied for annual periods beginning on or after October 1, 2008 (for Eni: 2009 financial statements).

On November 27, 2008, IFRIC issued IFRIC 17 "Distributions of Non-cash Assets to Owner" which defines the criteria of recognition and evaluation of the distributions of assets other than cash when it pays dividends to its owner. It also applies in those situations in which an entity gives its owner a choice of receiving either non-cash assets or a cash alternative. In particular, an entity shall measure a liability to distribute non-cash assets as dividends to its owners at the fair value of the assets to be distributed. The liability, with any adjustments, is recognized as a contra to equity. When the entity settles the dividend payable, the difference, if any, between the carrying amount of the assets distributed and the fair value of the dividend payable is taken to profit or loss. This interpretation shall be applied for annual periods beginning on or after July 1, 2009 (for Eni: 2010 financial statements).

On January 29, 2008, IFRIC issued IFRIC 18 "Transfers of Assets from customers" which defines the criteria of recognition and evaluation of transfers of items of property, plant and equipment by service providers that receive such transfers from their customers. The interpretation is also applied in the cases in which the entity receives cash from a customer that must be used only to connect the customer to a network. When the definition of an asset is met, the asset is recognized at its fair value. When the connection is realized, the entity shall recognize the revenue for a period generally determined by the terms of the arrangement with the customer or, if the arrangement does not specify a term, over a period corresponding to the lower of the length of the supply and the useful life of the asset used to provide the ongoing service. This interpretation shall be applied for annual periods beginning on or after July 1, 2009 (for Eni: 2010 financial statements).

Eni is currently reviewing these new IFRS and interpretations to determine the likely impact on the Group’s results.

 

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Notes to the Consolidated Financial Statements

Current assets

1 Cash and cash equivalents
Cash and cash equivalents of euro 1,939 million (euro 2,114 million at December 31, 2007) included financing receivables originally due within 90 days for euro 616 million (euro 415 million at December 31, 2007). The latter were related to amounts on deposit with financial institutions accessible only on a 48-hour notice.

2 Other financial assets held for trading or available for sale
Other financial assets held for trading or available for sale are set out below:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Investments		2,476		2,741
Securities held for operating purposes
Listed Italian treasury bonds		229		257
Listed securities issued by Italian and foreign financial institutions		27		45
Non-quoted securities		3		8
		259		310
Securities held for non-operating purposes
Listed Italian treasury bonds		168		109
Listed securities issued by Italian and foreign financial institutions		5		67
Non-quoted securities		1		9
		174		185
Total other securities		433		495
		2,909		3,236

Equity instruments of euro 2,741 million (U.S. $3,815 million at December 31, 2008 exchange rate) comprised the carrying amount of a 20% interest in OAO Gazprom Neft acquired on April 4, 2007 following finalization of a bid within the Yukos liquidation procedure. This entity is currently listed at the London Stock Exchange where approximately 5% of the share capital is traded, while Gazprom currently holds a 75% stake. This accounting classification reflects the circumstance that Eni granted to Gazprom a call option on the entire 20% interest to be exercisable by Gazprom within 24 months from the acquisition date, at a price of U.S. $3.7 billion equaling the bid price, adjusted by subtracting dividends distributed and adding possible share capital increases, a contractual remuneration of 9.4% on the capital employed and related financing expenses.

The existing shareholder agreements establish that the governance of the investee will be modified to allow Eni to exercise significant influence through participation in the financial and operating policy decisions of the investee in the case that Gazprom does not exercise its call option. The carrying amount of the interest equals the strike price of the call option as of December 31, 2008. Eni decided not to adjust the carrying amount of the interest to the market prices at the balance sheet date resulting in U.S. $1,961 million for the following reasons: (i) if Gazprom decides to exercise the call option, the strike price will be equal to the current carrying amount; (ii) if Gazprom decides not to exercise the call option, Eni will be granted significant influence in the decision-making process of the investee and consequently will be in a position to account for the investee in accordance with the equity method of accounting provided by IAS 28 for interests in associates. Under the equity method, Eni is required to allocate the purchase price to the corresponding interest in net equity and the residual amount to fair values of the investee’s assets and liabilities. Subsequently, the carrying amount is adjusted to reflect Eni’s share of losses and profits of the investee. Based on available information and the outcome of an impairment test performed also with the support of an independent consultant, the equity method assessment would result in an amount not lower than the current carrying amount of the interest.

Other securities of euro 495 million (euro 433 million at December 31, 2007) were available-for-sale securities. At December 31, 2007 and December 31, 2008, Eni did not own financial assets held for trading.

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The effects of the valuation at fair value of securities are set out below:

(euro million)		Value at Dec. 31, 2007		Changes recognized in the reserves of shareholders' equity		Value at Dec. 31, 2008

Fair value		2			3			5
Deferred tax liabilities					(1	)		(1	)
Other reserves of shareholders’ equity		2			2			4

Securities held for operating purposes of euro 310 million (euro 259 million at December 31, 2007) were designed to provide coverage of technical reserves of Group’s insurance company Eni Insurance Ltd for euro 302 million (euro 256 million at December 31, 2007).

The fair value of securities was determined by reference to quoted market prices.

3 Trade and other receivables
Trade and other receivables were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Trade receivables		15,609		16,444
Financing receivables:
- for operating purposes - short-term		357		402
- for operating purposes - current portion of long-term receivables		27		85
- for non-operating purposes		990		337
		1,374		824
Other receivables:
- from disposals		125		149
- other		3,568		4,805
		3,693		4,954
		20,676		22,222

Receivables are stated net of the allowance for impairment losses of euro 1,251 million (euro 935 million at December 31, 2007):

(euro million)		Value at Dec. 31, 2007		Additions		Deductions		Other changes		Value at Dec. 31, 2008

Trade receivables		595			251			(36	)		(63	)		747
Financing receivables					14						5			19
Other receivables		340			137			(26	)		34			485
		935			402			(62	)		(24	)		1,251

The increase in trade receivables of euro 835 million was primarily related to the Gas & Power segment (euro 1,987 million), the Engineering & Construction segment (euro 513 million). These increases were partially offset by the decrease related to the Refining & Marketing segment (euro 1,036 million), Petrochemicals (euro 459 million) and Exploration & Production segment (euro 115 million).

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Trade and other receivables were as follows:

(euro million)		Dec. 31, 2008

		Trade receivables		Other receivables		Total

Neither impaired nor past due		12,611		3,395		16,006
Impaired (net of the valuation allowance)		1,242		88		1,330
Not impaired and past due in the following periods:
- within 90 days		1,812		502		2,314
- 3 to 6 months		231		68		299
- 6 to 12 months		248		294		542
- over 12 months		300		607		907
		2,591		1,471		4,062
		16,444		4,954		21,398

Trade receivables not impaired and past due primarily referred to high-credit-quality public administrations and other highly-reliable counterparties for oil, natural gas and chemical products supplies.

Allowances for impairment losses of traded receivables of euro 251 million (euro 98 million in 2007) primarily referred to Refining & Marketing segment (euro 72 million), Gas & Power segment (euro 65 million), Petrochemicals (euro 60 million) and Syndial SpA (euro 27 million). In comparison with 2007 the amount of the allowance is more than double as a consequence of the larger number of clients in financial difficulties after the worsening of general economic conditions over the last part of the year.

Allowances for impairment losses of other receivables of euro 137 million (euro 109 million in 2007) primarily referred to the Exploration & Production segment (euro 135 million) due primarily to impairment of certain receivables associated with cost recovery with respect to local state-owned co-venturers based on underlying petroleum agreements and modifications of the Company’s interest in certain joint ventures.

Trade receivables included guarantees for work in progress for euro 213 million (euro 156 million at December 2007).

Other receivables for euro 227 million associated with cost recovery in the Exploration & Production segment are currently undergoing arbitration procedure. No impairment loss has been recognized as the Company and the third party are in the process of defining a transaction on amicable terms.

Receivables for financing operating activities of euro 487 million (euro 384 million at December 31, 2007) included euro 399 million due from not consolidated subsidiaries, joint ventures and associates (euro 246 million at December 31, 2007) and euro 47 million cash deposit to provide coverage of Eni Insurance Ltd technical reserves (euro 112 million at December 31, 2007). Receivables for financing non-operating activities amounted to euro 337 million (euro 990 million at December 31, 2007) of which euro 173 million related to the current portion of a restricted deposit held by Eni Lasmo Plc as a guarantee of a debenture and euro 88 million related to deposit of Eni Insurance Ltd. The decrease of euro 653 million related for euro 898 million to the discharge of a collateral cash deposit made by Eni SpA to guarantee certain cash flow hedging derivatives.

Other receivables were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Accounts receivable from:
- joint venture operators in exploration and production		1,699		2,242
- Italian government entities		386		378
- insurance companies		253		146
		2,338		2,766
Prepayments for services		194		857
Receivables relating to factoring operations		182		171
Other receivables		979		1,160
		3,693		4,954

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Receivables deriving from factoring operations of euro 171 million (euro 182 million at December 31, 2007) were related to Serfactoring SpA and consisted primarily of advances for factoring operations with recourse and receivables for factoring operations without recourse.

Receivables with related parties are described in Note 37 - Transactions with related parties.

Because of the short-term maturity of trade receivables, the fair value approximated their carrying amount.

4 Inventories
Inventories were as follows:

		Dec. 31, 2007		Dec. 31, 2008

(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		861		299				809		1,969		466		263				1,155		1,884
Products being processed and semi finished products		74		27				15		116		48		17				3		68
Work in progress						553				553						953				953
Finished products and goods		1,962		703				17		2,682		2,528		557				92		3,177
Advances						179				179
		2,897		1,029		732		841		5,499		3,042		837		953		1,250		6,082

Inventories increased by euro 583 million primarily due to: (i) an increase in the trade value of the inventories in the Gas & Power segment reflecting favorable trends in the gas price formulas (euro 661 million); and (ii) inclusion in consolidation of Distrigas NV (euro 322 million). Those increases were partially offset by a decrease of euro 718 million in the trade value of crude oil and petroleum products inventories in the Refining & Marketing segment primarily due to the impact of falling oil and petroleum product prices resulting in the recognition of a provision to write inventories down to their net realizable value at the year end.

Contract work in progress for euro 953 million (euro 553 million at December 31, 2007) are net of prepayments for euro 274 million (euro 577 million at December 31, 2007) within the limits of contractual considerations.

Inventories are stated net of the valuation allowance of euro 697 million (euro 75 million at December 31, 2007):

(euro million)		Value at Dec. 31, 2007		Additions		Deductions		Other changes		Value at Dec. 31, 2008

75

628

(5

)

(1

)

697

The additions of euro 628 million (euro 9 million in 2007) primarily related to the Refining & Marketing segment (euro 402 million) and to Petrochemicals (euro 215 million) as a consequence of the alignment of the inventories to their net realizable values at the closing date.

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5 Current tax assets
Current tax assets were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Italian subsidiaries		634		53
Foreign subsidiaries		69		117
		703		170

The euro 533 million decrease in the current income tax assets primarily referred to Eni SpA which has used the tax receivables to offset the tax payables for 2008 year (euro 554 million).

6 Other current tax assets
Other current tax assets were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

VAT		376		623
Excise and customs duties		316		167
Other taxes and duties		141		340
		833		1,130

7 Other current assets
Other current assets were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Fair value of non-hedging derivatives		629		1,608
Fair value of cash flow hedge derivatives		10		474
Other assets		441		267
		1,080		2,349

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The fair value of derivative contracts which do not meet the criteria to be classified as hedges under IFRS was as follows:

		Dec. 31, 2007		Dec. 31, 2008

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Interest currency swap		170		821		291		141		403		200
Currency swap		69		1,596		2,881		202		2,654		1,712
Other		3		18		11		314		111		1,202
		242		2,435		3,183		657		3,168		3,114
Non-hedging derivatives on interest rate
Interest rate swap		91		248		3,466		29		217		703
Other										4
		91		248		3,466		29		221		703
Non-hedging derivatives on commodities
Over the counter		12		75		22		864		1,270		2,709
Other		284		2		1,218		58		65		53
		296		77		1,240		922		1,335		2,762
		629		2,760		7,889		1,608		4,724		6,579

Fair value of the derivative contracts is determined using market quotations provided by the primary info-provider, or in the absence of market information, appropriate valuation methods used in the marketplace.

The increase in the fair value of the non-hedging derivatives of euro 979 million referred to the fair value of the derivatives deriving from the consolidation of Distrigas NV after the acquisition of control by the Gas & Power segment (euro 637 million).

Fair value of the cash flow hedges of euro 474 million referred to Distrigas NV (euro 293 million) and to Exploration & Production segment (euro 181 million). The Distrigas NV derivatives were designated to hedge surpluses or deficits of gas to achieve a proper balance in the gas portfolio and sales/purchases of amounts of gas and oil products at fixed price. Fair value related to the Exploration & Production segment referred to the fair value of the future sale agreements of the proved oil reserves with a deadline by 2009. Those derivatives were entered into to hedge exposure to variability in future cash flows deriving from the sale in the 2008-2011 period of approximately 2% of Eni’s proved reserves as of December 31, 2006 corresponding to 125.7 mmBBL, decreasing to 79.7 mmBOE as of the end of December 2008 due to transactions settled in the year. These hedging transactions were undertaken in connection with acquisitions of oil and gas assets in the Gulf of Mexico and Congo that were executed in 2007.

Fair value of contracts expiring by 2009 is given in Note 20 - Other current liabilities; fair value of contracts expiring beyond 2009 is given in Note 15 - Other non-current receivables and in Note 25 - Other non-current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are given in the Note 27 - Shareholders’ equity and in the Note 32 - Finance income (expense).

The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for euro 1,069 million and euro 3,130 million. Information on the hedged risks and the hedging policies is given in Note 29 - Guarantees, commitments and risks.

Other assets amounted to euro 267 million (euro 441 million at December 31, 2007) and included prepayments and accrued income for euro 63 million (euro 297 million at December 31, 2007), rentals for euro 31 million (euro 21 million at December 31, 2007), and insurance premiums for euro 11 million (euro 10 million at December 31, 2007).

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Non-current assets

8 Property, plant and equipment
Analysis of tangible assets is set out below:

(euro million)

Net value at the beginning of the year

Investments

Depreciation

Impairments

Change in the scope of consolidation

Currency translation differences

Other changes

Net value at the end of the year

Gross value at the end of the year

Provisions for amortization and impairments

Dec. 31, 2007
Land		442			4									28						123			597			627			30
Buildings		1,406			74			(98	)		(3	)		115			(3	)		(152	)		1,339			3,123			1,784
Plant and machinery		32,494			1,774			(4,642	)		(37	)		31			(1.530	)		4.885			32,975			78,030			45,055
Industrial and commercial equipment		230			163			(112	)					40			(8	)		38			351			1,434			1,083
Other assets		328			86			(83	)		(3	)		1			(11	)		23			341			1,361			1,020
Tangible assets in progress and advances		6,229			6,263						(97	)		235			(648	)		(666	)		11,316			11,969			653
		41,129			8,364			(4,935	)		(140	)		450			(2,200	)		4,251			46,919			96,544			49,625
Dec. 31, 2008
Land		597			8									(7	)					27			625			655			30
Buildings		1,339			101			(105	)		(29	)		(122	)		7			(341	)		850			3,055			2,205
Plant and machinery		32,975			3,486			(5,648	)		(652	)		1.299			123			4,535			36,118			86,714			50,596
Industrial and commercial equipment		351			180			(158	)		(3	)					1			230			601			1,722			1,121
Other assets		341			124			(83	)		(6	)		(13	)		5			9			377			1,563			1,186
Tangible assets in progress and advances		11,316			8,183						(653	)		2.344			414			(4,342	)		17,262			18,481			1,219
		46,919			12,082			(5,994	)		(1,343	)		3.501			550			118			55,833			112,190			56,357

Capital expenditures of euro 12,082 million (euro 8,364 million at December 31, 2007) primarily related to the Exploration & Production segment (euro 7,611 million), the Engineering & Construction segment (euro 2,015 million), the Gas & Power segment (euro 1,318 million) and the Refining & Marketing segment (euro 941 million). Capital expenditures included capitalized finance expenses of euro 236 million (euro 180 million at December 31, 2007) essentially related to the Exploration & Production segment (euro 109 million), the Refining & Marketing segment (euro 44 million) and the Gas & Power segment (euro 42 million). The interest rate used for the capitalization of finance expense ranged from 3.5% to 5.1% (4.4% and 5.2% at December 31, 2007).

The depreciation rates used were as follows:

(%)
Buildings					2		-	10
Plant and machinery					2		-	10
Industrial and commercial equipment					4		-	33
Other assets					6		-	33

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The break-down by segment of impairments amounting to euro 1,343 million (euro 140 at December 31, 2007) and the associated tax effect is provided below:

(euro million)		2007		2008

Impairment
Exploration & Production		86		765
Refining & Marketing		52		292
Petrochemicals				279
Other segments		2		7
		140		1,343
Fiscal effect
Exploration & Production		30		213
Refining & Marketing		19		108
Petrochemicals				88
Other segments				2
		49		411
Impairment net of the relevant fiscal effect
Exploration & Production		56		552
Refining & Marketing		33		184
Petrochemicals				191
Other segments		2		5
		91		932

In assessing whether impairment is required, the carrying value of the asset is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell and value in use. Given the nature of Eni’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are taking place. Consequently the recoverable amount used in assessing the impairment charges described below is value in use. Value in use is calculated by discounting the estimated cash flows determined on the basis of the best information available at the moment of the assessment deriving from: (i) the Company’s four-year plan approved by the top management which provides information on expected oil and gas production, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends in the main monetary variables, including inflation, nominal interest rates and exchange rates. For the subsequent years beyond the plan horizon, a real growth rate ranging from 0% to 2% has been used; (ii) the commodity prices have been assessed based on the forward prices prevailing in the market place 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 for the following years (see "Basis of presentation").

Post-tax cash flows are discounted at the rate which corresponds for the Exploration & Production, Refining & Marketing and Petrochemicals segments to the Company’s weighted average cost of capital, adjusted to consider the risks specific to each country of activity. The post-tax WACC used for impairment purposes has ranged from 8.5% to 12.5%. Post-tax cash flows and discount rates have been adopted as they result in an assessment that is substantially equal to a pre-tax assessment.

In the Exploration & Production segment the main impairments were associated to proved and unproved properties in Turkmenistan, Iran and Gulf of Mexico as a consequence of changes in the regulatory and contractual framework, cost increases, as well as a changed pricing environment.

In the Refining & Marketing segment the main impairments referred to: (i) refining plants due to a worsening pricing environment and specific plant factors (low complexity and high fixed operating costs); and (ii) the motorway retail network of service stations due to a worsening pricing environment, lower forecast volumes, increased motorway royalties and the commitments with the grantor to execute certain capital expenditures that bear no return.

In Petrochemicals the main impairments referred to: (i) aromatic plants of the Sicilian industrial base and of Porto Marghera due to lower expected profitability associated with a worsening margin environment; (ii) styrene plants of Mantova due to the structural drop of the demand by the users of polystyrene; and (iii) polyethylene plants of the Sicilian industrial base due to the low competitiveness of the product, to the drop of the demand and the competitive pressure.

Changes in the consolidation area of euro 3,501 million (euro 450 million at December 31, 2007) referred to the acquisition of control by the Exploration & Production segment of Burren Energy Plc (euro 2,543 million), First

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Petroleums Ltd (euro 757 million), Hindustan Oil Exploration Co (euro 199 million) and Eni Hewett Ltd (euro 118 million), the acquisition of control by the Gas & Power segment of Distrigas NV (euro 30 million) and the sale by Refining & Marketing of Agip España SA (euro 146 million). More information on acquisitions is included in the Note 28 - Other information.

Foreign currency translation differences of euro 550 million were primarily related to translation of entities accounts denominated in U.S. dollar (euro 1,374 million). This effect was partially offset by translation of entities accounts denominated in Norwegian krones (euro 433 million) and British pounds (euro 308 million).

Other changes in the net book value of tangible assets (euro 118 million) referred to the initial recognition and change in the estimated amount of the costs for the dismantling and restoration of sites referring to the Exploration & Production segment (euro 620 million). This effect was partially offset by asset disposals for euro 318 million, of which euro 248 million related to oil and gas assets of the Exploration & Production segment.

The accumulated impairments amounted to euro 3,328 million and euro 4,692 million at December 31, 2007 and 2008, respectively.

At December 31, 2008, Eni pledged property, plant and equipment for euro 27 million primarily as collateral against certain borrowings (euro 52 million at December 31, 2007).

Government grants recorded as a decrease of property, plant and equipment amounted to euro 651 million (euro 682 million at December 31, 2007).

Assets acquired under financial lease agreements amounted to euro 163 million, of which euro 127 million related to a drilling platform by the Engineering & Construction segment, euro 25 million related to FPSO ships used by the Exploration & Production segment to support oil production and treatment activities and euro 11 million related to service stations in the Refining & Marketing segment.

Contractual commitments related to the purchase of property, plant and equipment are included in Note 29 - Guarantees, commitments and risks - Liquidity risk.

Property, plant and equipment under concession arrangements are described in Note 29 - Guarantees, commitments and risks - Assets under concession arrangements.

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Property, plant and equipment by segment

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Property, plant and equipment, gross
Exploration & Production		54,284			66,023
Gas & Power		17,438			18,944
Refining & Marketing		12,421			12,899
Petrochemicals		4,918			5,036
Engineering & Construction		5,823			7,702
Other activities		1,543			1,550
Corporate and financial companies		344			391
Elimination of intra-group profits		(227	)		(355	)
		96,544			112,190
Accumulated depreciation, amortization and impairment losses
Exploration & Production		27,806			32,811
Gas & Power		6,179			6,863
Refining & Marketing		7,926			8,403
Petrochemicals		3,819			4,124
Engineering & Construction		2,310			2,548
Other activities		1,461			1,467
Corporate and financial companies		148			179
Elimination of intra-group profits		(24	)		(38	)
		49,625			56,357
Property, plant and equipment, net
Exploration & Production		26,478			33,212
Gas & Power		11,259			12,081
Refining & Marketing		4,495			4,496
Petrochemicals		1,099			912
Engineering & Construction		3,513			5,154
Other activities		82			83
Corporate and financial companies		196			212
Elimination of intra-group profits		(203	)		(317	)
		46,919			55,833

 

9 Other assets
The carrying amount of the expropriated Dación assets (euro 563 million at December 31, 2007) have been reclassified in the item "Other non-current receivables" following the settlement agreement with the Republic of Venezuela. Under the terms of this agreement, Eni will receive cash compensation, a part of which has been already collected in the year, to be paid in seven yearly installments, yielding interest income from the date of the settlement. The net present value of this cash compensation is in line with the book value of assets, net of the related provisions.

10 Inventory - compulsory stock
Inventory - compulsory stock was as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Crude oil and petroleum products		2,015		1,040
Natural gas		156		156
		2,171		1,196

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Compulsory stock was primarily held by Italian companies (euro 2,008 million and euro 1,184 million at December 31, 2007 and 2008, respectively) in accordance with minimum stock requirements set forth by applicable laws. The decrease of euro 975 million in crude oil and petroleum products is primarily due to the impairment for alignment of the inventories to the net realizable values recognized at year end (euro 724 million).

11 Intangible assets
Intangible assets were as follows:

(euro million)

Net value at the beginning of the year

Investments

Amortization

Changes in the scope of consolidation

Other changes

Net value at the end of the year

Gross value at the end of the year

Provisions for amortization and writedowns

Dec. 31, 2007
Intangible assets with finite useful lives
Exploration expenditures		409			1,682			(1,812	)					470			749			1,509			760
Industrial patents and intellectualproperty rights		112			40			(81	)					77			148			1,179			1,031
Concessions, licenses, trademarksand similar items		856			12			(83	)		1						786			2,449			1,663
Service concession arrangements		3,183			168			(96	)					(37	)		3,218			5,699			2,481
Intangible assets in progressand advances		151			312									(86	)		377			381			4
Other intangible assets		141			15			(24	)		36			(10	)		158			572			414
		4,852			2,229			(2,096	)		37			414			5,436			11,789			6,353
Intangible assets with indefinite useful lives
Goodwill		2,084												31			2,115
		6,936			2,229			(2,096	)		37			445			7,551
Dec. 31, 2008
Intangible assets with finite useful lives
Exploration expenditures		749			1,907			(2,097	)		326			77			962			2,286			1,324
Industrial patents and intellectual property rights		148			44			(85	)					42			149			1,203			1,054
Concessions, licenses, trademarks and similar items		786			17			(93	)		(15	)		38			733			2,475			1,742
Service concession arrangements		3,218			230			(109	)					(17	)		3,322			5,837			2,515
Intangible assets in progressand advances		377			264									(61	)		580			590			10
Other intangible assets		158			18			(52	)		1,600			14			1,738			2,000			262
		5,436			2,480			(2,436	)		1,911			93			7,484			14,391			6,907
Intangible assetswith indefinite useful lives
Goodwill		2,115									1,439			(1	)		3,553
		7,551			2,480			(2,436	)		3,350			92			11,037

Exploration expenditures of euro 962 million related to acquisition costs of unproved reserves other than probable and possible resources included in business combinations and the purchase of mineral rights. Main additions in the year included exploration drilling expenditures which were fully amortized as incurred for euro 1,715 million included within "investments" (euro 1,610 million at December 31, 2007).

Concessions, licenses, trademarks and similar items for euro 733 million primarily comprised transmission rights for natural gas imported from Algeria (euro 482 million) and concessions for mineral exploration (euro 189 million).

Service concession arrangements primarily refer to the Italian gas distribution activity (euro 3,111 million and euro 3,205 million at December 31, 2007 and 2008, respectively). Such activity is conducted on the basis of concessions granted by local public entities. At the expiry date of the concession, compensation is paid, defined by using criteria of business appraisal, to the outgoing operator following the sale of its own gas distribution network. Service tariffs for distribution are defined on the basis of a method established by the Authority for Electricity and Gas. Legislative Decree No. 164/2000 provides the grant of distribution service exclusively by tender, with a

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maximum length of 12 years. Government grants recorded as a decrease of service concession arrangements amounted to euro 657 million (euro 513 million at December 31, 2007).

Other intangible assets with finite useful lives of euro 1,738 million primarily referred to: (i) customer relationship and order backlog for euro 1,355 million recognized after the acquisition of control of Distrigas NV. These assets are amortized on the basis of the supply contract with the longest term (19 years) and the residual useful life of the sale contract (4 years); (ii) the development project of the gas storage capacity recognized after the acquisition of control of Eni Hewett Ltd (euro 208 million); (iii) royalties for the use of licenses by Polimeri Europa SpA (euro 72 million); and (iv) estimated costs for Eni’s social responsibility projects in relation to oil development programs in Val d’Agri (euro 18 million) following commitments made with the Basilicata Region.

The depreciation rates used were as follows:

(%)
Exploration expenditures					10		-	33
Industrial patents and intellectual property rights					20		-	33
Concessions, licenses, trademarks and similar items					7		-	33
Service concession arrangements					2		-	20
Other intangible assets					4		-	25

Changes in the consolidation area related to the intangible assets with a finite useful life of euro 1,911 million primarily related to the acquisition of control by the Gas & Power segment on Distrigas NV for euro 1,395 million (customer relationship for euro 1,216 million, order backlog for euro 165 million and software for euro 14 million), unproved reserves other than probable and possible resources recognized after the acquisition of control by the Exploration & Production segment on Burren Energy Plc for euro 326 million and the development project of the gas storage capacity recognized after the acquisition of control of Eni Hewett Ltd (euro 208 million).

Change in the consolidation area related to the intangible assets with an indefinite useful life (goodwill) of euro 1,439 million primarily refers to the acquisition of control by the Gas & Power segment on Distrigas NV (euro 1,245 million), the acquisition of control by the Exploration & Production segment on Burren Energy Plc (euro 89 million), on First Calgary Petroleums Ltd (euro 88 million) and on Eni Hewett (euro 39 million).

The carrying amount of goodwill at the end of the year was euro 3,553 million (euro 2,115 million at December 31, 2007). The break-down by operating segment is as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Exploration & Production		158		266
Gas & Power		1,125		2,399
Refining & Marketing		86		142
Engineering & Construction		746		746
		2,115		3,553

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 recoverable amount of the CGUs is the higher of: (i) fair value less costs to sell if there is an active market or recent transactions for similar assets within the same industry between knowledgeable and willing parties; and (ii) value-in-use determined by discounting the estimated future cash flows determined on the basis of the best pieces of information available at the moment of the assessment deriving from: (a) the Company’s four-year plan approved by the top management which provides information on expected oil and gas production, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends in the main monetary variables, including inflation, nominal interest rates and exchange rates. For the subsequent years beyond the plan horizon, a real growth rate ranging from 0% to 2% has been used; (b) the commodity prices have been assessed based on the forward prices prevailing in the market place 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 top management for strategic planning purposes for the following years (see Basis of presentation).

Value-in-use is determined by discounting post-tax cash flows at the rate which corresponds: (i) for the Exploration & Production and Refining & Marketing and Petrochemicals segments at the Company’s weighted average cost of capital (post-tax WACC), adjusted to consider risks specific to each country of activity. WACC used for the impairment purposes has ranged from 8.5% to 12.5%; (ii) for the Gas & Power and Engineering

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& Construction segments at their specific WACC. For the Gas & Power segment it has been estimated on the basis of a sample of companies operating in the same segment, for the Engineering & Construction segment on the basis of market data. WACC used for impairments in the Gas & Power segment has been adjusted to take into consideration risks specific to each country of activity, while WACC used for impairments in the Engineering & Construction segment has not been adjusted as most of the company assets are not permanently located in a specific country. WACC used for impairment has ranged from 7.5% to 9% for the Gas & Power segment and it was 8% for the Engineering & Construction segment; and (iii) for the regulated activities in the Italian natural gas sector, the discount rates have been assumed equal to the rates of return defined by the Italian Authority for Electricity and Gas.

Post-tax cash flows and discount rates have been adopted as they result in an assessment that is substantially equal to a pre-tax assessment.

Goodwill has been allocated to the following CGUs:

Gas & Power

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Domestic gas market		743		743
Foreign gas market		67		1,341
- of which Distrigas NV				1,245
Domestic natural gas transportation network		305		305
Other		10		10
		1,125		2,399

Goodwill allocated to the CGU domestic gas market referred primarily to goodwill recognized following the purchase of minorities in Italgas SpA in 2003 through a public offering (euro 706 million). The key assumptions adopted for assessing the recoverable amount of the CGU which exceeds its carrying amount referred to commercial margins, forecast volumes, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers has been collected from the four-year-plan approved by the Company’s top management while the terminal value has been estimated through the perpetuity method of the last-year-plan. The excess of the recoverable amount of the domestic gas market CGU over its carrying amount including the allocated portion of goodwill (headroom) would be reduced to zero under each of the following hypothesis: (i) a decrease of 20% in the projected commercial margins in each of the four years of the plan; (ii) a decrease of 20% in the expected volumes in each of the four years of the plan; (iii) an increase of 1.7 percentage points in the discount rate; and (iv) a negative real growth rate of 2%.

Goodwill allocated to the Distrigas CGU has been recognized following the acquisition of a controlling interest of 57.24% in the Belgian company in October 2008. The allocation is on a preliminary basis. When the price allocation is finalized, goodwill is expected to be allocated to the different CGUs that are expected to benefit from the synergies of the acquisition. At that time, it will be possible to determine any excess of the recoverable amount of the CGUs over their carrying amounts, including any allocated portion of goodwill, and define the hypothesis under which the headroom would be reduced to zero.

Goodwill allocated to the domestic natural gas transportation network CGU referred to the purchase of own shares by Snam Rete Gas SpA and it is equal to the difference between the purchase cost over the carrying amount of the corresponding share of equity. The recoverable amount of the CGU is assessed based on its Regulatory Asset Base (RAB) as recognized by the Italian Authority for Electricity and Gas and it is higher than its carrying amount, including the allocated goodwill. Management believes that no reasonably possible change in the assumptions adopted would cause the headroom of the CGU to be reduced to zero.

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Engineering & Construction
The segment goodwill of euro 746 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA (euro 711 million) and was allocated to the following CGUs:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Offshore constructions		416		416
Onshore constructions		315		314
Other		15		16
		746		746

The key assumptions adopted for assessing the recoverable amount of the CGUs which exceeds the carrying amount referred to operating results, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers has been collected from the four-year-plan approved by the Company’s top management while the terminal value has been estimated by using a perpetual growth rate of 2% applied to an average normalized terminal cash flow.

The following changes in each of the assumptions, all else being equal would cause the headroom of the Offshore construction CGU to be reduced to zero: (i) decrease of 52% of the operating result of the four years of the plan; (ii) increase of 6 percentage points of the discount rate; and (iii) negative real growth rate.

Changes in each of the assumptions, all else being equal that would cause the headroom of the Onshore construction CGU to be reduced to zero are greater than those of the Offshore construction CGU described above. As well, also the headroom for the Offshore and Onshore CGUs calculated by removing the normalization of the terminal cash flows results widely positive.

Other changes in goodwill of euro 1 million referred to impairments of euro 44 million of which euro 38 million primarily referred to Exploration & Production which has impaired the interest in goodwill recognized following the acquisition of Burren Energy Plc (euro 28 million) and of Lasmo Plc (euro 9 million). More information on acquisitions is included in the Note 28 - Other information.

12 Investments

Equity-accounted investments
Equity-accounted investments were as follows:

(euro million)

Value at the beginning of the year

Acquisition and subscriptions

Share of profit of equity-accounted investments

Share of loss of equity-accounted investments

Deduction for dividends

Currency translation differences

Other changes

Value at the end of the year

Dec. 31, 2007
Investments in unconsolidated entities controlled by Eni		144			4			10			(2	)		(9	)		(6	)					141
Joint ventures		2,506			1,109			481			(130	)		(351	)		(173	)		(132	)		3,310
Associates		1,236			813			415			(3	)		(220	)		(42	)		(11	)		2,188
		3,886			1,926			906			(135	)		(580	)		(221	)		(143	)		5,639
Dec. 31, 2008
Investments in unconsolidated entities controlled by Eni		141			41			27			(6	)		(5	)		3			(24	)		177
Joint ventures		3,310			47			536			(94	)		(444	)		(123	)		25			3,257
Associates		2,188			289			198			(5	)		(266	)		35			(402	)		2,037
		5,639			377			761			(105	)		(715	)		(85	)		(401	)		5,471

Acquisitions and subscriptions for euro 377 million related to the subscription of capital increase for euro 345 million, of which euro 254 million related to Angola LNG Ltd.

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Share of profit of equity-accounted investments and the decrease following the distribution of the dividends referred to the following companies:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

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		181		173		50.00		200		185		50.00
United Gas Derivatives Co		79		40		33.33		107		127		33.33
EnBW Eni Verwaltungsgesellschaft mbH		64		42		50.00		40		22		50.00
Trans Austria Gasleitung GmbH		43		28		89.00		39		28		89.00
Supermetanol CA		34		36		34.51		39		34		34.51
Galp Energia SGPS SA		255		126		33.34		39		88		33.34
Other investments		250		135				297		231
		906		580				761		715

The share of loss of equity-accounted investments of euro 105 million primarily related to Enirepsa Gas Ltd (euro 44 million) and Lipardiz - Construção de Estruturas Maritimas Lda (euro 40 million).

Other changes of euro 401 million are due to the exclusion from the equity-accounted investments and the inclusion in the consolidation area of Burren Energy Plc after the acquisition of control by the Exploration & Production segment (euro 592 million), the disposal of Gaztransport et Technigaz SAS (euro 115 million). These effects were partially offset by the inclusion in the equity-accounted investments of Angola LNG Ltd (euro 175 million).

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The following table sets out the net carrying amount relating to equity-accounted:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

		Net carrying amount		Eni’s interest %		Net carrying amount		Eni’s interest %

Investments in unconsolidated entities controlled by Eni:
- Eni Btc Ltd		42		100.00		62		100.00
- other investments (*)		99				115
		141				177
Joint ventures:
- Artic Russia BV		925		60.00		895		60.00
- Unión Fenosa Gas SA		507		50.00		499		50.00
- Blue Stream Pipeline Co BV		298		50.00		351		50.00
- EnBW Eni Verwaltungsgesellschaft mbH		256		50.00		268		50.00
- Azienda Energia e Servizi Torino SpA		162		49.00		166		49.00
- Eteria Parohis Aeriou Thessalonikis AE		154		49.00		158		49.00
- Toscana Energia SpA		133		49.38		136		49.38
- Raffineria di Milazzo ScpA		126		50.00		128		50.00
- Trans Austria Gasleitung GmbH		96		89.00		109		89.00
- Super Octanos CA		90		49.00		90		49.00
- Supermetanol CA		78		34.51		90		34.51
- Unimar Llc		71		50.00		65		50.00
- Eteria Parohis Aeriou Thessalias AE		41		49.00		42		49.00
- Transmediterranean Pipeline Co Ltd		47		50.00		40		50.00
- Transitgas AG		30		46.00		33		46.00
- Altergaz SA		18		27.80		25		38.91
- Lipardiz - Construção de Estruturas Maritimas Lda		88		50.00		10		50.00
- FPSO Mystras - Produção de Petròleo Lda		58		50.00		2		50.00
- other investments (*)		132				150
		3,310				3,257
Associates:
- Galp Energia SGPS SA		911		33.34		862		33.34
- Angola LNG Ltd						453		13.60
- Ceska Rafinerska AS		325		32.44		323		32.44
- United Gas Derivatives Co		140		33.33		128		33.33
- ACAM Gas SpA		45		49.00		46		49.00
- Distribuidora de Gas del Centro SA		33		31.35		32		31.35
- Burren Energy Plc		592		24.90
- other investments (*)		142				193
		2,188				2,037
		5,639				5,471

(*)		Each individual amount included herein did not exceed euro 25 million.

The net carrying amount of investments in not consolidated entities controlled by Eni, joint ventures and associates include the differences between purchase price and Eni’s equity in investments of euro 615 million. Such differences primarily related to Unión Fenosa Gas SA (euro 195 million), EnBW - Eni Verwaltungsgesellschaft mbH (euro 187 million), Galp Energia SGPS SA (euro 106 million) and Ceska Rafinerska AS (euro 97 million).

Artic Russia BV (the former Eni Russia BV) held 100% interest in three Russian companies acquired on April 4, 2007 in partnership with Enel (Eni 60%, Enel 40%), following award of a bid for Lot 2 in the Yukos liquidation procedure. The three companies – OAO Arctic Gas, OAO Urengoil and OAO Neftegaztechnologiya – engage in exploration and development of gas reserves.

Eni and Enel granted to Gazprom a call option to acquire a 51% interest in the three companies to be exercisable by Gazprom within 24 months from the acquisition date. Eni assesses the investment in Artic Russia BV under the equity method as it jointly controls the three entities based on ongoing shareholder arrangements, therefore exercising significant influence in the financial and operating policy decisions of the investees. This 60% interest corresponds to the present ownership interest of Eni in the acquired companies determined by not taking

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into account the possible exercise of the call option by Gazprom. The carrying amount of the three entities is lower than the strike price of the call option with respect to the underlying stake. The strike price equals the bid price adjusted by subtracting dividends received and adding possible share capital increases, a contractual remuneration of 9.4% on the capital employed and additional financing expenses.

The fair value of listed investments was as follows:

		Shares		Ownership (%)		Price per share (euro)		Fair value (euro million)

Galp Energia SGPS SA		276,472,160		33.34		7.18		1,985
Altergaz SA		1,050,892		38.91		9.90		10

The table below sets out the provisions for losses included in the provisions for contingencies of euro 119 million (euro 135 million at December 31, 2007), primarily related to the following equity-accounted investments:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Charville - Consultores e Serviços Lda		31		33
Polimeri Europa Elastomeres France SA (under liquidation)		50		31
Industria Siciliana Acido Fosforico - ISAF - SpA (under liquidation)		28		27
Southern Gas Constructors Ltd		14		17
Other investments		12		11
		135		119

Other investments
Other investments were as follows:

(euro million)

Net value at the beginning of the year

Acquisition and subscriptions

Currency translation differences

Other changes

Net value at the end of the year

Gross value at the end of the year

Accumulated impairment charges

Dec. 31, 2007
Investments in unconsolidated entities controlled by Eni		21			3			(1	)		2			25			36			11
Associates		9									1			10			11			1
Other investments		330			190			(36	)		(47	)		437			443			6
		360			193			(37	)		(44	)		472			490			18
Dec. 31, 2008
Investments in unconsolidated entities controlled by Eni		25			1						4			30			41			11
Associates		10									(6	)		4			28			24
Other investments		437			5			11			(77	)		376			382			6
		472			6			11			(79	)		410			451			41

Investments in not consolidated 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.

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The net carrying amount of other investments of euro 410 million (euro 472 million at December 31, 2007) was related to the following entities:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

		Net carrying amount		Eni’s interest %		Net carrying amount		Eni’s interest %

Investments in unconsolidated entities controlled by Eni (*)		25				30
Associates		10				4
Other investments:
- Interconnector (UK) Ltd		22		5.00		135		16.06
- Nigeria LNG Ltd		80		10.40		85		10.40
- Darwin LNG Pty Ltd		87		10.99		83		10.99
- Angola LNG Ltd		175		13.60
- other (*)		73				73
		437				376
		472				410

(*)		Each individual amount included herein did not exceed euro 25 million.

Provisions for losses related to other investments, included within the provisions for contingencies, amounted to euro 44 million (euro 28 million at December 31, 2007) and were primarily in relation to the following entities:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Caspian Pipeline Consortium R - Closed Joint Stock Co		25		24
Burren Energy Ship Management Ltd (Cyprus)				17
Other investments		3		3
		28		44

Other information about investments
The following table summarizes key financial data, net to Eni, as disclosed in the latest available financial statements of not consolidated entities controlled by Eni, joint ventures and associates:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Not consolidated entities controlled by Eni

Joint ventures

Associates

Not consolidated entities controlled by Eni

Joint ventures

Associates

Total assets		1,247		7,781		4,252		1,361		7,761		4,020
Total liabilities		1,111		4,526		2,061		1,230		4,565		1,958
Net sales from operations		99		4,667		5,134		134		5,303		5,067
Operating profit		14		674		502		2		736		702
Net profit		14		318		410		20		490		690

The total assets and liabilities of not consolidated controlled entities of euro 1,361 million and euro 1,230 million, respectively (euro 1,247 million and euro 1,111 million at December 31, 2007) concerned for euro 923 million and euro 923 million (euro 873 million and euro 873 million at December 31, 2007) entities for which consolidation does not produce significant effects.

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13 Other financial assets
Other financial assets were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Financing receivables:
- receivables for financing operating activities		677		1,084
- receivables for financing non-operating activities		225
		902		1,084
Securities:
- securities held for operating purposes		21		50
		21		50
		923		1,134

Financing receivables are presented net of the allowance for impairment losses of euro 26 million (euro 24 million at December 31, 2007). Operating financing receivables of euro 1,084 million (euro 677 million at December 31, 2007) primarily concerned loans made by the Exploration & Production segment (euro 754 million), Refining & Marketing segment (euro 109 million) and Gas & Power segment (euro 76 million), as well as receivables for financial leasing (euro 128 million). Receivables for financial leasing related to the disposal of the Belgian gas network by Finpipe GIE, company included in the consolidation area after the acquisition of control by the Gas & Power segment of Distrigas NV. 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		Beyond five years		Total

Principal receivable		19		95		33		147
Interests		4		13		2		19
Undiscounted value of future lease payments		23		108		35		166

Receivables with a maturity date within one year are shown in current assets in the item trade receivables for operating purposes – current portion of long-term receivables in the Note 3 - Trade and other receivables.

Non-operating financing receivables of euro 225 million at December 31, 2007 concerning a restricted deposit held by Eni Lasmo Plc as a guarantee of a debenture have been reclassified to current assets in the item financing receivables for non operating purposes in the Note 3 - Trade and other receivables.

Receivables in currencies other than euro amounted to euro 827 million (euro 821 million at December 31, 2007).

Receivables due beyond five years amounted to euro 617 million (euro 509 million at December 31, 2007).

Securities of euro 50 million (euro 21 million at December 31, 2007), designated as held-to-maturity investments, are listed securities, issued by foreign governments (euro 30 million) and by the Italian Government (euro 20 million). The increase of euro 29 million referred to Banque Eni SA.

Securities with a maturity beyond five years amounted to euro 20 million.

The fair value of financing receivables and securities did not differ significantly from their carrying amount. The fair value of financing receivables has been determined based on the present value of expected future cash flows discounted at rates ranging from 1.9% to 3.9% (3.8% and 6.0% at December 31, 2007). The fair value of securities was derived from quoted market prices.

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14 Deferred tax assets
Deferred tax assets were recognized net of deferred tax liabilities able to be offset for euro 3,468 million (euro 3,526 million at December 31, 2007).

(euro million)

Value at Dec. 31, 2007

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2008

1,915

1,778

(767

)

(43

)

29

2,912

Deferred tax assets are described in Note 24 - Deferred tax liabilities.

15 Other non-current receivables
The following table provides an analysis of other non-current receivables:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Tax receivables from:
- Italian tax authorities
. income tax		486		24
. interest on tax credits		325		58
. Value Added Tax (VAT)		42		2
. other		11
		864		84
- foreign tax authorities		30		28
		894		112
Other receivables:
- in relation to disposals		7		780
- other non-current receivables		197		268
		204		1,048
Fair value cash flow hedge derivative instruments				197
Other asset		12		44
		1,110		1,401

The decrease of tax receivables of euro 782 million primarily referred to Eni SpA which obtained the reimbursement of the income tax and of the related interest of euro 746 million.

The other receivables related to disposals amounting to euro 780 million related to: (i) the receivable of euro 501 million recognized after the agreement settled with the Republic of Venezuela according to which Eni will receive a cash compensation for the expropriated Dación assets, for a part already received, to be paid in seven annual installments which yields interest income from the date of the settlement. More information is included in Note 9 - Other assets; and (ii) the receivable of euro 275 million related to the disposal of the interest of 1.71% in the Kashagan project to the local partner kazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea PSA and the Kashagan government, which are effective starting from January 1, 2008.

Fair value of the derivative contracts is determined using market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation methods generally accepted in the marketplace.

Fair value of the cash flow hedge derivatives of euro 197 million referred to Distrigas NV (euro 105 million) and to the Exploration & Production segment (euro 92 million). Further information on cash flow hedge derivatives is given in Note 7 - Other current assets; fair value related to the contracts expiring beyond 2009 is given in Note 25 - Other non-current liabilities; fair value related to the contracts expiring in 2009 is indicated in Note 7 - Other current assets and in Note 20 - Other current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are given in Note 27 - Shareholders’ equity and in Note 32 - Finance income (expense).

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The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for euro 64 million and euro 1,268 million. Information on the hedged risks and the hedging policies is given in Note 29 - Guarantees, commitments and risks.

Current liabilities

16 Short-term debt
Short-term debt was as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Banks		4,070		2,411
Ordinary bonds		3,176		3,663
Other financial institutions		517		285
		7,763		6,359

Short-term debt decreased by euro 1,404 million primarily due to the balance of repayments and new proceeds (euro 1,652 million), partially offset by currency translation differences (euro 193 million) and changes in the consolidation area (euro 48 million) due to the acquisition of Distrigas NV by the Gas & Power segment (euro 76 million) and the disposal of Agip España SA by the Refining & Marketing segment (euro 28 million). Debt comprised commercial paper of euro 3,663 million (euro 3,176 million at December 31, 2007) mainly issued by the financial company Eni Coordination Center SA.

Short-term debt per currency is shown in the table below:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Euro		5,453		3,801
U.S. dollar		1,591		1,332
Other currencies		719		1,226
		7,763		6,359

In 2008, the weighted average interest rate on short-term debt was 4.2% (4.9% in 2007).

At December 31, 2008 Eni had undrawn committed and uncommitted borrowing facilities available of euro 3,313 million and euro 7,696 million, respectively (euro 5,006 million and euro 6,298 million at December 31, 2007). These facilities were under interest rates that reflected market conditions. Charges for unutilized facilities were not significant.

17 Trade and other payables
Trade and other payables were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Trade payables		11,092		12,590
Advances		1,483		2,916
Other payables:
- related to capital expenditures		1,301		1,716
- others		3,240		3,293
		4,541		5,009
		17,116		20,515

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The increase of euro 1,498 million in trade payables was primarily related to the Gas & Power segment (euro 1,417 million), the Engineering & Construction segment (euro 630 million), the Exploration & Production segment (euro 658 million) and was partly offset by a decrease relating to the Refining & Marketing segment (euro 942 million) and the Petrochemical segment (euro 251 million).

Advances of euro 2,916 million (euro 1,483 million at December 31, 2007) were related to advances on contract work in progress for euro 2,516 million (euro 996 million at December 31, 2007) and other advances for euro 400 million (euro 487 million at December 31, 2007).

Advances on contract work in progress were in respect of the Engineering & Construction segment.

Other payables were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Payables due to:
- joint venture operators in exploration and production activities		1,624		2,007
- suppliers in relation to investments		1,015		1,057
- non-financial government entities		397		441
- employees		257		400
- social security entities		226		284
		3,519		4,189
Other payables		1,022		820
		4,541		5,009

Payables to related parties are described in Note 37 - Transactions with related parties.

The fair value of trade and other payables did not differ significantly from their carrying amount considering the short-term maturity of trade payables.

18 Income taxes payable
Income taxes payable were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Italian subsidiaries		247		808
Foreign subsidiaries		1,441		1,141
		1,688		1,949

Income taxes payable by Italian subsidiaries were affected by the fair value valuation of cash flow hedging derivatives (euro 291 million). This effect was recorded in the relevant provision within equity. Further information is provided in Note 7 - Other current assets, Note 15 - Other non-current receivables, Note 20 - Other current liabilities and Note 25 - Other non-current liabilities.

19 Other taxes payable
Other taxes payable were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Excise and customs duties		804		920
Other taxes and duties		579		740
		1,383		1,660

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20 Other current liabilities
Other current liabilities were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Fair value of non-hedging derivatives		412		1,982
Fair value of cash flow hedge derivatives		911		452
Other liabilities		233		1,885
		1,556		4,319

Fair value of non-hedging derivative contracts was as follows:

		Dec. 31, 2007		Dec. 31, 2008

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Currency swap		63		2,096		296		293		1,928		2,479
Interest currency swap		5		140				82		694		100
Other		7		76		1		327		151		1,197
		75		2,312		297		702		2,773		3,776
Non-hedging derivatives on interest rate
Interest rate swap		24		722		401		134		641		3,002
		24		722		401		134		641		3,002
Non-hedging derivatives on commodities
Over the counter		12		49		58		1,090		3,297		388
Other		301		1,187		28		56		66		119
		313		1,236		86		1,146		3,363		507
		412		4,270		784		1,982		6,777		7,285

Fair value of derivative contracts was determined by using market quotations reported by major market data providers, or, if no market information was available, on the basis of valuation models generally accepted in the marketplace.

The increase in the fair value of non-hedging derivatives of euro 1,570 million comprises the inclusion of the derivative contracts held by Distrigas NV which has been included in the consolidation area following the acquisition of control by the Gas & Power segment (euro 873 million).

The fair value of cash flow hedges amounted to euro 452 million (euro 911 million at December 31, 2007) and related to Distrigas NV for euro 415 million and the Exploration & Production segment for euro 37 million (euro 911 million at December 31, 2007). Further information on cash flow hedge derivatives is given in Note 7 - Other current assets. The fair value related to the contracts expiring in 2009 is given in Note 7 - Other current assets, in Note 15 - Other non-current receivables and in Note 25 - Other non-current liabilities. The effects of fair value valuation of cash flow hedging derivatives are given in Note 27 - Shareholders’ equity and in Note 32 - Finance income (expense).

The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for euro 989 million and euro 895 million, respectively (euro 1,399 million and euro 1,977 million at December 31, 2007).

Information on the hedged risks and the hedging policies is given in Note 29 - Guarantees, commitments and risks.

Other liabilities of euro 1,885 million (euro 233 million at December 31, 2007) comprised the put option granted to Publigaz (the Distrigas minority shareholder) to divest its 31.25% stake in Distrigas to Eni for a total amount of euro 1,495 million based on the same per-share price of the ongoing mandatory tender offer to minorities as part of the Distrigas acquisition as provided for the Shareholders Agreement signed by the two partners on July 30, 2008. This liability was recognized against the Group’s net equity. In subsequent periods, changes in the put option value will be recognized against the profit and loss account.

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Non-current liabilities

21 Long-term debt and current portion of long-term debt
Long-term debt included the current portion maturing during the year following the balance sheet date (current maturity). The table below analyzes debt by year of forecasted repayment:

Type of debt instrument		Maturity range		2007		2008		Current maturity 2009		2010		2011		2012		2013		After		Total

Towards banks:
- bank loans		2009-2019		6,073		6,896		145		2,503		600		2,584		324		740		6,751
- other bank loans at favorable rates		2009-2012		9		6		2		2		1		1						4
- other		2009-2010				101				101										101
				6,082		7,003		147		2,606		601		2,585		324		740		6,856
Ordinary bonds		2009-2037		5,386		6,843		360		844		133		40		1,602		3,864		6,483
Other financial institutions		2009-2020		599		632		42		180		63		62		55		230		590
				12,067		14,478		549		3,630		797		2,687		1,981		4,834		13,929

Long-term debt, including the current portion of long-term debt, of euro 14,478 million (euro 12,067 million at December 31, 2007) increased by euro 2,411 million. The increase mainly reflected the balance of payments and new proceeds of euro 2,466 million as well as the change in the consolidation area (euro 286 million) primarily due to the acquisition of First Calgary Petroleums Ltd by the Exploration & Production segment that accounts for euro 229 million.

This increase was offset by the negative impact of foreign currency translation differences and translation differences arising on debt taken on by euro-reporting subsidiaries denominated in foreign currencies which are translated into euro at year-end exchange rates (euro 383 million).

Debt from other financial institutions of euro 632 million included euro 161 million of finance lease transactions. The following table shows principal outstanding by maturity date, which was obtained by summing future lease payments discounted at the effective interest rate, interest and the nominal value of future lease payments:

		Maturity range

(euro million)		Within 12 months		Between one and five years		Beyond five years		Total

Principal debt outstanding		134		22		5		161
Interests		3		5		2		10
Undiscounted value of future lease payments		137		27		7		171

Eni entered into long-term borrowing facilities with the European Investment Bank which were conditioned to the maintenance of certain performance indicators based on Eni’s consolidated financial statements or a rating not inferior to A- (S&P) and A3 (Moody’s). At December 31, 2007 and 2008, the amount of short and long-term debt subject to restrictive covenants was euro 1,429 million and euro 1,323 million, respectively. Furthermore, Saipem SpA entered into certain borrowing facilities for euro 75 million with a number of financial institutions subordinated to the maintenance of certain performance indicators based on the consolidated financial statements of Saipem. Eni and Saipem are in compliance with the covenants contained in their respective financing arrangements.

Bonds of euro 6,843 million consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 6,391 million and other bonds for a total of euro 452 million.

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The following table analyses bonds per issuing entity, maturity date, interest rate and currency as at December 31, 2008:

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		43			1,543		EUR				2013				4.625
Eni SpA		1,250		(5	)		1,245		EUR				2017				4.750
Eni SpA		1,250		2			1,252		EUR				2014				5.875
Eni Coordination Center SA		682		7			689		GBP		2010		2019		4.875		6.125
Eni SpA		500		16			516		EUR				2010				6.125
Eni Coordination Center SA		366		1			367		YEN		2012		2037		1.150		2.810
Eni Coordination Center SA		350		10			360		EUR		2010		2028		2.876		5.441
Eni Coordination Center SA		183		2			185		USD		2013		2015		4.450		4.800
Eni Coordination Center SA		165		4			169		EUR		2009		2015				variable
Eni Coordination Center SA		34					34		CHF				2010				2.043
Eni Coordination Center SA		32		(1	)		31		USD				2013				variable
		6,312		79			6,391
Other bonds
Eni USA Inc		287		3			290		USD				2027				7.300
Eni Lasmo Plc (*)		157		(6	)		151		GBP				2009				10.375
Eni UK Holding Plc		11					11		GBP				2013				variable
		455		(3	)		452
		6,767		76			6,843

(*)		The bond is guaranteed by a restricted cash deposit recorded under non-current financial assets (euro 173 million).

As at December 31, 2008 bonds maturing within 18 months (euro 412 million) were issued by Eni Coordination Center SA for euro 261 million and by Eni Lasmo Plc for euro 151 million. During 2008, Eni SpA, Eni Coordination Center SA and Eni UK Holding Plc issued bonds for euro 1,499 million, euro 302 million and euro 11 million respectively.

The following table shows the currency composition of long-term debt and its current portion, and the related weighted average interest rates on total borrowings.

		Dec. 31, 2007 (euro million)		Average rate (%)		Dec. 31, 2008 (euro million)		Average rate (%)

Euro		9,973		4.4		12,284		4.2
U.S. dollar		900		8.6		912		6.1
British pound		882		6.2		859		6.2
Japanese yen		281		1.9		367		2.0
Other currencies		31		2.0		56		3.8
		12,067				14,478

At December 31, 2008 Eni had undrawn committed long-term borrowing facilities of euro 1,850 million (euro 1,400 million at December 31, 2007). Interest rates on these contracts were at market conditions. Charges for unutilized facilities were not significant.

Fair value of long-term debt, including the current portion of long-term debt amounted to euro 15,247 million (euro 12,390 million at December 31, 2007) and consisted of the following:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Ordinary bonds		5,523		7,505
Banks		6,148		7,056
Other financial institutions		719		686
		12,390		15,247

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Fair value was calculated by discounting the expected future cash flows at rates ranging from 1.4% to 3.9% (3.8% and 6.0% at December 31, 2007).

At December 31, 2008 Eni pledged restricted deposits as collateral against its borrowings for euro 151 million (euro 198 million at December 31, 2007).

Analysis of net borrowings, as defined in the "Item 5 – Operating and Financial Review and Prospects", was as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Current

Non-current

Total

Current

Non-current

Total

A. Cash and cash equivalents		2,114				2,114		1,939				1,939
B. Available-for-sale securities		174				174		185				185
C. Liquidity (A+B)		2,288				2,288		2,124				2,124
D. Financing receivables		990		225		1,215		337				337
E. Short-term debt towards banks		4,070				4,070		2,411				2,411
F. Long-term debt towards banks		161		5,921		6,082		147		6,856		7,003
G. Bonds		263		5,123		5,386		360		6,483		6,843
H. Short-term debt towards related parties		131				131		153				153
I. Long-term debt towards related parties				16		16				9		9
L. Other short-term debt		3,562				3,562		3,795				3,795
M. Other long-term debt		313		270		583		42		581		623
N. Total borrowings (E+F+G+H+I+L+M)		8,500		11,330		19,830		6,908		13,929		20,837
O. Net borrowings (N-C-D)		5,222		11,105		16,327		4,447		13,929		18,376

Available-for-sale securities of euro 185 million (euro 174 million at December 31, 2007) were held for non-operating purposes.

Not included in the calculation above were held-to-maturity and available-for-sale securities held for operating purposes amounting to euro 360 million (euro 280 million at December 31, 2007), of which euro 302 million (euro 256 million at December 31, 2007) were held to provide coverage of technical reserves for Eni’s insurance companies.

Financing receivables of euro 337 million (euro 1,215 million at December 31, 2007) were held for non-operating purposes.

Not included in the calculation above were financing receivables held for operating purposes amounting to euro 487 million (euro 384 million at December 31, 2007), of which euro 399 million (euro 246 million at December 31, 2007) were in respect of securities granted to non-consolidated subsidiaries, joint ventures and associates primarily in relation to the implementation of certain capital projects and a euro 47 million cash deposit to provide coverage of Eni Insurance Ltd technical reserves. At December 31, 2007, non-current financial receivables of euro 225 million were related to a restricted deposit held by Eni Lasmo Plc as a guarantee of a debenture; the financial receivable has been reclassified in the current portion for euro 173 million.

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22 Provisions for contingencies
Provisions for contingencies were as follows:

(euro million)

Value at Dec. 31, 2007

Additions

Changes of estimated expenditures

Accretion discount

Reversal of utilized provisions

Reversal of unutilized provisions

Other changes

Value at Dec. 31, 2008

Provision for site restoration and abandonment		3,974						635			202			(113	)		(8	)		(116	)		4,574
Provision for environmental risks		1,858			369						38			(333	)		(9	)		57			1,980
Provision for legal and other proceedings		716			90						1			(30	)		(35	)		70			812
Loss adjustments and actuarial provisions for Eni’s insurance companies		418			1												(49	)		34			404
Provisions for the supply of goods		187			115						6												308
Provision for taxes		213			39									(3	)		(10	)		21			260
Provision for losses on investments		163			21												(5	)		(16	)		163
Provisions for marketing and promotion initiatives		65			75									(57	)		(2	)					81
Provision for OIL insurance		80			14									(13	)		(8	)		(1	)		72
Provision for restructuring or decommissioning		130																		(114	)		16
Provision for onerous contracts		50												(50	)					4			4
Other (*)		632			418			(2	)		2			(151	)		(73	)		73			899
		8,486			1,142			633			249			(750	)		(199	)		12			9,573

(*)		Each individual amount included herein does not exceed euro 50 million.

The provision for site restoration and abandonment of euro 4,574 million primarily referred to the estimation of future costs relating to decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration (euro 4,494 million). The increase in the provision for the year amounted to euro 635 million and was primarily due to changes in the estimates of future costs made by subsidiaries in the Exploration & Production segment including Eni Norge AS (euro 183 million), Eni UK Ltd (euro 90 million) and Eni Petroleum Co Inc (euro 82 million) with a corresponding entry to fixed assets. Also an amount of euro 202 million was recognized through profit and loss as the accretion charge for the period.

The discount rates adopted ranged from 3.3% to 6.2% (from 4.2% to 6.2% at December 31, 2007). Other changes of euro 116 million related to negative currency translation differences which arose from the translation of financial statements denominated in currencies other than euro (euro 157 million). Offsetting this effect was the acquisition of Eni Hewett Ltd by the Exploration & Production segment (euro 52 million).

The provision for environmental risks of euro 1,980 million primarily related to the estimated future costs of remediation in accordance with existing laws and regulations recognized by Syndial SpA (euro 1,382 million) and the Refining & Marketing segment (euro 454 million). The increase in the provision of euro 369 million was primarily related to Syndial SpA (euro 222 million) and the Refining & Marketing segment (euro 108 million). Specifically, Syndial SpA recognized the estimated cost of the remediation of the divested area of Crotone as the clean-up has become probable and the associated costs can be reliably estimated. The decrease of euro 333 million was related to the reversal of utilized provisions primarily by Syndial SpA (euro 194 million) and the Refining & Marketing segment (euro 93 million). Other changes of euro 57 million included the reclassification from the provision for restructuring or decommissioning made by the Refining & Marketing segment (euro 114 million).

The provision for legal and other proceedings of euro 812 million primarily included charges expected on failure to perform certain contractual obligations and estimated future losses on pending litigation including legal, antitrust and administrative matters. These provisions are stated on the basis of Eni’s best estimate of the expected probable liability and primarily relate to the Gas & Power segment (euro 452 million), Syndial SpA (euro 225 million) and the Petrochemical segment (euro 36 million). Other changes of euro 70 million were essentially related to the change in the consolidation area following the acquisition of Distrigas NV by the Gas & Power segment (euro 68 million).

Loss adjustments and actuarial provisions for Eni’s insurance companies of euro 404 million represented the liabilities accrued for claims on insurance policies underwritten by Eni’s insurance company, Eni Insurance Ltd.

Provisions for the supply of goods for euro 308 million related to Eni SpA and included the estimated costs of the supply contracts.

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The provision for taxes of euro 260 million primarily included charges for unsettled tax claims in connection with uncertain applications of the tax regulation for foreign subsidiaries of the Exploration & Production segment (euro 193 million).

The provision for losses on investments of euro 163 million was made with respect to losses on investments in entities incurred to date where the losses exceeded the carrying amount of the investments.

The provision for marketing and promotional initiatives amounted to euro 81 million and was made in respect of marketing initiatives involving awards and prizes to clients in the Refining & Marketing segment.

The provision for OIL insurance cover of euro 72 million included a mutual insurance provision for future increases in insurance charge as a result of past accidents that will be paid in the next 5 years by Eni for participating in the mutual insurance policy of Oil Insurance Ltd.

The provision for restructuring or decommissioning of unused production facilities of euro 16 million was primarily made for the estimated future costs of site restoration and remediation in connection with divestments and the closing of facilities in the Refining & Marketing segment (euro 10 million). Other changes of euro 114 million related to a reclassification to the provision for environmental risks made by the Refining & Marketing segment.

The provision for onerous contracts of euro 4 million related to contracts for which the termination or execution costs exceed the benefits. The reversal of utilized provisions related to Syndial SpA.

23 Provisions for employee benefits
Provisions for employee benefits were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

TFR		499		458
Foreign pension plans		219		223
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans		99		98
Other benefits		118		168
		935		947

Provisions for indemnities upon termination of employment primarily related to the provisions accrued by Italian companies for employee termination indemnities ("TFR"), determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code.

The indemnity is paid upon retirement as a lump sum payment the amount of which corresponds to the total of the provisions accrued during the employee’s service period based on payroll costs as revalued until retirement. Following changes in the regime, starting from January 1, 2007, the amount already accrued and the future benefits have been transferred to a pension fund or the treasury fund custodied by the Italian administration for post-retirement benefits (INPS). Companies with less than 50 employees can choose not to adopt the new scheme. Therefore, the allocation of future TFR provisions to pension funds or the INPS treasury fund determines that these amounts will be classified as costs to provide benefits under a defined contribution plan. Past unpaid amounts accrued as at December 31, 2006 for post-retirement indemnities under the Italian TFR regime continue to represent costs to provide benefits under a defined benefit plan and must be assessed based on actuarial assumptions.

Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria and in Germany. Benefits under these plans consisted 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 retirement.

Group companies provide healthcare benefits to retired managers. Liability to these plans and the current cost are limited to the contributions made by the company.

Other benefits primarily related to a deferred cash incentive scheme for managers and certain Jubilee awards. The provision for the deferred cash incentive scheme is assessed based on the likelihood that the company will

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reach planned targets and the employees will reach individual performance goals. Jubilee awards are benefits due following the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration.

The 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

2007
Current value of benefit liabilities and plan assets at beginning of year		614			771			(440	)		91			95			1,131
Current cost		13			13						1			38			65
Interest cost		23			32						4			2			61
Expected return on plan assets								(23	)								(23	)
Employee contributions								(126	)								(126	)
Actuarial gains (losses)		(52	)		3			12			1			(1	)		(37	)
Benefits paid		(64	)		(35	)		18			(6	)		(7	)		(94	)
Amendments		1			2												3
Curtailments and settlements		(62	)		(201	)		201									(62	)
Currency translation differences and other changes		3			36			(4	)		1			(9	)		27
Current value of benefit liabilities and plan assets at end of year		476			621			(362	)		92			118			945
2008
Current value of benefit liabilities and plan assets at beginning of year		476			621			(362	)		92			118			945
Current cost					21						1			48			70
Interest cost		25			28						5			5			63
Expected return on plan assets								(25	)								(25	)
Employee contributions					(1	)		(41	)								(42	)
Actuarial gains (losses)		8			(11	)		102			3			3			105
Benefits paid		(65	)		(25	)		20			(7	)		(7	)		(84	)
Curtailments and settlements											(2	)					(2	)
Currency translation differences and other changes		(1	)		169			(147	)		2			1			24
Current value of benefit liabilities and plan assets at end of year		443			802			(453	)		94			168			1,054

The gross liability for foreign employee pension plans of euro 802 million (euro 621 million at December 31, 2007) included the liabilities related to joint ventures operating in exploration and production activities for euro 67 million and euro 77 million at December 31, 2007 and 2008, respectively. A receivable of an amount equivalent to such liability was recorded. Other benefits of euro 168 million (euro 118 million at December 31, 2007) primarily concerned the deferred monetary incentive plan for euro 107 million (euro 69 million at December 31, 2007) and jubilee awards for euro 47 million (euro 40 million at December 31, 2007).

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The reconciliation of benefit obligations to plan assets was as follows:

		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

(euro million)

Dec. 31, 2007

Dec. 31, 2008

Dec. 31, 2007

Dec. 31, 2008

Dec. 31, 2007

Dec. 31, 2008

Dec. 31, 2007

Dec. 31, 2008

Present value of benefit obligations with plan assets						439			610
Present value of plan assets						(362	)		(453	)
Net present value of benefit obligations with plan assets						77			157
Present value of benefit obligations without plan assets		476		443		182			192			92		94		118		168
Actuarial gains (losses) not recognized		23		15		(33	)		(126	)		7		4
Past service cost not recognized						(7	)
Net liabilities recognized in provisions for employee benefits		499		458		219			223			99		98		118		168

Costs charged to the profit and loss account were as follows:

(euro million)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits		Total

2007
Current cost		13			13			1			38			65
Interest cost		23			32			4			2			61
Expected return on plan assets					(23	)								(23	)
Amortization of actuarial gains (losses)		1			3									4
Effect of curtailments and settlements		(83	)		41									(42	)
		(46	)		66			5			40			65
2008
Current cost					19			1			48			70
Interest cost		25			28			5			5			63
Expected return on plan assets					(25	)								(25	)
Amortization of actuarial gains (losses)					1									1
Effect of curtailments and settlements								(2	)					(2	)
		25			25			4			53			107

The main actuarial assumptions used for the valuation of post-retirement benefit obligations at year-end and for the estimate of costs expected for 2009 were as follows:

(%)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

2007
Discount rate		5.4		3.5-13.0		5.5		4.8-5.4
Expected return rate on plan assets				4.0-13.0
Rate of compensation increase		2.7-3.0		2.0-12.0				2.7-4.0
Rate of price inflation		2.0		1.0-10.0		2.0		2.0
2008
Discount rate		6.0		3.5-13.0		6.0		5.2-6.0
Expected return rate on plan assets				4.5-13.0
Rate of compensation increase		2.7-3.0		2.4-13.0				2.7-4.0
Rate of price inflation		2.5		1.3-11.0		2.5		2.5

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With regards to Italian plans, demographic tables prepared by Ragioneria Generale dello Stato (RG48) were used. The expected return rate by plan assets has been determined by reference to quoted prices expressed in regulated markets.

Plan assets consisted of the following:

(%)		Plan assets		Expected return

Securities		6.9		6.6-8.9
Bonds		20.4		2.8-10.0
Real estate		1.8		5.4-15.0
Other		70.9		2.0-13.0
Total		100.0

The effective return on plan assets amounted to a cost of euro 77 million (a profit of euro 11 million at December 31, 2007).

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 the current costs and interest costs		1		(1	)
Impact on net benefit obligation		10		(9	)

The amount expected to be accrued to defined benefit plans for 2009 is euro 32 million.

The analysis of changes in the actuarial valuation of the net liability with respect to prior year deriving from the non-correspondence of actuarial assumptions with actual values recorded at year-end was as follows:

(euro million)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

2007
Impact on net benefit obligation		(8	)		6
Impact on plan assets					3
2008
Impact on net benefit obligation		7			15			3			1
Impact on plan assets					(62	)

24 Deferred tax liabilities
Deferred tax liabilities were recognized net of offsettable deferred tax assets for euro 3,468 million (euro 3,526 million at December 31, 2007).

(euro million)

Value at Dec. 31, 2007

Additions

Deductions

Changes in the scope of consolidation

Currency translation differences

Other changes

Value at Dec. 31, 2008

5,471

952

(2,335

)

1,684

(38

)

8

5,742

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Deferred tax liabilities and deferred tax assets consisted of the following:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Deferred tax liabilities		8,997			9,210
Deferred tax assets available for offset		(3,526	)		(3,468	)
		5,471			5,742
Deferred tax assets not available for offset		(1,915	)		(2,912	)
		3,556			2,830

The most significant temporary differences giving rise to net deferred tax liabilities were as follows:

(euro million)

Value at Dec. 31, 2007

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2008

Deferred tax liabilities:
- accelerated tax depreciation		6,257			212			(895	)		(60	)		(148	)		5,366
- site restoration and abandonment (tangible assets)		539			191			(30	)		(32	)		(14	)		654
- capitalized interest expense		177			10			(15	)					1			173
- application of the weighted average cost method in evaluation of inventories		731			335			(1,070	)					83			79
- other		1,293			204			(325	)		54			1,712			2,938
		8,997			952			(2,335	)		(38	)		1,634			9,210
Deferred tax assets:
- site restoration and abandonment (provisions for contingencies)		(1,363	)		(244	)		17			45			(27	)		(1,572	)
- accruals for impairment losses and provisions for contingencies		(913	)		(701	)		235			3			(21	)		(1,397	)
- depreciation and amortization		(622	)		(278	)		48			(42	)		(16	)		(910	)
- assets revaluation as per Laws No. 342/2000 and No. 448/2001		(788	)					60						(7	)		(735	)
- carry-forward tax losses		(79	)		(10	)		37			1			(6	)		(57	)
- other		(1,676	)		(545	)		370			36			106			(1,709	)
		(5,441	)		(1,778	)		767			43			29			(6,380	)
Net deferred tax liabilities		3,556			(826	)		(1,568	)		5			1,663			2,830

Deferred tax assets are recognized for deductible temporary differences to the extent that is probable that sufficient taxable profit will be available against which part or all of the deductible temporary differences can be utilized. When future taxable profit is no longer deemed to be sufficient to absorb all existing deferred tax assets, any surplus is written off.

Other changes of euro 1,663 million included: (i) changes in the consolidation area for euro 1,456 million following of the acquisition made by the Exploration & Production segment of Burren Energy Plc (euro 733 million), of First Calgary Petroleums Ltd (euro 108 million), of Eni Hewett Ltd (euro 91 million) and of Hindustan Oil Exploration Co Ltd (euro 31 million), the acquisition made by the Gas & Power segment of Distrigas NV (euro 504 million) and the disposal done by the Refining & Marketing segment of Agip España SA (euro 11 million); and (ii) the recognition of the deferred tax effect against equity on the fair value evaluation of derivatives designated as cash flow hedge for euro 76 million. Further information on cash flow hedging derivatives is given in Note 7 - Other current assets, in Note 15 - Other non-current receivables and in Note 25 - Other non-current liabilities.

Italian taxation law allows the carry-forward of tax losses over the five subsequent years. Losses suffered in the first three years of the company’s life can however be, for the most part, carried forward indefinitely. The tax rate applied by the Italian subsidiaries to determine the portion of carry-forwards tax losses to be utilized equaled 33%; 33.73% for foreign entities.

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Carry-forward tax losses of euro 1,024 million can be used in the following periods:

(euro million)		Italian subsidiaries		Foreign subsidiaries

2009		41		7
2010				12
2011				1
2012
2013		6		3
Beyond 2013		3		14
Without limit		38		899
		88		936

Carry-forward tax losses of euro 171 million expected to be offset against future taxable profit and were in respect of Italian subsidiaries for euro 88 million and of foreign subsidiaries for euro 83 million. Deferred tax assets recognized on these losses amounted to euro 29 million and euro 28 million, respectively.

25 Other non-current liabilities
Other non-current liabilities were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Fair value of cash flow hedge derivatives		1,340		499
Current income tax liabilities		215		254
Payables related to capital expenditures		22
Other payables		295		55
Other liabilities		159		1,730
		2,031		2,538

The fair value of derivative contracts was determined by using market quotations reported by major market data providers, or, if no market information was available, on the basis of generally accepted methods for financial valuations.

The fair value of cash flow hedging derivatives amounted to euro 499 million (euro 1,340 million at December 31, 2007) and related to the Exploration & Production segment for euro 264 million (euro 1,340 million at December 31, 2007) and to Distrigas NV (euro 235 million).

Further information on cash flow hedging derivatives is given in Note 7 - Other current assets. The fair value related to the contracts expiring in 2009 is given in Note 7 - Other current assets, in Note 15 - Other non-current receivables and in Note 25 - Other non-current liabilities. The effects of the fair value valuation of cash flow hedging derivatives are given in Note 27 - Shareholders’ equity and in Note 32 - Finance income (expense).

The nominal value of these derivatives referred to purchase and sale commitments for euro 1,878 million and euro 1,832 million, respectively (euro 2,804 million and euro 3,404 million at December 31, 2007).

Information on the hedged risks and the hedging policies is shown in Note 29 - Guarantees, commitments and risks.

The group’s liability for current income taxes of euro 254 million (euro 215 million at December 31, 2007) was due as special tax (with a rate lower than the statutory tax rate), relating to the option to increase the deductible tax bases of certain tangible and other assets to their carrying amounts as permitted by the 2008 Budget Law.

Other liabilities of euro 1,730 million (euro 159 million at December 31, 2007) included advances received by Suez following the long-term supply of natural gas and electricity of euro 1,552 million.

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26 Assets classified as held for sale and liabilities directly associated with the assets classified as held for sale
Non-current assets held for sale and directly associated liabilities related to the disposal of Fertlizantes Nitrogenados de Oriente, a company specialized in the production of fertilizers.

27 Shareholders’ equity

Minority interest
Minority interest and the attributable profit with reference to certain consolidated subsidiaries related to:

(euro million)		Net profit		Shareholders’ equity

		2007		2008		Dec. 31, 2007		Dec. 31, 2008

Saipem SpA		514		407			1,299		1,560
Distrigas NV				74					1,162
Snam Rete Gas SpA		268		254			865		948
Hindustan Oil Exploration Co Ltd				(1	)				128
Tigàz Tiszàntùli Gàzszolgàltatò Részvénytàrsasàg		1		(11	)		79		65
Others		15		10			196		211
		798		733			2,439		4,074

Eni shareholders’ equity
Eni’s net equity at December 31 was as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Share capital		4,005			4,005
Legal reserve		959			959
Reserve for treasury shares		7,207			7,187
Cumulative foreign currency translation differences		(2,233	)		(969	)
Other reserves		(914	)		(1,140	)
Retained earnings		29,591			34,685
Treasury shares		(5,999	)		(6,757	)
Interim dividend		(2,199	)		(2,359	)
Net profit for the period		10,011			8,825
		40,428			44,436

Share capital
At December 31, 2008 the parent company’s issued share capital consisted of 4,005,358,876 shares (nominal value euro 1 each) fully paid-up (the same amount at December 31, 2007).

On April 29, 2008 Eni’s Shareholders’ Meeting declared a dividend distribution of euro 0.70 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2007 dividend of euro 1.30 per share, of which euro 0.60 per share paid as interim dividend. The balance was paid on May 22, 2008 to shareholders on the register on May 19, 2008.

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.

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Reserve for treasury shares
The reserve for treasury shares represents the reserve restricted to the purchase of own shares in accordance with the decisions of Eni’s Shareholders’ Meetings. The amount of euro 7,187 million (euro 7,207 million at December 31, 2007) included treasury shares purchased. The decrease of euro 20 million primarily concerned the sale and grant of treasury shares to Group managers following stock option and stock grants incentive schemes.

Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

Other reserves
Other reserves of negative amount were euro 1,140 million (at December 31, 2007 other reserves of negative amount were euro 914 million) and included:

•		a reserve of euro 247 million constituted following the sale by Eni SpA of Snamprogetti SpA to Saipem Projects SpA (now Saipem SpA) (same amount at December 31, 2007);
•		a reserve of euro 194 million (euro 181 million at December 31, 2007) deriving from Eni SpA’s equity;
•		a reserve of euro 86 million (at December 31, 2007 a negative for euro 1,342 million) including the related tax, for the valuation at fair value of available-for-sale securities and cash flow hedge derivatives. Further information is given in Note 2 - Other financial assets held for trading or available for sale, Note 7 - Other current assets, Note 20 - Other current liabilities and Note 25 - Other non-current liabilities;
•		a negative reserve of euro 1,495 million related to the put option granted to Publigaz (the Distrigas minority shareholder) to divest its 31.25% stake in Distrigas NV valued at the same per-share price of the ongoing mandatory tender offer to minorities.

The valuation at fair value of securities available for sale and cash flow hedge derivatives, net of the related tax effect, consisted of the following:

Reserve as of December 31, 2006		8			(2	)		6			1						1			9			(2	)		7
Changes of the year 2007											(2,237	)		867			(1,370	)		(2,237	)		867			(1,370	)
Foreign currency translation differences											51			(26	)		25			51			(26	)		25
Amount recognized in the profit and loss account		(6	)		2			(4	)											(6	)		2			(4	)
Reserve as of December 31, 2007		2						2			(2,185	)		841			(1,344	)		(2,183	)		841			(1,342	)
Changes of the year 2008		3			(1	)		2			964			(364	)		600			967			(365	)		602
Changes in the scope of consolidation											(68	)		23			(45	)		(68	)		23			(45	)
Foreign currency translation differences											48			(23	)		25			48			(23	)		25
Amount recognized in the profit and loss account											1,005			(402	)		603			1,005			(402	)		603
Reserve as of December 31, 2008		5			(1	)		4			(236	)		75			(161	)		(231	)		74			(157	)
of which: Eni Group		5			(1	)		4			(128	)		38			(90	)		(123	)		37			(86	)

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The ineffective portion of the change in fair value of cash flow hedging derivatives (time value component) entered into by the Exploration & Production segment consisted of the following:

(euro million)		Value at Dec. 31, 2007		Changes recognized in profit and loss account		Currency translation differences		Value at Dec. 31, 2008

(56

)

7

4

(45

)

Treasury shares purchased
A total of 382,954,240 ordinary shares (348,525,005 at December 31, 2007) with nominal value of euro 1 each, were held in treasury, for a total cost of euro 6,757 million (euro 5,999 million at December 31, 2007). 23,557,425 treasury shares (35,423,925 at December 31, 2007) at a cost of euro 505 million (euro 768 million at December 31, 2007) were available for 2002-2005 and 2006-2008 stock option plans.

The decrease of 11,866,500 shares consisted of the following:

		Stock option		Stock grant		Total

Number of shares at December 31, 2007		34,521,125			902,800			35,423,925
Rights not assigned for the 2006-2008 stock option plan		(9,406,500	)					(9,406,500	)
Rights exercised		(582,100	)		(893,400	)		(1,475,500	)
Rights cancelled		(975,100	)		(9,400	)		(984,500	)
		(10,963,700	)		(902,800	)		(11,866,500	)
Number of shares at December 31, 2008		23,557,425						23,557,425

At December 31, 2008, options outstanding were 23,557,425 shares. Options refer to the 2002 stock plan for 97,000 shares with an exercise price of euro 15.216 per share, to the 2003 stock plan for 231,900 shares with an exercise price of euro 13.743 per share, to the 2004 stock plan for 671,600 shares with an exercise price of euro 16.576 per share, to the 2005 stock plan for 3,756,000 shares with an exercise price of euro 22.512 per share, to the 2006 stock plan for 5,954,250 shares with an weighted average exercise price of euro 23.119 per share, to the 2007 stock plan for 5,492,375 with an weighted average exercise price of euro 27.451 per share and to the 2008 stock plan for 7,354,300 with an weighted average exercise price of euro 22.540 per share.

Information about commitments related to stock grant and stock option plans is included in Note 31 - Operating expenses.

Interim dividend
Interim dividend for the year 2008 amounted of euro 2,359 million corresponding to euro 0.65 per share, as decided by the Board of Directors on September 11, 2008 in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 25, 2008.

Distributable reserves
At December 31, 2008 Eni shareholders’ equity included distributable reserves for euro 39,000 million.

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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)		2007		2008		Dec. 31, 2007		Dec. 31, 2008

As recorded in Eni SpA’s Financial Statements		6,600			6,745			28,926			30,049
Difference between the equity value of individual accounts of consolidated subsidiaries with respect to the corresponding carrying amount in the statutory accounts of the parent company		4,122			4,140			16,320			18,999
Consolidation adjustments:
- difference between cost and underlying value of equity		(1	)		(330	)		1,245			5,161
- elimination of tax adjustments and compliance with accounting policies		649			(1,373	)		(1,235	)		(2,852	)
- elimination of unrealized intercompany profits		(435	)		216			(3,383	)		(3,127	)
- deferred taxes		(97	)		159			711			(15	)
- other adjustments		(29	)		1			283			295
		10,809			9,558			42,867			48,510
Minority interest		(798	)		(733	)		(2,439	)		(4,074	)
As recorded in Consolidated Financial Statements		10,011			8,825			40,428			44,436

 

28 Other information

Acquisitions
Burren Energy Plc
On January 11, 2008, following a non-hostile takeover by means of a cash offer, Eni acquired control over the British oil company Burren Energy Plc (Burren). Burren held producing assets in Turkmenistan and Congo, and exploratory licenses in Egypt, Yemen and India. Total consideration for this transaction of euro 2,358 million, of which euro 14 million related to additional costs directly attributable to the combination, has been allocated to assets and liabilities on a definitive basis.

Hindustan Oil Exploration Co Ltd (HOEC)
On August 5, 2008, following the execution of a mandatory tender offer on a 20% stake of the HOEC share capital, Eni acquired control over the Indian company Hindustan Oil Exploration Co Ltd (HOEC). The mandatory offer was associated with Eni’s acquisition of a 27.18% of HOEC as part of the Burren deal. Total consideration for this transaction of euro 107 million, with the exclusion of the minority interest, has been allocated to assets and liabilities on a preliminary basis because of the significant amount of time required for a more precise valuation.

Distrigas NV
On October 30, 2008, following the acquisition of a 57.243% majority stake from the French company Suez-Tractebel Eni acquired control over the Belgian company Distrigas NV. On December 30, 2008, Eni was granted authorization from the Belgian market authorities to execute a mandatory tender offer to the minorities of Distrigas. The deadline of the offer was March 19, 2009. Total consideration for this transaction of euro 2,751 million, of which euro 12 million related to additional costs directly attributable to the acquisition, with the exclusion of the minority interest, has been allocated to assets and liabilities on a preliminary basis because of the amount of time required for a more precise valuation.

First Calgary Petroleums Ltd
On November 21, 2008, following the acquisition of all of the common shares Eni gained control of First Calgary Petroleums Ltd, a Canadian oil and gas company with exploration and development activities in Algeria. Total consideration for this transaction of euro 605 million, of which euro 5 million related to additional costs directly attributable to the acquisition, has been allocated to assets and liabilities on a preliminary basis because of the amount of time required for a more precise valuation.

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Eni Hewett Ltd
On November 28, 2008, following the finalization of an agreement with the British company Tullow Oil Ltd Eni acquired a 52% stake and the operatorship of fields in the Hewett Unit and relevant facilities in the North Sea, with the aim to upgrade certain depleted fields in the area so as to achieve a gas storage facility. Total consideration for this transaction of euro 224 million has been allocated to assets and liabilities on a preliminary basis because of the amount of time required for a more precise valuation.

(euro million)		Burren Energy Plc		Hindustan Oil Exploration Co Ltd		Distrigas NV		First Calgary Petroleums Ltd		Eni Hewett Ltd

Pre- acquisition

Post- acquisition

Pre- acquisition

Post- acquisition

Pre- acquisition

Post- acquisition

Pre- acquisition

Post- acquisition

Pre- acquisition

Post- acquisition

Current assets		187		187		115		115		3,375		3,375		148		148		56		19
Property, plant and equipment		457		2,543		79		199		30		30		643		757		29		118
Intangible assets		47		326		8				1		1,395								208
Goodwill				89								1,245				88				39
Investments		56		53		1		1		112		112
Other non-current assets		17		17						202		203						9
Assets acquired		764		3,215		203		315		3,720		6,360		791		993		94		384
Current liabilities		62		100		37		37		1,796		1,796		45		45		17		17
Net deferred tax liabilities		36		733		(5	)	31		30		504		15		108				91
Provisions for contingencies		14		24		4		3		80		80		3		6		44		52
Other non-current liabilities						17		17		88		88		229		229
Liabilities acquired		112		857		53		88		1,994		2,468		292		388		61		160
Minority interest						79		120		748		1,141
Eni’s shareholders equity		652		2,358		71		107		978		2,751		499		605		33		224

 

29 Guarantees, commitments and risks

Guarantees
Guarantees were as follows:

		Dec. 31, 2007		Dec. 31, 2008

(euro million)

Unsecured guarantees

Other guarantees

Total

Unsecured guarantees

Other guarantees

Total

Consolidated subsidiaries				6,388		6,388				13,139		13,139
Unconsolidated entities controlled by Eni				150		150				151		151
Joint ventures and associates		5,896		1,099		6,995		6,027		1,075		7,102
Others		12		279		291		8		245		253
		5,908		7,916		13,824		6,035		14,610		20,645

Other guarantees issued on behalf of consolidated subsidiaries of euro 13,139 million (euro 6,388 million at December 31, 2007) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 7,004 million (euro 3,244 million at December 31, 2007), of which euro 5,965 million related to the Engineering & Construction segment (euro 2,351 million at December 31, 2007); (ii) guarantees issued on behalf of Eni Gas & Power Belgium SA for euro 2,739 million related to the Share Purchase Agreement with Suez-Tractebel SA for the acquisition of a 57.24% majority stake in Distrigas NV; (iii) VAT recoverable from tax authorities for euro 1,248 million (euro 1,286 million at December 31, 2007); and (iv) insurance risk for euro 257 million reinsured by Eni (euro 259 million at December 31, 2007). At December 31, 2007 the underlying commitment covered by such guarantees was euro 10,202 million (euro 6,050 million at December 31, 2007).

Other guarantees issued on behalf of unconsolidated subsidiaries of euro 151 million (euro 150 million at December 31, 2007) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for euro 146 million (euro 144 million at December 31, 2007). At December 31, 2008, the underlying commitment covered by such guarantees was euro 79 million (euro 19 million at December 31, 2007).

Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of euro 7,102 million (euro 6,995 million at December 31, 2007) primarily concerned: (i) an unsecured guarantee of euro 6,001 million (euro 5,870 million at December 31, 2007) given by Eni SpA to Treno Alta Velocità - TAV - SpA for the proper and timely completion of a project relating to the Milan-Bologna train link by CEPAV (Consorzio Eni per

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l’Alta Velocità) Uno; consortium members, excluding unconsolidated 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 871 million (euro 824 million at December 31, 2007), of which euro 716 million related to a contract released by Snam SpA (now merged into Eni SpA) on behalf of Blue Stream Pipeline Co BV (Eni 50%) to a consortium of international financial institutions (euro 677 million at December 31, 2007); and (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for euro 107 million (euro 119 million at December 31, 2007). At December 31, 2008, the underlying commitment covered by such guarantees was euro 983 million (euro 1,562 million at December 31, 2007).

Unsecured and other guarantees given on behalf of third parties of euro 253 million (euro 291 million at December 31, 2007) consisted primarily of: (i) guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%) as security against payment commitments of fees in connection with the re-gasification activity for euro 216 million (euro 204 million at December 31, 2007); and (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit for euro 19 million on behalf of minor investments or companies sold (euro 20 million at December 31, 2007).

At December 31, 2008 the underlying commitment covered by such guarantees was euro 232 million (euro 281 million at December 31, 2007).

Commitments and contingencies
Commitments and contingencies were as follows:

(euro million)		Dec. 31, 2007		Dec. 31, 2008

Commitments		200		205
Risks		1,520		1,660
		1,720		1,865

Other commitments of euro 205 million (euro 200 million at December 31, 2007) were essentially related to a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 180 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 177 million at December 31, 2007).

Risks of euro 1,660 million (euro 1,520 million at December 31, 2007) primarily concerned potential risks associated with the value of assets of third parties under the custody of Eni for euro 1,273 million (euro 1,126 million at December 31, 2007) and contractual assurances given to acquirers of certain investments and businesses of Eni for euro 387 million (euro 376 million at December 31, 2007).

Risk factors
FOREWORD
The main risks that the Company is facing and actively monitoring and managing are the following: (i) the market risk deriving from exposure to fluctuations in interest rates, foreign currency exchange rates and commodity prices; (ii) the credit risk deriving from the possible default of a counterparty; (iii) the liquidity risk deriving from the risk that suitable sources of funding for the Group’s operations may not be available; (iv) the country risk in the upstream business; (v) the operational risk; (vi) the possible evolution of the Italian gas market; and (vii) the specific risks deriving from exploration and production activities.

Financial risks are managed in respect of guidelines defined by the parent company, targeting to align and coordinate Group companies’ policies on financial 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 conducting finance, treasury and risk management operations based on three separate entities: the parent company’s (Eni SpA) finance department, Eni Coordination Center and Banque Eni which is subject to certain bank regulatory

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restrictions preventing the Group’s exposure to concentrations of credit risk. Additionally, in 2007, Eni Trading & Shipping was established and has the mandate to manage and monitor solely commodity derivative contracts. In particular Eni SpA and Eni Coordination Center manage subsidiaries’ financing requirements in and outside of Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative financial contracts are managed by the parent company as well as the activity of trading certificates according to the European Union Emission Trading Scheme. The commodity risk is managed by each business unit with Eni Trading & Shipping ensuring the negotiation of hedging derivatives. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to changes in exchange rates and interest rates and to manage exposure to commodity prices fluctuations. Eni does not enter into derivative transactions on a speculative basis. 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 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 departments define maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates, pooling Group companies risk positions. Eni’s calculation and measurement techniques for interest rate and foreign currency exchange rate risks are in accordance with established 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’s Group companies minimize such kinds of market risks. With regard to the commodity risk, Eni’s policies and guidelines define rules to manage this risk aiming at the optimization of core activities and the pursuing of preset targets of industrial margins. The maximum tolerable level of risk exposure is pre-defined in terms of value at risk in connection with trading and commercial activities, while the strategic risk exposure to commodity prices fluctuations – i.e. the impact on the Group’s business results deriving from changes in commodity prices – is monitored in terms of value-at risk, albeit not hedged in a systematic way. Accordingly, Eni evaluates the opportunity to mitigate its commodity risk exposure by entering into hedging transactions in view of certain acquisition deals of oil and gas reserves as part of the Group’s strategy to achieve its growth targets or ordinary asset portfolio management. The Group controls commodity risk with a maximum value-at-risk limit awarded to each business unit. Hedging needs from business units are pooled by Eni Trading & Shipping which also manages its own risk exposure. 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 in 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 transaction 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 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 (translation risk). 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 economic and transactional exposures arising from foreign currency movements. Eni does not undertake any hedging activity for risks deriving from 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 departments which match opposite positions within Group companies, 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 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 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 the Group’s 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.

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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 the first half of 2008 (compared with full year 2007) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section.

(Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

	2007		2008

(euro million)

High

Low

Avg

At year end

High

Low

Avg

At year end

Interest rate		7.36		0.47		1.39		4.35		12.31		0.73		4.17		6.54
Exchange rate		1.25		0.03		0.21		0.43		1.48		0.09		0.48		0.47

(Value at risk - historic simulation method; holding period: 1 day; confidence level: 95%)

	2007		2008

(U.S. $ million)

High

Low

Avg

At year end

High

Low

Avg

At year end

Area oil, products		44.59		4.39		20.17		12.68		46.48		3.44		19.88		5.43
Area Gas & Power (*)		54.11		20.12		34.56		25.57		67.04		24.38		43.53		32.07

(*)		Amounts relating to the Gas & Power business also include results of Distrigas NV for the months of November and December 2008 based on the closing date of acquisition.

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 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. The monitoring activity of credit risk exposure is performed at the Group level according to set guidelines and measurement techniques that establish counterparty limits and systems to monitor exposure against limits and report regularly on those exposures. Specifically, credit risk exposure to multi-business clients and exposures higher than the limit set at euro 4 million are closely monitored. Monitoring activities do not include retail clients and public administrations. The assessment methodology assigns a score to individual clients based on publicly available financial data and capital, profitability and liquidity ratios. Based on those scores, an internal credit rating is assigned to each counterparty that is accordingly allocated to its proper risk category. The Group risk categories are comparable to those prepared by the main rating agencies on the marketplace. The Group’s internal ratings are also benchmarked against ratings prepared by a specialized external source.

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

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Company’s Board of Directors taking into accounts the credit ratings provided by the primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance departments, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions. Those are the sole Group entities entitled to be party to financial transactions due to the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty 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. Counterparties have been also selected on more stringent criteria particularly in transactions on derivatives instruments and with maturity longer than a three-month period. Eni has not experienced material non-performance by any counterparty. As of December 31, 2007 and 2008, Eni had no significant concentrations of credit risk.

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 the 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 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 above mentioned actions aimed at ensuring availability of suitable sources of funding to fulfill short-term commitments and due obligations also preserving the necessary financial flexibility to support the Group’s development plans. In doing so, the Group has pursued an efficient balance of finance debt in terms of maturity and composition leveraging on the structure of its lines of credit particularly the committed ones.

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.

As of December 31, 2008, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 11,099 million, of which euro 3,313 million were committed, and long-term committed unused borrowing facilities of euro 1,850 million.

These facilities were under interest rates that reflected market conditions. Fees charged for unused facilities were not significant. Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 10 billion, of which euro 6,391 million were drawn as of the balance sheet date.

The Group has debt ratings of AA- and A-1+ respectively for the long and short-term debt assigned by Standard & Poor’s and Aa2 and P-1 assigned by Moody’s; the outlook is stable for both.

The tables below summarize the Group main contractual obligations for finance debt repayments, including expected payments for interest charges, and trade and other payables maturities.

Finance debt

		Maturity year

(euro million)		2009		2010		2011		2012		2013		2014 and thereafter		Total

Non current debt		549		3,630		797		2,687		1,981		4,834		14,478
Current financial liabilities		6,359		-		-		-		-		-		6,359
		6,908		3,630		797		2,687		1,981		4,834		20,837
Interest on finance debt		502		469		412		383		336		791		2,893

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Trade and other payables

		Maturity year

(euro million)		2009		2010-2013		2014 and thereafter		Total

Trade payables		12,590		-		-		12,590
Advances, other payables		7,925		28		27		7,980
		20,515		28		27		20,570

In addition to finance debt and trade payables presented in the financial statements, 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 are certain arrangements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay clauses whereby the Company obligations consist of off-taking 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.

The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

Expected payments by period under contractual obligations and commercial commitments

		Maturity year

(euro million)		2009		2010		2011		2012		2013		2014 and thereafter		Total

Operating lease obligations (1)		618		1,025		697		468		395		1,084		4,287
Decommissioning liabilities (2)		269		35		61		18		256		8,830		9,469
Environmental liabilities		396		421		284		223		221		443		1,988
Purchase obligations (3)		17,938		13,777		14,326		14,405		14,112		185,415		259,973
Gas
- Natural gas to be purchased in connection with take-or-pay contracts		15,694		13,041		13,574		13,610		13,343		179,067		248,329
- Natural gas to be transported in connection with ship-or-pay contracts		539		537		545		549		528		3,151		5,849
Other take-or-pay and ship-or-pay obligations		139		135		126		111		106		838		1,455
Other purchase obligations (4)		1,566		64		81		135		135		2,359		4,340
Other obligations		8		5		5		5		5		152		180
of which:
- Memorandum of intent relating Val d’Agri		8		5		5		5		5		152		180
		19,229		15,263		15,373		15,119		14,989		195,924		275,897

(1)		Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(2)		Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3)		Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(4)		Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S.

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The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects at December 31, 2008. 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.

		Maturity year

(euro million)		2009		2010		2011		2012		2013 and subsequent years		Total

Committed on major projects		4,938		3,831		2,697		1,837		9,856		23,159
Other committed projects		5,147		4,342		3,186		2,389		9,846		24,910
		10,085		8,173		5,883		4,226		19,702		48,069

Country risk
Substantial portions of Eni’s hydrocarbons reserves are located in countries outside the EU and North America, certain of which may be politically or economically less stable than EU or North American. At December 31, 2007, approximately 70% of Eni’s proved hydrocarbons reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2007, approximately 60% of Eni’s domestic supply of natural gas came from such countries. Developments in the political framework, economic crisis, social unrest can compromise temporarily or permanently Eni’s ability to operate or to economically operate in such countries, and to have access to oil and gas reserves. Further risks related to the activity undertaken in these countries, are represented by: (i) lack of well established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; (ii) unfavorable developments in laws and regulations leading to expropriation of Eni’s titles and mineral assets, changes in unilateral contractual clauses reducing value of Eni’s assets; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases; and (v) civil and social unrest leading to sabotages, acts of violence and incidents. While the occurrence of these events is unpredictable, it is possible that they can have a material adverse impact on Eni’s financial condition and results of operations. Eni periodically monitors political, social and economic risks of approximately 60 countries where it has invested, or, with regard to upstream projects evaluation, where Eni is planning to invest in order to assess returns of single projects based also on the evaluation of each country’s risk profile. Country risk is mitigated in accordance with guidelines on risk management defined in the procedure "Project risk assessment and management". In the most recent years, unfavorable developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America.

Operational risk
Eni’s business activities conducted in and outside of Italy are subject to a broad range of laws and regulations, including specific rules concerning oil and gas activities currently in force in countries in which it operates. In particular, those laws and regulations require the acquisition of a license before exploratory drilling may commence and compliance with health, safety and environment standards. Environmental laws impose restrictions on the types, quantities and concentration of various substances that can be released into the environment and on discharges to surface and subsurface water. In particular Eni is required to follow strict operating practices and standards to protect biodiversity when exploring for, drilling and producing oil and gas in certain ecologically sensitive locations (protected areas). Breach of environmental, health and safety laws exposes employees to criminal and civil liability and in the case of violation of certain rules regarding safety on the workplace also companies can be liable as provided for by a general EU rule on businesses liability due to negligent or willful conduct on part of their employees as adopted in Italy with Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations and expenses and liabilities that Eni may incur in relation to compliance with environmental, health and safety laws and regulations are expected to remain material to the group’s results of operations or financial position in future years. Recently enacted regulation of safety and health of the workplace in Italy will impose a new array of obligations to the Company operations, particularly regarding contractors. New regulation prescribe that a company adopts certified operational and organizational systems whereby the Company can discharge possible liabilities due to a violation of health and security standards on condition that adopted operational systems and processes worked properly and were effective.

Eni has adopted guidelines for assessing and managing health, safety and environmental (HSE) risks, with the objective of protecting Eni’s employees, the populations involved in its activity, contractors and clients, and the environment and being in compliance with local and international rules and regulations. Eni’s guidelines prescribe the adoption of international best practices in setting internal principles, standards and solutions. The ongoing process for identifying, evaluating and managing HSE operations in each phase of the business activity and is performed through the adoption of procedures and effective pollution management systems tailored on the

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peculiarities of each business and industrial site and on steady enhancement of plants and process. Additionally, coding activities and procedures on operating phases allow reduce the human component in the plant risk management. Operating emergencies that may have an adverse impact on the assets, people and the environment are managed by the business units for each site. These units manage the HSE risk through a systematic way that involves having emergency response plans in place with a number of corrective actions to be taken that minimize damage in the event of an incident. In the case of major crisis, Divisions/Entities are assisted by the Eni Unit of Crises to deal with the emergency through a team which has the necessary training and skills to coordinate in a timely and efficient manner resources and facilities.

The integrated management system of health, safety and environmental matters is supported by the adoption of Eni’s Model of HSE operations in all the Divisions and companies of Eni Group. This is a procedure based on an annual cycle of planning, implementation, control, review of results and definition of new objectives. The model is directed towards the prevention of risks, the systematic monitoring and control of HSE performance, in a continuous improvement cycle, also subject to audits by internal and independent experts. Major refining and petrochemical facilities of Eni are certified to international environmental standards, such as ISO14001, OHSAS 18001 and EMAS. Eni provides a program of specific training and development for HSE staff in order to:
(i) promote the execution of behaviors consistent with guidelines;
(ii) drive people’s learning growth process by developing professionalism, management and corporate culture;
(iii) support management knowledge and control of HSE risks.

Possible evolution of the Italian gas market
Legislative Decree No. 164/2000 opened the Italian natural gas market to competition, impacting on Eni’s activities, as the company is engaged in all the phases of the natural gas chain. The opening to competition was achieved through the enactment of certain antitrust thresholds on volumes input into the national transport network and on volumes sold to final customers. These enabled new competitors to enter the Italian gas market, resulting in declining selling margins on gas. Other material aspects regarding the Italian gas sector regulation are the regulated access to natural gas infrastructure (transport backbones, storage fields, distribution networks and LNG terminals), the Code adopted by the Authority for Electricity and Gas on the issue of unbundling which forbids a controlling entity from interfering in the decision-making process of its subsidiaries running gas transport and distribution infrastructures and the circumstance that the Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing and in establishing tariffs for the use of natural gas infrastructures. Particularly, 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 supply of natural gas to residential and commercial users consuming less than 200,000 CM/y (qualified as non eligible customers at December 31, 2002 as defined by Legislative Decree No. 164/2000) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the cost of fuels onto final consumers of natural gas. As a matter of fact, following a complex and lengthy administrative procedure started in 2004 and finalized in March 2007 with Resolution No. 79/2007, the Authority finally established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 CM/y, establishing, among other things: (i) that an increase in the international price of Brent crude oil is only partially transferred to residential and commercial users of natural gas in case international prices of Brent crude oil exceed the 35 dollars per barrel threshold; and (ii) that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account of this new indexation mechanism.

Also certain provisions of law may limit the Company ability to set commercial margins. Specifically, Law Decree No. 112 enacted in June 2008 forbids energy companies like Eni to pass to prices to final customers higher income taxes incurred in connection with a supplemental tax rate of 5.5 percentage points introduced by the same decree on energy companies with a yearly turnover in excess of euro 25 million. The Authority for Electricity and Gas is in charge of monitoring compliance with the rule. The Authority has subsequently established with a set of deliberations that energy companies have to adopt effective operational and monitoring systems certified by the Company CEO in order to prevent unlawful increases of final prices of gas.

In order to meet the medium and long-term demand for natural gas, in particular in the Italian market, Eni entered into long-term purchase contracts with producing countries. These contracts which contain take-or-pay clauses will ensure total supply volumes of approximately 62.4 BCM/y of natural gas to Eni by 2010 (excluding take-or-pay volumes coming from Distrigas acquisition which will destined to supply the Belgian market). Despite the fact that an increasing portion of natural gas volumes purchased under said contracts is planned to be marketed outside Italy, management believes that in the long-term unfavorable trends in the Italian demand and supply for natural gas, also taking into account the start-up of new import capacity to the Italian market by Eni and third parties

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as well as implementation of all publicly announced plans for the construction of new import infrastructures (backbone upgrading and new LNG terminals), and developments within the Italian regulatory framework, represent risk factors for the ability of the Company to meet its contractual obligations in connection with its take-or-pay supply contracts. Particularly, should natural gas demand in Italy grow at a lower pace than management expectations, also in view of the expected build-up of natural gas supplies to the Italian market, the Company could face a further increase in competitive pressure on the Italian gas market resulting in a negative impact on its selling margins, taking account of Eni’s gas availability under take-or-pay supply contracts and risks in executing its expansion plans to grow sales volumes in European markets.

Specific 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 expenditure and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil or natural gas fields. Exploratory activity involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. 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 commerciality, sanctioning a development project and building and commissioning relating facilities.

As a consequence, rates of return of such long lead-time projects are exposed to the volatility of oil and gas prices and the risk of an increase in developing and lifting costs, resulting in lower rates of return. This set of circumstances is particularly important to those projects intended to develop reserves located in deep water and harsh environments, where the majority of Eni’s planned and ongoing projects is located.

Managing sources of funds
Eni management makes use of the leverage as a financial measure to assess the soundness and efficiency of the Group balance sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards. Leverage is a measure of the company’s level of indebtedness, calculated as the ratio between net borrowings and shareholders’ equity, including minority interests. In the medium-term, management plans to target a level of leverage up to 0.4 which is intended to provide an efficient capital structure and the appropriate level of financial flexibility.

 

 

 

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Other information about financial instruments
The carrying amount of financial instruments and relevant economic effect for the year 2008 consisted of the following:

		Finance income (expense) recognized in

(euro million)		Carrying amount		Profit and loss account		Equity

Held-for-trading financial instruments
Non-hedging derivatives (a)		(374	)		(558	)
Held-to-maturity financial instruments
Securities		50			2			3
Available-for-sale financial instruments
Securities (a)		495			19
Receivables and payables and other assets/liabilities valued at amortized cost
Trade and receivables and other (b)		22,446			(254	)
Financing receivables (a)		1,908			117
Trade payables and other (c)		20,570			(53	)
Financing payables (a)		20,837			(607	)
Assets at fair value through profit or loss (fair value option)
Investments (a)		2,741			241
Net liabilities for hedging derivatives (d)		280			1,012			964

(a)		Gains or losses were recognized in the profit and loss account within "Finance income (expense)".
(b)		In the profit and loss account, impairments and losses on receivables were recognized within "Purchase, services and other" for euro 385 million whilst negative exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were recognized within "Finance income (expense)" for euro 100 million.
(c)		Positive exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were recognized in the profit and loss account within "Finance income (expense)".
(d)		Gains or losses were recognized in the profit and loss account within "Net sales from operations" and "Purchase, services and other" for euro 1,005 million within "Finance income (expense)" for euro 7 million (time value component).

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

ENI SPA
(i)		Subsidence. The Court of Rovigo conducted investigations concerning a subsidence phenomenon allegedly caused by hydrocarbon exploration and extraction activities in the Ravenna and North Adriatic area both on land and in the sea. Eni appointed an independent and interdisciplinary scientific commission, composed of prominent and highly qualified international experts of subsidence caused by hydrocarbon exploration and extraction activities, with the aim of verifying the magnitude and effects and any actions appropriate to reduce or to neutralize any subsidence phenomenon in the area. This commission produced a study which excludes the possibility of any risk to human health or damage to the environment. The study also states that worldwide there are no instances of accidents of harm to public safety caused by subsidence induced by hydrocarbon production. It also shows that Eni employs the most advanced techniques for monitoring, measuring and controlling the soil. This proceeding is

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in the first level hearing stage. The Veneto Region, other local bodies and two private entities have been acting as plaintiffs. Eni was admitted as a defendant. The Court decided that the proceeding must be heard by the Court of Ravenna.

(ii)		Alleged damage. In 2002, the public prosecutor of Gela commenced a criminal investigation to ascertain alleged damage caused by emissions of the Gela plant, owned by Polimeri Europa SpA, Syndial SpA (formerly EniChem SpA) and Raffineria di Gela SpA. The judge for the preliminary hearing dismissed the accusation of adulteration of food products, while the proceeding for the other allegations regarding pollution and environmental damage remains underway. The trial ended in acquittal with regard to the general manager and officer pro tempore of the refinery. The sentence of the Gela Tribunal stated that the charges were lacking factual basis.
(iii)		Alleged negligent fire in the refinery of Gela. In June 2002, in connection with a fire at the refinery of Gela, a criminal investigation began concerning alleged negligent fire, environmental crimes and crimes against natural beauty. First degree proceedings ended with an acquittal sentence. In November 2007, the public prosecutors of Gela and of Caltanissetta filed an appeal against this decision.
(iv)		Investigation of the quality of ground water in the area of the refinery of Gela. In 2002, the public prosecutor of Gela commenced a criminal investigation concerning the refinery of Gela to ascertain the quality of ground water in the area of the refinery. Eni is charged of having breached environmental rules concerning the pollution of water and soil and of illegal disposal of liquid and solid waste materials. The preliminary hearing phase was closed for one employee who would stand trial, while the preliminary hearing phase is ongoing for other defendants. During the hearings the judge admitted as plaintiffs three environmental associations.
(v)		Alleged negligent fire (Priolo). The public prosecutor of Siracusa commenced an investigation regarding certain Eni managers who were previously in charge of conducting operations at the Priolo refinery (Eni divested this asset in 2002) to ascertain whether they acted with negligence in connection with a fire that occurred at the Priolo plants on April 30 and May 1-2, 2006. After preliminary investigations and based on the outcome of preliminary hearing the public prosecutor requested the opening of a proceeding against the mentioned managers for negligent behavior.
(vi)		Groundwater at the Priolo site. 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 are being investigated who were 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), Syndial and Polimeri Europa. Probes on technical issues are ongoing as required by the Prosecutor.

ENIPOWER SPA

(i)		Alleged unauthorized waste management activities. In 2004, the public prosecutor of Rovigo commenced an investigation for alleged crimes related to unauthorized waste management activities in Loreo relating to the samples of soil used during the construction of the new EniPower power station in Mantova. The prosecutor requested the CEO of EniPower and the managing director of the Mantova plant at the time of the alleged crime to stand trial.
(ii)		Air emissions. The public prosecutor of Mantova commenced an investigation against two managers of the Mantova plant in connection with air emissions by the new power plant.

SYNDIAL SPA

(i)

Porto Torres. In March 2009, the Public Prosecutor of Sassari (Sardinia) resolved to commence a criminal trial against a number of executive officers and managing directors 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. The charge involves environmental damage and poisoning of water and stuff destined to feeding. A preliminary hearing is scheduled in July 2009.

1.2 Civil and administrative proceedings

SYNDIAL SPA (FORMER ENICHEM SPA)

(i)

Alleged pollution caused by the activity of the Mantova plant. In 1992, the Ministry of Environment summoned EniChem SpA (now Syndial SpA) and Edison SpA before the Court of Brescia. The Ministry requested, primarily, environmental remediation for the alleged pollution caused by the activity

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of the Mantova plant from 1976 until 1990, and provisionally, in case there was no possibility to remediate, the payment of environmental damages. Edison agreed on a settlement with the Ministry whereby Edison quantified compensation for environmental damage freeing from any obligation Syndial, which purchased the plant in 1989. Parties are working through a possible settlement of the matter.

(ii)

Summon before the Court of Venice for environmental damages allegedly caused to the lagoon of Venice by the Porto Marghera plants. On December 13, 2002, EniChem SpA (now Syndial SpA), jointly with Ambiente SpA (now merged into Syndial SpA) and European Vinyls Corporation Italia SpA, was summoned before the Court of Venice by the Province of Venice. The province requested compensation for environmental damages that were not quantified, allegedly caused to the lagoon of Venice by the Porto Marghera plants, which were already the subject of two previous criminal proceedings against employees and managers of the defendants. EVC Italia and Ineos presented an action to be indemnified by Eni’s Group companies in case the alleged pollution is proved. The environmental damage has been assessed by an independent consultant who filed his advice to be discussed in a hearing set in October 2009.

(iii)		Claim of environmental damages, allegedly caused by industrial activities in the area of Crotone, commenced by the President of the Regional Council of Calabria. On April 14, 2003, the President of the Regional Council of Calabria, as Delegated Commissioner for Environmental Emergency in the Calabria Region, commenced an action against EniChem SpA (now Syndial SpA) with reference to environmental damages for approximately euro 129 million and damages for euro 250 million (plus interest and compensation) in connection with loss of income and damage to property allegedly caused by industrial activities in the area of Crotone. In addition, the Province of Crotone is acting as plaintiff, claiming damage for euro 300 million. With a decision in May 2007, the Court of Milan declared the invalidity of the power of proxy conferred to the Delegated Commissioner to act on behalf of the Calabria Region with the notice served to Syndial SpA and decided the liquidation of expenses born by the defendant. The Province of Crotone appealed this decision. The second instance court accepted this appeal and Syndial repealed this determination. On October 21, 2004, Syndial was convened before the Court of Milan by the Calabria Region which is seeking to obtain a condemnation of Syndial for a damage payment, should the office of the Delegated Commissioner for Environmental Emergency in the Calabria Region cease during this proceeding. The Calabria Region requested a damage payment amounting to euro 800 million as already requested by the Delegated Commissioner for Environmental Emergency in the Calabria Region in the proceeding commenced in 2003. This new proceeding is in the preliminary investigation stage. This proceeding was unified with the one opened by the Ministry of the Environment. Syndial filed a new project for the environmental remediation of the site to be approved by the Ministry and the body of public administrations and entities involved in the matter that expressed a first partial consent in January 2009. The environmental provision was consequently increased. In 2006, the Council of Ministers, Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the Calabria Region represented by the State Lawyer requested Syndial to appear before the Court of Milan to obtain the ascertainment, quantification and payment of damage (in the form of land, air and water pollution and therefore of the general condition of the population) caused by the operations of Pertusola Sud SpA in the Municipality of Crotone and in surrounding municipalities. The local authorities requested the ascertainment of Syndial’s responsibility as concerns expenses borne and to be borne for the cleanup and reclamation of sites, currently quantified at euro 129 million. This proceeding concerns the same matter and damage claim as the proceedings commenced by the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region against Syndial in 2003 and 2004, respectively.
(iv)		Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore. With a temporarily executive decision dated July 3, 2008 the District Court of Turin sentenced the subsidiary Syndial SpA (former EniChem) to compensate for environmental damages that were allegedly caused when EniChem managed an industrial plant at Pieve Vergonte during the 1990-1996 period. Specifically, the Court sentenced Syndial to pay the Italian Ministry of the Environment compensation 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 ill-founded 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. As no development of the proceeding has occurred since the filing of the Court’s decision, management has confirmed its stance of making no provision for this proceeding in accordance with accounting principles. Syndial will appeal against the ruling on Pieve Vergonte site of the District Court of Turin as soon as possible. Another administrative proceeding is ongoing regarding a ministerial decree enacted by the Italian Ministry for the Environment. The decree provides that Syndial executes the following tasks: (i) the upgrading of a

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hydraulic barrier to protect the site; and (ii) the design of a project for the environmental remediation of Lake Maggiore. The Administrative Court of Piemonte rejected Syndial’s opposition against the outlined environmental measures requested by the Ministry of the Environment. However, the Court judged the prescriptions of the Ministry regarding the remediation of the site to be plain findings of an environmental enquiry to ascertain the state of the lake. Syndial has filed an appeal against the decision of the Court before an upper degree body, also requesting suspension of the effectiveness of the decision. The appeal has been put on hold considering that a plan to ascertain the environmental status of the site is going to be approved by all interested parties, including the Ministry and local municipalities.

(v)

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 certain environmental damage which cannot be cleaned up as well as further damages of various types (e.g. damage to the natural beauty of this site). 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 of 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. Syndial summoned Rumianca SpA, Sir Finanziaria SpA and Sogemo SpA, who ran the plant in previous years, in order to be guaranteed. A report produced by an independent expert appointed by the judge was filed with the Court. The findings of this report quantify the residual environmental damage at euro 15 million. With a sentence of March 2008, the Court of Genova rejected all claims made by the Municipality of Carrara and the Ministry of environment. Both plaintiffs filed an appeal against this decision in June 2008, requesting to all defendants cumulative damage amounting to euro 189.9 million. Syndial filed in the appeal hearing, disputing the plaintiffs’ claims.

(vi)

Ministry for the Environment Augusta harbor. The Italian Ministry for the Environment with various administrative acts ordered 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 Polimeri Europa and Syndial. 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. Polimeri Europa opposed said administrative actions, objecting in particular to the way in which remediation works have been designed and information on concentration of pollutants has been gathered. The Regional Administrative Court of Catania with its decision of July 2007 annulled the decision made by the Service Conference of the Ministry of the Environment concerning Priolo and the Augusta harbor. The Ministry and the municipalities of Augusta and Melilli filed a claim with an Administrative Court of the Sicily Region which accepted the claim. In January 2008 the Regional Court of Catania accepted two further claims on this matter, remitting to the European Union Court of Justice the correct application of the debated community principle on the matter of environmental responsibility. In June 2008 the Ministry for the Environment and the Municipalities of Melilli and Augusta filed and appeal against the decision of the Regional Court of Catania with the Administrative Justice Council. Syndial challenged the administrative acts of December 20, 2007 and March 6, 2008, also requesting the Court of Justice of the EU to decide on the correct application of the debated community principle. A review of the issue made by an independent consultant has been filed showing evidence supporting the thesis of the plaintiffs. The proceedings are still pending before the Administrative Court of Lazio.

ENI SPA
(i)		Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe. On March 2009 Eni was 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 its subsidiary Sofid 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.

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2. Other judicial or arbitration proceedings
SYNDIAL SPA (FORMER ENICHEM SPA)
(i)			Serfactoring: disposal of receivables. In 1991, Agrifactoring SpA commenced proceedings against Serfactoring SpA, a company 49% owned by Sofid SpA and which is controlled by Eni SpA. The claim relates to an amount receivable of euro 182 million for fertilizer sales (plus interest and compensation for inflation), originally owed by Federconsorzi to EniChem Agricoltura SpA (later Agricoltura SpA - in liquidation), and Terni Industrie Chimiche SpA (merged into Agricoltura SpA - in liquidation), that has been merged into EniChem SpA (now Syndial SpA). Such receivables were transferred by Agricoltura and Terni Industrie Chimiche to Serfactoring, which appointed Agrifactoring as its agent to collect payments. Agrifactoring guaranteed to pay the amount of such receivables to Serfactoring, regardless of whether or not it received payment on the due date. Following payment by Agrifactoring to Serfactoring, Agrifactoring was placed in liquidation and the liquidator of Agrifactoring commenced proceedings in 1991 against Serfactoring to recover such payments (equal to euro 182 million) made to Serfactoring based on the claim that the foregoing guarantee became invalid when Federconsorzi was itself placed in liquidation. Agricoltura and Terni Industrie Chimiche brought counterclaims against Agrifactoring (in liquidation) for damages amounting to euro 97 million relating to acts carried out by Agrifactoring SpA as agent. The amount of these counterclaims has subsequently been reduced to euro 46 million following partial payment of the original receivables by the liquidator of Federconsorzi and various setoffs. These proceedings, which have all been joined, were decided with a partial judgment, deposited on February 24, 2004; the request of Agrifactoring has been rejected and the company has been ordered to pay the sum requested by Serfactoring and damages in favor of Agricoltura, to be determined following the decision. A final verdict on this issue is pending. Agrifactoring appealed this partial decision, requesting in particular the annulment of the first step judgment, the reimbursement of euro 180 million from Serfactoring along with the rejection of all its claims and the payment of all proceeding expenses. On June 2008, the trial was decided with a partial judgment that, reforming the previous judgment of the Court of Rome, granted the requests of Agrifactoring and condemned Serfactoring to reimburse to Agrifactoring in liquidation the amount of the receivables due from Federconsorzi and not collected as Federconsorzi went bankrupt. The Court resolved to appoint an independent accounting consultant to quantify the amount paid by Agrifactoring to Serfactoring and amounts paid by Federconsorzi to Agrifactoring. The hearing has been rescheduled to February 2010 in order to allow the Court to review the independent accounting consultant’s advice. Syndial and Serfactoring have appealed the sentence with the Supreme Court of Appeal. Agrifactoring has presented a counter-recourse. Eni accrued a provision with respect to this proceeding.

ENI SPA
(i)			Fintermica. Fintermica presented a claim against Eni concerning the management of the Jacorossi joint venture with reference to an alleged abuse of key roles played by Eni SpA in the joint venture, thus damaging the other partner’s interest and the alleged dilatory behavior of Syndial in selling its interest in the joint venture to Fintermica. The parties decided to commence arbitration on the matter. The examining phase is ongoing and an independent assessment of this matter is being executed. The Board of Arbitrators issued a decision on November 26, 2008 condemning Eni and Syndial to compensate Fintermica for the damages suffered amounting to euro 5 million including monetary revaluation and accrued interest as of April 3, 2001.

SNAMPROGETTI SPA
(i)		CEPAV Uno and CEPAV Due. Eni holds interests in the CEPAV Uno (50.36%) and CEPAV Due (52%) consortia that in 1991 signed two contracts with TAV SpA for the construction of two railway tracks for high speed/high capacity trains from Milan to Bologna (under construction) and from Milan to Verona (in the design phase). With regard to the project for the construction of the line from Milan to Bologna, an Addendum to the contract between CEPAV Uno and TAV was signed on June 27, 2003, redefining certain terms and conditions of the contract. Subsequently, the CEPAV Uno consortium requested a time extension for the completion of works and a claim amounting to euro 800 million. CEPAV Uno and TAV failed to solve this dispute amicably. CEPAV Uno opened an arbitration procedure as provided for under terms of the contract on April 27, 2006. With regard to the project for the construction of a high-speed railway from Milan to Verona, in December 2004, CEPAV Due presented the final project, prepared in accordance with Law No. 443/2001 on the basis of the preliminary project approved by an Italian governmental authority (CIPE). As concerns the arbitration procedure requested by CEPAV Due against TAV for the recognition of costs incurred by the Consortium in the 1991-2000 ten-year period plus suffered damage, in January 2007, the arbitration committee determined the Consortium’s right to recover the costs incurred in connection with the design activities performed. A technical independent survey is underway to assess the amount of compensation

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		to be awarded to the Consortium as requested by the arbitration committee. TAV appealed the arbitration committee’s determination. In April 2007, the Consortium filed with the second instance court of Rome an appeal against Law Decree No. 7 of December 31, 2007, that revoked the concessions awarded to TAV resulting in the annulment of arrangements signed between TAV and the Consortium to build the high-speed railway section from Milan to Verona. The European Court of Justice was requested to judge on this matter. In the meantime, TAV decided to not request the reimbursement of advances paid to the Consortium. Subsequently, Law 133/2008 re-established the concessions awarded to TAV resulting in the continuation of the arrangements between the consortium CEPAV Due and a new entity in charge of managing the Italian railway system.
3. Antitrust, EU Proceedings, Actions of the Authority for Electricity and Gas and of Other Regulatory Authorities
3.1 Antitrust
ENI SpA
(i)		Abuse of dominant position of Snam alleged by the Italian Antitrust Authority. In March 1999, the Italian Antitrust Authority concluded its investigation started in 1997 and: (i) found that Snam SpA (merged in Eni SpA in 2002) abused its dominant position in the market for the transportation and primary distribution of natural gas relating to the transportation and distribution tariffs applied to third parties and the access of third parties to infrastructure; (ii) fined Snam for euro 2 million; and (iii) ordered a review of the practices relating to such abuses. Snam believes it has complied with existing legislation and appealed the decision with the Regional Administrative Court of Lazio requesting its suspension. On May 26, 1999, stating that these decisions are against Law No. 9/1991 and the European Directive 98/30/EC, this Court granted the suspension of the decision. The Authority did not appeal this decision. The decision on the merit of this dispute is still pending before the same Administrative Court.

(ii)		Formal assessment commenced by the Commission of the European Communities for the evaluation of alleged participation to activities limiting competition in the field of paraffin. On April 28, 2005, the Commission of the European Communities commenced a formal assessment to evaluate the alleged participation of Eni and its subsidiaries in activities limiting competition in the field of paraffin. The alleged violation of competition is for: (i) the determination of and increase in prices; (ii) the subdivision of customers; and (iii) exchange of trade secrets, such as production capacity and sales volumes. After, the Commission requested information on Eni’s activities in the field of paraffin and certain documentation acquired by the Commission during an inspection. Eni filed the requested information. On October 2008, the Commission of the European Communities issued the final decision on the matter condemning Eni to the payment of a sanction amounting to euro 29,120,000. Eni has filed for recourse against this decision that is fully covered by the accrued risk provision.
(iii)		Ascertainment by the European Commission of the level of competition in the European natural gas market. As part of its activities to ascertain the level of competition in the European natural gas market, with Decision No. C (2006)1920/1 of May 5, 2006, the European Commission informed Eni that the Group companies were subject to an inquiry under Article 20, paragraph 4 of the European Regulation No. 1/2003 of the Council in order to verify the possible existence of any business conducts breaching European rules in terms of competition and intended to prevent access to the Italian natural gas wholesale market and to subdivide the market among few operators in the activity of supply and transport of natural gas. Similar actions have been performed by the Commission also against the main operators in natural gas in Germany, France, Austria and Belgium. In April 2007, the European Commission made public its decision to start a further stage of inquiry, as the elements collected supported its suspicion that Eni adopted behaviors leading to "capacity hoarding and strategic, in its view, underinvestment in the transmission system leading to the foreclosure of competitors and harm for competition and customers in one or more supply markets in Italy". On March 9, 2009 Eni received a Statement of Objections related to a proceeding under Article No. 82 of the EU Treaty and Article No. 54 of the SEE agreement with reference to an alleged unjustifiable refusal of access to the TAG and TENP/Transitgas gas pipelines, that are interconnected with the Italian gas transport system through actions intended to "capacity hoarding, capacity degradation and strategic limitation of investment" with the effect of "hindering the development of a real competition in the downstream market and [...] harming the consumers". The European Commission envisages the possible imposition of a fine and of structural remedies. The Company is currently assessing the reasoning underlying the Commission’s objections in order to ascertain whether the challenged actions are supported by evidence and may be qualified as infringement of the European competition rules. The Company will file its defensive memories within the proceeding. In addition, and following the aforementioned assessment, the Company may consider whether to voluntarily file a set of remedies to settle the proceeding as provided

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by Article No. 9 of the European Regulation No. 1/2003. Taking into account the numerous elements to be considered in determining the amount of the fine, the complex checks to carry out with respect to the Statement of Objections, and also the circumstance that the Commission’s approval of the possible remedies, presented by Eni pursuant to European Regulation No. 1/2003, would settle the matter without imposing a fine, management believes that the liability is contingent upon the future events described and cannot be measured with reasonable reliability.

(iv)

TTPC. In April 2006, Eni filed a claim before the Regional Administrative Court of Lazio against the decision of the Italian Antitrust Authority of February 15, 2006 stating that Eni’s behavior pertaining to implementations of plans for the upgrading of the TTPC pipeline for importing natural gas from Algeria represented an abuse of dominant position under Article 82 of the European Treaty and fined Eni. The initial fine amounted to euro 390 million and was reduced to euro 290 million in consideration of Eni’s commitment to perform actions favoring competition including the upgrade of the gasline. Eni accrued a provision with respect to this proceeding. With a decision filed on November 29, 2006, the Regional Administrative Court of Lazio partially accepted Eni’s claim, annulling such part of the Authority’s decision where the fine was quantified. Eni is waiting for the filing of the motivations of the Court decision to ascertain the impact of said decision. Pending this development, the payment of the fine has been voluntarily suspended. In 2007, the Regional Administrative Court of Lazio accepted in part Eni’s claim and cancelled the quantification of the fine based on the Antitrust Authority’s inadequate evaluation of the circumstances presented by Eni. Eni filed an appeal with the Council of State, as did the Antitrust Authority and TTPC. Pending the final outcome, Eni awaits for the determination of the amount of the fine to be paid.

(v)		Italian natural gas market. On May 7, 2009, the Italian Antitrust Authority started a preliminary investigation against the Company and its fully-owned subsidiary Italgas and other operators engaging in the gas retail market in Italy. The investigation targets an alleged abuse of dominant position in the gas retail market in Italy associated with commercial practices intended to make it difficult for retail clients to change the supplier and the retrieval of data on volumes.
POLIMERI EUROPA SPA AND SYNDIAL SPA
(i)		Inquiries in relation to alleged anti-competitive agreements in the area of elastomers. In December 2002, inquiries were commenced concerning alleged anti-competitive agreements in the field of elastomers. These inquiries were commenced concurrently by European and U.S. authorities. At present, proceedings are pending before the European Commission regarding the CR and NBR products. In March 2007, the Commission sent to Eni, Polimeri Europa and Syndial a statement of objections, thus opening the second phase of this proceeding. In December 2007, the European Commission dismissed Syndial’s position on CR and imposed on Eni and Polimeri a fine amounting to euro 132.16 million. The two companies have filed an appeal with the EU Court of First Instance against this decision and, at the same time, paid the fine in March 2008. Investigations relating to other elastomers products resulted in the ascertainment of Eni having infringed European competition laws in the field of synthetic rubber production (BR and ESBR). On November 29, 2006, the Commission fined Eni and its subsidiary Polimeri Europa 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 Commission filed a counter appeal. Pending the outcome, Polimeri Europa presented a bank guarantee for euro 200 million and paid the residual amount of the fine. In August 2007, 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 manufacturers. With regard to NBR, an inquiry is underway also in the U.S., where class actions have also been commenced. On the federal level, the class action was abandoned by the plaintiffs. However, the federal judge has yet to acknowledge this abandonment. With regard to other products under investigation in the U.S., settlements were reached with both relevant U.S. antitrust authorities and the plaintiffs acting through a class action. Eni recorded a provision for these matters.

 

3.2 Regulation

TOSCANA ENERGIA CLIENTI SPA
Eni’s subsidiary Toscana Energia Clienti SpA started an action against a customer regarding alleged lack of measurement of gas consumption due to inability to access a measurement facility at the customer’s site, also in connection with the application of Resolution No. 229/2001 of the Italian Authority for Electricity and Gas. This customer has annual consumption in excess of 5,000 CM. The defendant has filed a counter-claim in relation to this proceeding. In the hearing of November 12, 2008 the judge resolved to partially accept the Eni’s subsidiary reasons and to limit compensation to be paid to the defendant to only euro 1,475 with interests amounting to euro 90. The sum was paid while the defendant is evaluating the opportunity to appeal the sentence.

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DISTRIBUIDORA DE GAS CUYANA SA
(i)		Formal investigation of the agency entrusted with the regulations for the natural gas market in Argentina. Enargas started a formal investigation on some operators, among them Distribuidora de Gas Cuyana SA, a company controlled by Eni. Enargas stated that the company improperly applied conversion factors to volumes of natural gas invoiced to customers and requested the company to apply the conversion factors imposed by local regulations from the date of the default notification (March 31, 2004) without prejudice to any damage payment and fines that may be decided after closing the investigation. In April 2004 the company filed a defensive memorandum. On April 28, 2006, the company formally requested the acquisition of documents from Enargas in order to have access to the documents on which the allegations are based.

 

4. Tax Proceedings

ENI SPA
Dispute for the omitted payment of the municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. With a formal assessment presented by the Municipality of Pineto (Teramo) in December 1999, Eni SpA has been accused of not having paid 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 in front of the coast of Pineto. Eni was requested to pay a total of approximately euro 17 million including interest and a fine. Eni filed a claim against this request stating that the sea where the platforms are located is not part of the municipal territory and the tax application as requested by the municipality lacked objective fundamentals. The claim has been accepted in the first two degrees of judgment at the Provincial and Regional Tax Commissions. However, the 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 nominated a Board of Consultants, in order to make all the accounting/technical verifications necessary for the judgment. On December 28, 2005, the Municipality of Pineto presented the same request for the same platforms for the years 1999 to 2004. The total amount requested from Eni is euro 24 million including interest and penalties. Eni filed a claim against this request which was accepted by the first degree judge with a decision of December 4, 2007. Similar formal assessments related to Eni oil and gas offshore platforms were presented by the Municipalities of Falconara Marittima and Pedaso. The total amounts of those claims were approximately euro 6 million. The company filed appeal or is planning to appeal.

AGIP KARACHAGANAK BV
Claims concerning unpaid taxes and relevant payment of interest and penalties. In July 2004, relevant Kazakh Authorities informed Agip Karachaganak BV and Agip Karachaganak Petroleum Operating Co BV, shareholder and operator of the Karachaganak contract, respectively, on the final outcome of 2000 to 2003 tax audits. Both companies counterclaimed against the assessment and a preliminary agreement was reached on November 18, 2004. Final assessments have now been issued by the Kazakh Authorities, and payment has been made. The final amount assessed and paid was $39 million net to Eni; this figure included taxes and interest. The companies continue to dispute the assessments and reserve the right to challenge their findings further.

 

5. Court Inquiries

(i)

EniPower. 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 (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 its meeting of August 10, 2004, Eni’s Board of Directors examined the aforementioned situation and Eni’s CEO approved the creation of a task force in charge of verifying the compliance with Group procedures regarding the terms and conditions for the signing of supply contracts by EniPower and Snamprogetti and the subsequent execution of works. The Board also

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advised divisions and departments of Eni to cooperate fully in every respect with the Court. From the inquiries performed, no default in the organization emerged, nor deficiency in internal control systems. External experts have performed inquiries with regard to certain specific aspects. In accordance with its transparency and firmness guidelines, Eni will take 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.

(ii)		Trading. An investigation is pending regarding two former Eni managers who were allegedly bribed by third parties to favor the closing of 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 preliminary hearings rejected most of the dismissal request, forcing the public prosecutor to continue with the criminal case.
(iii)		TSKJ Consortium Investigations of the SEC and other Authorities. The U.S. Securities and Exchange Commission (SEC), the U.S. Department of Justice (DoJ), and other authorities are investigating alleged improper payments made by the TSKJ Consortium to certain Nigerian public officials in relation to the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti Netherlands BV had a 25% participation in the TSKJ companies, with the remaining participations held by subsidiaries of Halliburton/KBR, Technip, and JGC. 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 resulting from the investigations into the TSKJ matter. In February 2009, KBR and its former parent company, Halliburton, announced that they had reached a settlement with the SEC and DoJ with respect to the TSKJ matter as well as other unspecified matters. In connection with the settlement, KBR pleaded guilty to Foreign Corrupt Practices Act (FCPA) charges stemming from the TSKJ matter. KBR and Halliburton also agreed to pay a substantial fine and entered into civil settlements with the SEC. We understand that the DoJ and the SEC believe that representatives of the other members of the TSKJ Consortium were involved in the conduct that gave rise to the FCPA charges against KBR. Since June 2004, Eni and Saipem/Snamprogetti have been in discussions with, and have provided information in response to requests by, various regulators, including the SEC, the DoJ and the Public Prosecutor’s office of Milan, in connection with the investigations.

(iv)		Gas Metering. On May 28, 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 Courts 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, interalia, 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. The Group companies are cooperating with the Supervising Authorities in the investigations.
(v)		Agip KCO NV. In November 2007, the public prosecutor of Kazakhstan informed Agip KCO of the start of an inquiry for an alleged fraud in the award of a contract to the Overseas International Constructors GmbH in 2005.

 

6. Settled Proceedings

ENI SPA
Inquiry of the Italian Authority for Electricity and Gas regarding information to clients about the right to pay amounts due for natural gas sales in installments. With Decision No. 228/2007, the Italian Authority for Electricity and Gas commenced a formal inquiry regarding information to clients about the right to pay amounts due

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for the natural gas sales in installments in order to possibly put a stop to the alleged infringement of the clients’ rights and to impose a fine. In April 2008, the Authority concluded its inquiry and fined the Company by euro 3.2 million.

SYNDIAL SPA (FORMER ENICHEM SPA)
Criminal action commenced by the public prosecutor of Brindisi. In 2000, the public prosecutor of Brindisi commenced a criminal action against 68 persons who are employees or former employees of companies that owned and managed plants for the manufacture of dichloroethane, vinyl chloride monomer and vinyl polychloride from the early 1960s to date, some of which were managed by EniChem from 1983 to 1993. At the end of the preliminary investigation the public prosecutor asked for the dismissal of the case in respect of the employees and the managers of EniChem. Plaintiffs presented oppositions, but the prosecutor confirmed the request to dismiss the case with a decision of June 2008, the public prosecutor dismissed the accusation as unfounded and requested the closing of the proceeding.

AGIP KCO NV
In December 2007 the Kazakh tax authority filed a notice of tax assessment for fiscal years 2004 to 2006 to Agip KCO, operator of the Kashagan contract. Allegedly unpaid taxes, including interest and penalties, amounted to approximately U.S. $235 million net to Eni and related to unpaid amounts and inapplicable deductions on value added tax and the default in applying certain withholding taxes on payments to foreign suppliers. The same notice also informed the companies party to the Kashagan contract that further assessments were pending on non-deductible costs for U.S. $188 million net Eni and higher taxable income on Kazakh branches for U.S. $48 million net to Eni. The further assessments were subsequently issued, the company filed an appeal and a settlement was reached in October 2008 with the following outcome: the unpaid taxes net to Eni were agreed at U.S. $24 million (U.S. $235 million assessed). An adjustment to deductible costs was agreed at U.S. $38 million net to Eni (U.S. $188 million assessed) and it was further agreed that there would be no income taxable on Kazakh branches (U.S. $48 million assessed).

Other risks and commitments
Parent company guarantees amounted to euro 11,110 million (euro 4,911 million at December 31, 2006) were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities, quantified on the basis of the capital expenditures to be incurred. The increase of euro 6,199 million primarily related to commitments that Agip Caspian Sea BV in Kazakhstan had entered into for euro 5,605 million.

Under the convention signed on October 15, 1991 by Treno Alta Velocità - TAV SpA and CEPAV (Consorzio Eni per l’Alta Velocità) Due, Eni committed to guarantee the execution of design and construction of the works assigned to the CEPAV Consortium (to which it is party) and guaranteed to TAV the correct and timely execution of all obligations indicated in the convention in a subsequent integration deed and in any further addendum or change or integration to the same. The regulation of CEPAV Due contains the same obligations and guarantees contained in the CEPAV Uno Agreement.

A commitment entered into by Eni USA Gas Marketing Llc on behalf of Cameron LNG for fulfilling certain obligations in connection with a regasification contract signed on August 1, 2005. This commitment is subject to a suspension clause and will come into force when the regasification service starts in a period included between October 1, 2008 and June 30, 2009 for an estimated total consideration of euro 226 million.

A commitment entered into by Eni USA Gas Marketing Llc on behalf of Gulf LNG Energy for the acquisition of unused regasification capacity (5.78 BCM/y) over a twenty-year period (2011-2031) for an estimated total consideration as high as $1,400 million equal to euro 951 million.

A commitment entered into by Eni USA Gas Marketing Llc on behalf of Angola LNG Supply Service for the acquisition of regasified gas at the Pascagoula plant in the United States that will come into force when the regasification service starts in a period included between 2011-2031.

Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain of Eni’s assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were

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operated by Eni. Eni believes such matters will not have a material adverse effect on the Company’s results of operations and liquidity.

Assets under concession arrangements

Eni operates under concession arrangements mainly in the Exploration & Production segment and in some activities of the Gas & Power 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 production and development activities and it is entitled to the productions realized. In Product 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 recover 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). With reference to natural gas storage in Italy, the activity is conducted on the basis of concessions with a duration that does not exceed a twenty year duration and it is granted by the Ministry of Productive Activities to persons that are consistent with legislation requirements and that can demonstrate to be able to conduct a storage program that meets the public interest in accordance with the laws. In the Gas & Power segment the gas distribution activity is primarily conducted on the basis of concessions granted by local public entities. At the expiry date of the concession, compensation is paid, defined by using criteria of business appraisal, to the outgoing operator following the sale of its own gas distribution network. Service tariffs for distribution are defined on the basis of a method established by the Authority for Electricity and Gas. Legislative Decree No. 164/2000 provides the grant of distribution service exclusively by tender, with a maximum length of 12 years.

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.

Environmental regulations

Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the risk section above, under the paragraph "Operational risks". 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 to cover environmental risks 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 Decree No. 471/1999 of the Ministry of 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 of Environment-Mse) published the Resolution 20/2008 defining emission permits for the 2008-2012 period. In particular, Eni was assigned permits corresponding to 127.2 mmtonnes of carbon dioxide (approximately 25 mmtonnes/y) in addition to approximately 7.4 million of permits expected to be assigned with respect to new plants in the five-year period 2008-2012. Emissions of carbon dioxide from Eni’s plants were lower than permits assigned in 2008. Emission permits for 25.9

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million tonnes were assigned, against emissions of carbon dioxide of approximately 25.3 million tonnes, resulting in a surplus of 0.6 million tonnes.

30 Revenues
The following is a summary of the main components of "Revenues". For more information about changes in revenues, see "Item 5 – Operating and Financial Review and Prospects".

Net sales from operations were as follows:

(euro million)		2006		2007		2008

Net sales from operations		85,957		87,103		107,843
Change in contract work in progress		148		153		305
		86,105		87,256		108,148

Net sales from operations were net of the following items:

(euro million)		2006		2007		2008

Excise taxes		13,762		13,292		13,142
Exchanges of oil sales (excluding excise taxes)		2,750		2,728		2,694
Services billed to joint venture partners		1,385		1,554		2,081
Sales to service station managers for sales billed to holders of credit cards		1,453		1,480		1,700
Exchanges of other products		127		121		83
		19,477		19,175		19,700

Net sales from operations by business segment and geographic area of destination are presented in Note 36 - Information by industry segment and geographic financial information.

Other income and revenues
Other income and revenues were as follows:

(euro million)		2006		2007		2008

Gains on price adjustments under overlifting/underlifting transactions		30		79		180
Lease and rental income		98		95		98
Gains from sale of assets		100		66		48
Contract penalties and other trade revenues		61		181		23
Compensation for damages		40		87		15
Other proceeds (*)		454		319		356
		783		827		720

(*)		Each individual amount included herein does not exceed euro 50 million.

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31 Operating expenses
The following is a summary of the main components of "Operating expenses". For more information about changes in operating expenses, see "Item 5 – Operating and Financial Review and Prospects".

Purchases, services and other
Purchases, services and other included the following:

(euro million)		2006		2007		2008

Production costs - raw, ancillary and consumable materials and goods		44,661			44,884			58,712
Production costs - services		10,015			10,828			13,355
Operating leases and other		1,903			2,276			2,558
Net provisions for contingencies		767			591			900
Other expenses		1,089			1,095			1,652
		58,435			59,674			77,177
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(783	)		(1,325	)		(645	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(162	)		(170	)		(124	)
		57,490			58,179			76,408

Production costs-services included brokerage fees related to Engineering & Construction segment for euro 155 million (euro 39 million and euro 37 million in 2006 and 2007, respectively).

Costs incurred in connection with research and development activity recognized in profit and loss amounted to euro 216 million (euro 219 million and euro 189 million in 2006 and 2007, respectively) as they do not meet the requirements to be capitalized.

The item "Operating leases and other" included operating leases for euro 957 million (euro 860 million and euro 1,081 million in 2006 and 2007, respectively) and royalties on hydrocarbons extracted for euro 871 million (euro 823 million and euro 772 million in 2006 and 2007, respectively). Future minimum lease payments expected to be paid under non-cancelable operating leases were as follows:

(euro million)		2006		2007		2008

To be paid within 1 year		594		588		618
Between 2 and 5 years		1,474		1,401		2,585
Beyond 5 years		762		942		1,084
		2,830		2,931		4,287

Operating leases primarily concerned 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 Eni to pay dividends, use assets or to take on new borrowings.

Increase of provisions for contingencies net of reversal of unutilized provisions amounted to euro 874 million (euro 767 million and euro 591 million in 2006 and 2007, respectively) and mainly regarded environmental risks for euro 360 million (euro 248 million and euro 327 million in 2006 and 2007, respectively), marketing initiatives awarding prizes to clients for euro 73 million (euro 44 million and euro 59 million in 2006 and 2007, respectively) and legal or other proceedings for euro 55 million (euro 149 million and euro 79 million in 2006 and 2007, respectively). More information is included in Note 22 - Provisions for contingencies.

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Payroll and related costs
Payroll and related costs were as follows:

(euro million)		2006		2007		2008

Wages and salaries		2,630			2,906			3,204
Social security contributions		691			690			694
Cost related to defined benefits plans and defined contributions plans		230			161			107
Other costs		305			275			282
		3,856			4,032			4,287
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(99	)		(109	)		(148	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(107	)		(123	)		(135	)
		3,650			3,800			4,004

Average number of employees
The average number and break-down of employees by category of Eni’s subsidiaries were as follows:

(number)		2006		2007		2008

Senior managers		1,676		1,594		1,621
Junior managers		11,142		11,816		12,597
Employees		34,671		35,725		36,766
Workers		25,426		25,582		26,387
		72,915		74,717		77,371

The average number of employees was calculated as the average between the number of employees at the beginning and end of the period. The average number of senior managers included managers employed and operating in foreign countries, whose position is comparable to a senior manager status.

Stock-based compensation

Stock grant
In 2008 residual rights for stock grant were exercised by managers of Eni SpA and its subsidiaries as defined in Article 2359 of the Civil Code as eligible to this compensation plan. Therefore at the balance sheet date there are not residual rights granted. Changes in the 2006, 2007 and 2008 stock grant plans consisted of the following:

		2006		2007		2008

Number of shares

Market price (a) (euro)

Number of shares

Market price (a) (euro)

Number of shares

Market price (a) (euro)

Stock grants outstanding as of January 1		3,127,200			23.460		1,873,600			25.520		902,800			25.120
New rights granted
Rights exercised in the period		(1,236,400	)		23.933		(966,000	)		24.652		(893,400	)		21.832
Rights cancelled in the period		(17,200	)		23.338		(4,800	)		26.972		(9,400	)		22.683
Stock grants outstanding as of December 31		1,873,600			25.520		902,800			25.120
of which exercisable at December 31		156,700			25.520		68,100			25.120

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Stock option
Stock options plans are designed for managers of Eni SpA and its subsidiaries as defined in Article 2359 of the Civil Code, who are directly responsible for corporate results or for strategic positions, making them participate to an effective incentive plan.

2002-2004 and 2005 plans
Stock options plans provide the right for the assignee to purchase treasury shares with a 1 to 1 ratio after the end of the third year from the date of the grant (vesting period) and for a maximum period of five years. The strike price was determined to be the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the grant date or, from 2003 onwards, the average carrying amount of treasury shares as of the day preceding the assignment, if greater.

2006-2008 plan
The 2006-2008 stock option plan has introduced a performance condition for the exercise of the options. At the end of each three-year period (vesting period) from the assignment, the Board of Directors determines the percentage of exercisable options, from 0 to 100, in relation to the Total Shareholders’ Return (TSR) of Eni’s shares as benchmarked against the TSR delivered by a panel of the six largest international oil companies for market capitalization. Options can be exercised for a maximum period of three years. The strike price is calculated as the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding assignment.

At December 31, 2008, 23,557,425 options were outstanding for the purchase of 23,557,425 ordinary shares. The break-down of outstanding options was the following:

		Rights outstanding as of December 31		Average strike price (euro)

Stock option plan 2002		97,000		15.216
Stock option plan 2003		231,900		13.743
Stock option plan 2004		671,600		16.576
Stock option plan 2005		3,756,000		22.512
Stock option plan 2006		5,954,250		23.119
Stock option plan 2007		5,492,375		27.451
Stock option plan 2008		7,354,300		22.540
		23,557,425

At December 31, 2008 the weighted-average remaining contractual life of the plans at December 2002, 2003, 2004, 2005, 2006, 2007 and 2008 was 1 year and 7 months, 2 years and 7 months, 3 years and 7 months, 4 years and 7 months, 3 years and 7 months, 4 years and 7 months and 5 years and 7 months, respectively.

Changes of stock option plans in 2006, 2007 and 2008 consisted of the following:

		2006		2007		2008

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)

Stock options as of January 1		13,379,600			17.705		23.460		15,290,400			21.022		25.520		17,699,625			23.822		25.120
New rights granted		7,050,000			23.119		23.119		6,128,500			27.451		27.447		7,415,000			22.540		22.538
Rights exercised in the period		(4,943,200	)		15.111		23.511		(3,028,200	)		16.906		25.338		(582,100	)		17.054		24.328
Rights cancelled in the period		(196,000	)		19.119		23.797		(691,075	)		24.346		24.790		(975,100	)		24.931		19.942
Stock options outstanding as of December 31		15,290,400			21.022		25.520		17,699,625			23.822		25.120		23,557,425			23.540		16.556
of which exercisable at December 31		1,622,900			16.190		25.520		2,292,125			18.440		25.120		5,184,250			21.263		16.556

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The fair value of stock options granted during the years 2002, 2003, 2004 and 2005 was euro 5.39, euro 1.50, euro 2.01 and euro 3.33 per share, respectively. For 2006, 2007 and 2008 the weighted average considering options granted was euro 2.89, euro 2.98 and euro 2.60 per share, respectively.

The fair value was determined by applying the following assumptions:

				2002		2003		2004		2005		2006		2007		2008

Risk-free interest rate		(%)		3.5		3.2		3.2		2.5		4.0		4.7		4.9
Expected life		(years)		8		8		8		8		6		6		6
Expected volatility		(%)		43.0		22.0		19.0		21.0		16.8		16.3		19.2
Expected dividends		(%)		4.5		5.4		4.5		4.0		5.3		4.9		6.1

Costs of the year related to stock grant and stock option plans amounted to euro 25 million (euro 20 million and euro 27 million in 2006 and 2007, respectively).

Compensation of key management
Compensation of persons responsible for key positions in planning, direction and control functions of Eni Group, including executive and non-executive officers, general managers and managers with strategic responsibility (key management) amount to euro 23 million, euro 25 million and euro 25 million for 2006, 2007 and 2008 respectively, and consisted of the following:

(euro million)		2006		2007		2008

Wages and salaries		16		17		17
Post-employment benefits		1		1		1
Other long-term benefits		3		3		3
Stock grant/option		3		4		4
		23		25		25

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 8.7 million, euro 8.9 million and euro 6.4 million for 2006, 2007 and 2008, respectively. Compensation of Statutory Auditors amounted to euro 0.686, euro 0.678 million and euro 0.634 million in 2006, 2007 and 2008, respectively. Compensation included emoluments and all other retributive and social security compensations due for the function of directors or statutory auditor assumed by Eni SpA or other companies included in the scope of consolidation, representing a cost for Eni.

Depreciation, depletion, amortization and impairments
Depreciation, depletion, amortization and impairments charges consisted of the following:

(euro million)		2006		2007		2008

Depreciation, depletion and amortization:
- tangible assets		4,694			4,935			5,994
- intangible assets		1,462			2,096			2,436
		6,156			7,031			8,430
Impairments:
- tangible assets		231			140			1,343
- intangible assets		54			67			53
		285			207			1,396
less:
- reversal of impairments - tangible assets		(17	)					(2	)
- reversal of impairment - intangible assets								(1	)
- capitalized direct costs associated with self-constructed assets - tangible assets		(1	)		(1	)		(4	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(2	)		(1	)		(4	)
		6,421			7,236			9,815

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32 Financial income (expense)
Finance income (expense) consisted of the following:

(euro million)		2006		2007		2008

Finance income (expense)
Finance income		3,749			4,445			7,985
Finance expense		(3,971	)		(4,554	)		(8,198	)
		(222	)		(109	)		(213	)
Gain (loss) on derivative financial instruments		383			26			(551	)
		161			(83	)		(764	)

Net finance income (expense) consisted of the following:

(euro million)		2006		2007		2008

Finance income (expense) related to net borrowings
Interest due to banks and other financial institutions		(215	)		(445	)		(745	)
Interest and other finance expense on ordinary bonds		(248	)		(258	)		(248	)
Interest from banks		194			236			87
Interest and other income on financing receivables and securities held for non-operating purposes		62			55			82
		(207	)		(412	)		(824	)
Exchange differences
Positive exchange differences		2,496			2,877			7,339
Negative exchange differences		(2,648	)		(2,928	)		(7,133	)
		(152	)		(51	)		206
Other finance income (expense)
Income from equity instruments					188			241
Capitalized finance expense		116			180			236
Interest and other income on financing receivables and securities held for operating purposes		119			96			62
Interest on tax credits		17			31			37
Finance expense due to passage of time (accretion discount) (a)		(116	)		(186	)		(249	)
Other finance income		1			45			78
		137			354			405
		(222	)		(109	)		(213	)

Income from equity instruments of euro 241 million (euro 188 million in 2007) relating to the contractual remuneration of 9.4% on the 20% interest in OAO Gazprom Neft according to the contractual arrangements between Eni and Gazprom (more information is included in Note 2 - Other financial assets held for trading or available for sale).

The fair value gain (loss) on derivative financial instruments consisted of the following:

(euro million)		2006		2007		2008

Derivatives on exchange rate		313			120			(300	)
Derivatives on interest rate		61			35			(127	)
Derivatives on commodities		9			(129	)		(124	)
		383			26			(551	)

Net loss from derivatives of euro 551 million (euro 383 million and euro 26 million of net gain in 2006 and 2007, respectively) was primarily due to the recognition in the profit and loss account of the change in fair value of derivatives that cannot be qualified as hedging instruments under IFRS. In fact, since these derivatives are entered

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into for amounts corresponding to the net exposure to exchange rate risk, interest rate risk or commodity risk, they cannot be linked to specific trade or financing transactions.

The lack of these formal requirements in order to assess these derivatives as hedging instruments under IFRS provides also the recognition in profit or loss of negative exchange translation differences on assets and liabilities denominated in currencies other than functional currency, as these translation effects cannot be offset by changes in fair value of derivative contracts.

Losses on commodity derivatives amounted to euro 124 million, included gain of euro 7 million related to the ineffective portion of the change in fair value of cash flow hedging derivatives (time value component) entered into by the Exploration & Production segment. Further information is given in Note 7 - Other current asset. The fair value of derivative contracts is provided in Note 7 - Other current asset, Note 15 - Other non-current receivables, Note 20 - Other current liabilities and Note 25 - Other non-current liabilities.

33 Income from investments

Share of profit (loss) of equity-accounted investments
Share of profit (loss) of equity-accounted investments consisted of the following:

(euro million)		2006		2007		2008

Share of profit of equity-accounted investments		887			906			761
Share of loss of equity-accounted investments		(36	)		(135	)		(105	)
Decreases (increases) in the provision for losses on investments		(56	)		2			(16	)
		795			773			640

More information is provided in Note 12 - Investments.

Other gain (loss) from investments
Other gain (loss) from investments consisted of the following:

(euro million)		2006		2007		2008

Gains on disposals		98			170			510
Dividends		25			301			218
Losses on disposals		(7	)		(1	)		(1	)
Other income (expense), net		(8	)					6
		108			470			733

Dividends of euro 510 million primarily related to Nigeria LNG (euro 453 million) and Saudi European Petrochemical Co - Ibn Zahr (euro 34 million).

Gains on disposals of euro 218 million primarily related to the sale of Gaztransport et Technigaz SAS (euro 185 million), Agip España SA (euro 15 million) and Padana Assicurazioni SpA (euro 10 million). Gains on disposals for 2007 of euro 301 million primarily related to the sale of Haldor Topsøe AS (euro 265 million) and Camom SA (euro 25 million). Gains on disposals for 2006 of euro 25 million primarily related to the sale of Fiorentina Gas SpA and Toscana Gas SpA (euro 16 million).

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34 Income taxes
Income taxes consisted of the following:

(euro million)		2006		2007		2008

Current taxes:
- Italian subsidiaries		2,007			2,380			1,916
- foreign subsidiaries of the Exploration & Production segment		6,740			6,695			9,744
- foreign subsidiaries		529			482			426
		9,276			9,557			12,086
Net deferred taxes:
- Italian subsidiaries		230			(582	)		(1,603	)
- foreign subsidiaries of the Exploration & Production segment		1,095			246			(827	)
- foreign subsidiaries		(33	)		(2	)		36
		1,292			(338	)		(2,394	)
		10,568			9,219			9,692

Current income taxes of euro 1,916 million were in respect of Italian subsidiaries for Ires (euro 1,408 million) and Irap (euro 307 million) and of foreign taxes (euro 201 million).

The effective tax rate was 50.3% (51.8% and 46.0% in 2006 and 2007, respectively) compared with a statutory tax rate of 38.2% (37.9% in 2006 and 2007, respectively) and calculated by applying a 33.0%¹⁵ tax rate (Ires) to profit before income taxes and 3.9% tax rate (Irap) 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:

(%)		2006		2007		2008

Statutory tax rate		37.9			37.9			38.2
Items increasing (decreasing) statutory tax rate:
- higher foreign subsidiaries tax rate		13.6			10.2			15.2
- changes in Italian statutory tax rate and adjustment of tax base of amortizable assets for Italian subsidiaries					(2.0	)
- impact pursuant to Law Decree No. 112 of June 25, 2008, the Budget Law 2008 and enactment of a renewed tax framework in Libya								(3.8	)
- permanent differences and other adjustments		0.3			(0.1	)		0.7
		13.9			8.1			12.1
		51.8			46.0			50.3

The increase in the tax rate of foreign subsidiaries primarily related to a 17.1 percentage points increase in the Exploration & Production segment (17.2% and 15% in 2006 and 2007, respectively).

The impact pursuant to Law Decree No. 112 of June 25, 2008, the Budget Law 2008 and enactment of a renewed tax framework in Libya of 3.8% consisted of the following: (i) utilization of deferred tax liabilities recognized on higher carrying amounts of year-end inventories of oil, gas and refined products stated at the weighted-average cost with respect to their tax base according to the last-in-first-out method (LIFO) (euro 528 million). In fact, pursuant to the Law Decree No. 112 of June 25, 2008 (become Law No. 133/2008), energy companies in Italy are required from 2008 to state inventories of hydrocarbons at the weighted-average cost for tax purposes as opposed to the previous LIFO evaluation and to recognize a one-off tax calculated by applying a special tax with a 16% rate on the difference between the two amounts. Accordingly, profit and loss benefited from the difference between utilization of deferred tax liabilities accrued on hydrocarbons inventories and the one-off tax (euro 229 million), for a total positive impact of euro 176 million, which consider previously applicable statutory tax rate (Ires) of 33% pursuant to the Law Decree No. 112 of June 25, 2008 instead of 27.5% of the previous tax regime. This one-off tax will be paid in three annual installments of same amount, due from 2009 onwards; (ii) application of the Italian Budget Law for 2008 that provide an increase in limits whereby carrying amounts of assets and liabilities of consolidated subsidiaries can be recognized for tax purposes by paying a one-off tax calculated by

 

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applying a special rate of 6% (positive impact on profit and loss of euro 370 million; euro 290 million net of the special tax); (iii) enactment of a renewed tax framework in Libya regarding oil companies operating in accordance with production sharing schemes. Based on the new provisions, the tax base of the Company’s Libyan oil properties has been reassessed resulting in the partial utilization of previously accrued tax liabilities of euro 173 million; and (iv) the impact of above mentioned Law Decree No. 112/2008 on energy companies calculated by applying statutory tax rate (Ires) of 33% pursuant to the Law Decree No. 112 of June 25, 2008 instead of the previously applicable statutory tax rate (Ires) of 27.5% (euro 94 million).

In 2006 the increase in the tax rate of foreign subsidiaries relating the Exploration & Production segment included the application of a windfall tax introduced by the Algerian government with effect starting from August 1, 2006 (1.6 percentage points) and a supplemental tax rate introduced by the government of the United kingdom relating to the North Sea productions with effect starting from January 1, 2006 (1 percentage point).

The adjustment to deferred tax assets and liabilities and to the 2007 tax rate for Italian subsidiaries were recognized in connection with certain amendments to the Italian tax regime enacted by the 2008 Budget Law. These included an option regarding the increase of the tax bases of certain tangible and other assets to their carrying amounts (euro 773 million) by paying a special tax (euro 325 million) and a lower statutory tax rate (Ires from 33% to 27.5%, Irap from 4.25% to 3.9%, euro 54 million).

In 2006 permanent differences mainly arose from certain charges that are not deductible because taken in connection with risk provisions arising from proceedings against the Italian Antitrust and other regulatory Authorities (0.4 percentage points).

35 Earnings per share attributable to Eni
Basic earnings per ordinary share are calculated by dividing net profit for the year attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the year, excluding treasury shares.

The average number of ordinary shares used for the calculation of the basic earnings per share outstanding at December 31, 2006, 2007 and 2008, was 3,698,201,896, 3,668,305,807 and 3,638,835,896 respectively.

Diluted earnings per share is calculated by dividing net profit for the year attributable to Eni’s shareholders by the weighted average number of shares fully-diluted which includes issued and outstanding shares during the year, excluding treasury shares and including the number of shares that could be issued potentially in connection with stock-based compensation plans.

The average number of shares fully diluted used in the calculation of diluted earnings was 3,701,262,557, 3,669,172,762 and 3,638,854,276 for the years ending December 31, 2006, 2007 and 2008, respectively.

Reconciliation of the average number of shares used for the calculation for both basic and diluted earning per share was as follows:

		2006		2007		2008

Average number of shares used for the calculation of the basic earnings per share				3,698,201,896		3,668,305,807		3,638,835,896
Number of potential shares following stock grant plans				1,070,676		302,092
Number of potential shares following stock options plans				1,989,985		564,863		18,380
Average number of shares used for the calculation of the diluted earnings per share				3,701,262,557		3,669,172,762		3,638,854,276
Eni’s net profit		(euro million)		9,217		10,011		8,825
Basic earning per share		(euro per share)		2.49		2.73		2.43
Diluted earning per share		(euro per share)		2.49		2.73		2.43

 

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36 Information by industry segment and geographic financial information

Information by industry segment

(euro million)

Exploration & Production

Gas & Power

Refining & Marketing

Petrochemicals

Engineering & Construction

Other activities

Corporate and financial companies

Intra-Group profits

Total

2006
Net sales from operations (a)		27,173			28,368			38,210			6,823			6,979			823			1,174
Less: intersegment sales		(18,445	)		(751	)		(1,300	)		(667	)		(771	)		(520	)		(991	)
Net sales to customers		8,728			27,617			36,910			6,156			6,208			303			183						86,105
Operating profit		15,580			3,802			319			172			505			(622	)		(296	)		(133	)		19,327
Provisions for contingencies		153			197			264			30			(13	)		236			(100	)					767
Depreciation, amortization and writedowns		4,776			738			447			174			196			28			71			(9	)		6,421
Share of profit (loss) of equity-accounted investments		28			509			194			2			66			(4	)								795
Identifiable assets (b)		29,720			23,500			11,359			2,984			6,362			344			1,023			(666	)		74,626
Unallocated assets																										13,686
Equity-accounted investments		258			2,214			874			11			483			46									3,886
Identifiable liabilities (c)		9,119			5,284			4,712			806			3,869			1,940			1,619						27,349
Unallocated liabilities																										19,764
Capital expenditures		5,203			1,174			645			99			591			72			88			(39	)		7,833
2007
Net sales from operations (a)		27,278			27,633			36,401			6,934			8,678			205			1,313
Less: intersegment sales		(16,475	)		(760	)		(1,276	)		(363	)		(1,182	)		(31	)		(1,099	)
Net sales to customers		10,803			26,873			35,125			6,571			7,496			174			214						87,256
Operating profit		13,788			4,127			729			74			837			(444	)		(217	)		(26	)		18,868
Provisions for contingencies		5			37			256			15			11			264			3						591
Depreciation, amortization and writedowns		5,626			687			491			116			248			10			68			(10	)		7,236
Share of profit (loss) of equity-accounted investments		23			449			216						79			6									773
Identifiable assets (b)		33,435			24,530			13,767			3,427			8,017			275			854			(692	)		83,613
Unallocated assets																										17,847
Equity-accounted investments		1,926			2,152			1,267			15			230			49									5,639
Identifiable liabilities (c)		11,480			5,390			5,420			939			4,349			1,827			1,380						30,785
Unallocated liabilities																										27,808
Capital expenditures		6,625			1,366			979			145			1,410			59			108			(99	)		10,593

2008
Net sales from operations (a)		33,318			36,936			45,083			6,303			9,176			185			1,331			75
Less: intersegment sales		(19,067	)		(873	)		(1,496	)		(398	)		(1,219	)		(29	)		(1,177	)
Net sales to customers		14,251			36,063			43,587			5,905			7,957			156			154			75			108,148
Operating profit		16,415			3,933			(1,023	)		(822	)		1,045			(346	)		(686	)		125			18,641
Provisions for contingencies		155			237			206			2			36			99			165						900
Depreciation, amortization and writedowns		7,542			744			729			395			335			8			76			(14)			9,815
Share of profit (loss) of equity-accounted investments		173			413			16			(9	)		43			4									640
Identifiable assets (b)		41,989			31,894			11,081			2,629			10,630			362			789			(641	)		98,733
Unallocated assets																										17,857
Equity-accounted investments		1,787			2,249			1,227			25			130			53									5,471
Identifiable liabilities (c)		11,030			11,212			4,481			664			6,177			1,638			1,780			(75	)		36,907
Unallocated liabilities																										31,173
Capital expenditures		9,545			1,794			965			212			2,027			52			95			(128	)		14,562

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Inter-segment sales were conducted on an arm’s length basis.

Geographic financial information

Assets and investments by geographic area of origin

(euro million)

Italy

Other European Union

Rest of Europe

Americas

Asia

Africa

Other areas

Total

2006
Identifiable assets (a)		37,339		10,037		3,200		2,987		6,341		14,190		532		74,626
Capital expenditures		2,529		713		436		572		1,032		2,419		132		7,833
2007
Identifiable assets (a)		39,742		11,071		3,917		6,260		6,733		15,368		522		83,613
Capital expenditures		3,246		1,246		469		1,004		1,253		3,152		223		10,593
2008
Identifiable assets (a)		40,432		15,065		3,561		6,149		10,561		22,044		921		98,733
Capital expenditures		3,674		1,660		582		1,240		1,777		5,153		476		14,562

Sales from operations by geographic area of destination

(euro million)		2006		2007		2008

Italy		36,343		37,346		42,909
Other European Union		23,949		23,074		29,341
Rest of Europe		6,975		5,507		7,125
Americas		6,250		6,447		7,218
Asia		5,595		5,840		8,916
Africa		5,949		8,010		12,331
Other areas		1,044		1,032		308
		86,105		87,256		108,148

37 Transactions with related parties
In the ordinary course of its business, Eni enters into transactions regarding:

a)		the exchange of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries;
b)		the exchange of goods and provision of services with entities directly and indirectly owned or controlled by the Government;
c)		transactions with the Cosmi Holding Group related to Eni SpA through a member of the Board of Directors related to certain acquisition of engineering, construction and maintenance services. Relevant transactions which were executed on an arm’s length basis amounted to approximately euro 13 million, euro 18 million and euro 13 million in 2006, 2007 and 2008, respectively. At December 31, 2008 were outstanding receivables for euro 4 million and payables for euro 8 million;
d)		contributions to entities, controlled by Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (a) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment as well as research and development. Transactions with Eni Foundation related to contribution of euro 200 million to the solidarity fund pursuant to Italian Law Decree No. 112/2008 and the payable of euro 100 million related to the part of the contribution that had not already been paid. Transactions in the past periods were not material; (b) Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of

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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.

Trade and other transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities directly and indirectly owned or controlled by the Government in the 2006, 2007 and 2008, respectively, consisted of the following:

(euro million)		Dec. 31, 2006		2006

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Goods

Services

Joint ventures and associates
ASG Scarl		7		40		80				88		1		1
Azienda Energia e Servizi Torino SpA		1		22						64		1		1
Bernhard Rosa Inh. Ingeborg Plöchinger GmbH		10										96
Blue Stream Pipeline Co BV		34		19						193				1
Bronberger & Kessler Und Gilg & Schweiger GmbH		11										113
CAM Petroli Srl		103										310
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		87		87		5,654		16		2				304
Charville - Consultores e Serviços Lda		7				85						4		11
Eni Oil Co Ltd		5		96						59
Fox Energy SpA		35										125
Gasversorgung Süddeutschland GmbH		14								1		123		19
Gruppo Distribuzione Petroli Srl		19										54
Karachaganak Petroleum Operating BV		23		70				29		129				7
Mangrove Gas Netherlands BV				1		52
Mellitah Oil & Gas BV		28		90				7		72		8		2
Petrobel Belayim Petroleum Co				3						181
Promgas SpA		44		39				375				419
Raffineria di Milazzo ScpA		9		12						237		109
Rodano Consortile Scarl		3		14						54				1
RPCO Enterprises Ltd		13				104								12
Supermetanol CA				13				91
Super Octanos CA				13				257
Trans Austria Gasleitung GmbH		7		78				53		138				56
Transitgas AG				8						64
Transmediterranean Pipeline Co Ltd				7						80
Unión Fenosa Gas SA		1		7		61		93		7
Other (*)		72		169		168		75		188		119		66
		533		788		6,204		996		1,557		1,482		481
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		27		132				18		16				57
Eni BTC Ltd						185
Eni Timor Leste SpA						102
Other (*)		20		30		8		1		4		8		4
		47		162		295		19		20		8		61
		580		950		6,499		1,015		1,577		1,490		542
Entities owned or controlled by the Government
Gruppo Alitalia		12										354
Gruppo Enel		162		42				47		33		1,068		383
Other (*)		42		29				4		44		136		1
		216		71				51		77		1,558		384
		796		1,021		6,499		1,066		1,654		3,048		926

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(euro million)		Dec. 31, 2007		2007

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Goods

Services

Joint ventures and associates
ASG Scarl		6		43		121				108				3
Bernhard Rosa Inh. Ingeborg Plöchinger GmbH		11										86
Blue Stream Pipeline Co BV		19								183				1
Bronberger & Kessler und Gill & Schweiger GmbH		18										106
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		84		70		5,870								263
CEPAV (Consorzio Eni per l’Alta Velocità) Due		1		1		64				1				1
Eni Oil Co Ltd		7		60						141		1
Fox Energy SpA		49										139
Gasversorgung Süddeutschland GmbH		54										195		4
Gruppo Distribuzione Petroli Srl		26										50
Karachaganak Petroleum Operating BV		43		102				24		301				7
Mellitah Oil & Gas BV		10		137						105		1		6
OOO "EniNeftegaz"		215												1
Petrobel Belayim Petroleum Co				60						211
Raffineria di Milazzo ScpA		17		21						245		118		5
Supermetanol CA				11				78						1
Super Octanos CA				18				201						1
Trans Austria Gasleitung GmbH		6		80				43		147				47
Transitgas AG				8						64
Transmediterranean Pipeline Co Ltd				6						70				1
Unión Fenosa Gas SA		1				61						193
Other (*)		120		127		56		76		374		172		118
		687		744		6,172		422		1,950		1,011		459
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		49		111				11		534				52
Eni BTC Ltd						138								1
Other (*)		23		8		11		2		18		5		18
		72		119		149		13		552		5		71
		759		863		6,321		435		2,502		1,016		530
Entities owned or controlled by the Government
Gruppo Alitalia		4										363		1
Gruppo Enel		384		8						245		894		408
GSE - Gestore Servizi Elettrici		124		63				239		37		870		7
Terna SpA		19		69				106		105				31
Other (*)		45		79				19		89		75		3
		576		219				364		476		2,202		450
		1,335		1,082		6,321		799		2,978		3,218		980

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(euro million)		Dec. 31, 2008		2008

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Joint ventures and associates
Agiba Petroleum				11						60
Altergaz SA		30												135
ASG Scarl		2		25		49				57
Bayernoil Raffineriegesellschaft mbH		3		4		1		6		62				4
Bernhard Rosa Inh. Ingeborg Plöchinger GmbH		5												98
Blue Stream Pipeline Co BV		23		17						171						1
Bronberger & Kessler und Gilg & Schweiger GmbH		12												175
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		95		37		6,001				17		3				397
CEPAV (Consorzio Eni per l’Alta Velocità) Due		4		1		64				1						1
Eni Oil Co Ltd		9		28						660						6
Fox Energy SpA		37						2						329		1
FPSO Mystras - Produção de Petroleo Lda								94				10
Gasversorgung Süddeutschland GmbH		64												337		18
Gruppo Distribuzione Petroli Srl		20												111
InAgip doo		24		45						116				3		35
Karachaganak Petròleum Operating BV		72		207				874		380		25				12
Mellitah Oil & Gas BV		10		121						329				2		4
Petrobel Belayim Petroleum Co				77						181
Raffineria di Milazzo ScpA		11		4						276				135		3
Saipon Snc		4				58										12
Super Octanos CA				24				286
Supermetanol CA				5				90
Trans Austria Gasleitung GmbH		8		78				60		153						64
Transitgas AG				5						1		64
Unión Fenosa Gas SA		1		25		62		25						257		1
Other (*)		231		115		18		36		319		46		71		129		8
		655		829		6,253		1,473		2,783		148		1,657		684		8
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		144		166						720		11		1		367		10
Eni BTC Ltd						146
Other (*)		22		18		4		2		20		2		4		6		4
		166		184		150		2		740		13		5		373		14
		831		1,013		6,403		1,475		3,523		161		1,662		1,057		22
Entities owned or controlled by the Government
Ferrovie dello Stato		4												417		2
Gruppo Alitalia		153		12				13		223				941		380
Gruppo Enel		19		7						27		1		57
GSE - Gestore Servizi Elettrici		92		63				315				79		347		16		6
Terna SpA		33		35				14		128				12		83		10
Other (*)		28		72				33		88		5		72		2		1
		329		189				375		466		85		1,846		483		17
		1,160		1,202		6,403		1,850		3,989		246		3,508		1,540		39

Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned:

• transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Bologna with ASG Scarl, CEPAV (Consorzio Eni per l’Alta Velocità) Uno, and related guarantees;

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• acquisition of refining services from Bayernoil Raffineriegesellschaft mbH and Raffineria di Milazzo ScpA in relation to incurred costs;
• supply of oil products to Bernhard Rosa Inh. Ingeborg Plöchinger GmbH, Bronberger & Kessler und Gilg & Schweiger GmbH, Fox Energy Srl, Gruppo Distribuzione Petroli Srl 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;
• acquisition of FPSO from FPSO Mystras - Produção de Petròleo Lda;
• acquisition of natural gas transport services outside Italy from Blue Stream Pipeline Co BV, Trans Austria Gasleitung GmbH and Transitgas AG;
• guarantees issued on behalf of CEPAV (Consorzio Eni per l’Alta Velocità) Due in relation to contractual commitments related to the execution of project planning and realization;
• provision of specialized services in upstream activities and payables for investment activities from Agip Kazakhstan North Caspian Operating Co NV, Agiba Petroleum Co, Eni Oil Co Ltd, InAgip doo, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co and, only for Karachaganak Petroleum Operating BV supply of oil products; services are invoiced on the basis of incurred costs;
• sale of natural gas to Altergaz SA and Gasversorgung Süddeutschland GmbH;
• acquisition of petrochemical products from Supermetanol CA and Super Octanos 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;
• guarantees issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd.

Most significant transactions with entities owned or controlled by the Government concerned:

• sale of oil products with Alitalia and Ferrovie dello Stato;
• sale and transportation of natural gas, the sale of fuel oil and the sale and purchase of electricity and the acquisition of electricity transmission service with Enel;
• sale and purchase of electricity with GSE - Gestore Servizi Elettrici;
• sale and purchase of electricity and the acquisition of domestic electricity transmission service jointly with Terna SpA.

Financing transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities directly and indirectly owned or controlled by the Government in the 2006, 2007 and 2008, respectively, consisted of the following:

(euro million)		Dec. 31, 2006		2006

Name		Receivables		Payables		Guarantees		Charges		Gains

Joint ventures and associates
Blue Stream Pipeline Co BV				3		794		4		26
Raffineria di Milazzo ScpA						57
Spanish Egyptian Gas Co SAE						323
Trans Austria Gasleitung GmbH		41								6
Transmediterranean Pipeline Co Ltd		147								11
Other (*)		88		81		39		13		11
		276		84		1,213		17		54
Unconsolidated entities controlled by Eni
Other (*)		95		25		2		1		4
		95		25		2		1		4
		371		109		1,215		18		58

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(euro million)		Dec. 31, 2007		2007

Name

Receivables

Payables

Guarantees

Charges

Gains

Derivative financial instruments

Joint ventures and associates
Blue Stream Pipeline Co BV				1		711				20
Raffineria di Milazzo ScpA						60
Trans Austria Gasleitung GmbH		65								3
Transmediterranean Pipeline Co Ltd		97								9
Other (*)		108		120		52		19		11
		270		121		823		19		43
Unconsolidated entities controlled by Eni
Other (*)		114		26		1		1		6
		114		26		1		1		6
Entities owned or controlled by the Government
GSE - Gestore Servizi Elettrici												10
												10
		384		147		824		20		49		10

 

(euro million)		Dec. 31, 2008		2008

Name

Receivables

Payables

Guarantees

Charges

Gains

Derivative financial instruments

Joint ventures and associates
Bayernoil Raffineriegesellschaft mbH		131
Blue Stream Pipeline Co BV						752				14
PetroSucre SA		153
Raffineria di Milazzo ScpA						70
Trans Austria Gasleitung GmbH		186								7
Transmediterranean Pipeline Co Ltd		103								6
Other (*)		123		124		27		16		9
		696		124		849		16		36
Unconsolidated entities controlled by Eni
Other (*)		115		38		1		1		6
		115		38		1		1		6
Entities owned or controlled by the Government
GSE - Gestore Servizi Elettrici												58
												58
		811		162		850		17		42		58

Most significant transactions with joint ventures, associates and non-consolidated subsidiaries included:

• bank debt guarantee issued on behalf of Blue Stream Pipeline Co BV and cash deposit at Eni’s financial companies;
• bank debt guarantee issued on behalf of Raffineria di Milazzo ScpA;
• financing loan to Bayernoil Raffineriegesellschaft mbH;
• receivable from PetroSucre SA following the contribution of Corocoro activities, still to be defined, in the new mixed company;
• the financing of the Austrian section of the gasline from the Russian Federation to Italy and the construction of natural gas transmission facilities and transport services with Trans Austria Gasleitung GmbH and Transmediterranean Pipeline Co Ltd, respectively.

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Most significant transactions with entities owned or controlled by the Government concerned the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with GSE - Gestore Servizi Elettrici.

Impact of transactions and positions with related parties on the balance sheet, net profit and cash flows
The impact of transactions and positions with related parties on the balance sheet, net profit and cash flows consisted of the following:

		Dec. 31, 2006		Dec. 31, 2007		Dec. 31, 2008

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Trade and other receivables		18,799		1,027		5.46		20,676		1,616		7.82		22,222		1,539		6.93
Other current assets		855		4		0.47		1,080						2,349		59		2.51
Other non-current financial assets		805		136		16.89		923		87		9.43		1,134		356		31.39
Other non-current assets		994						1,110		16		1.44		1,401		21		1.50
Current financial liabilities		3,400		92		2.71		7,763		131		1.69		6,359		153		2.41
Trade and other payables		15,995		961		6.01		17,116		1,021		5.97		20,515		1,253		6.11
Other liabilities		634		4		0.63		1,556		4		0.26		4,319		4		0.09
Long-term debt and current portion of long-term debt		8,299		17		0.20		12,067		16		0.13		14,478		9		0.06
Other non-current liabilities		418		56		13.40		2,031		57		2.81		2,538		53		2.09

The impact of transactions with related parties on the profit and loss accounts consisted of the following:

		Dec. 31, 2006		Dec. 31, 2007		Dec. 31, 2008

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Net sales from operations		86,105			3,974			4.62			87,256			4,198			4.81			108,148			5,048			4.67
Other income and revenues		783						..			827						..			720			39			5.42
Purchases, services and other		57,490			2,720			4.73			58,179			3,777			6.49			76,408			6,298			8.24
Financial income		3,749			58			1.55			4,445			49			1.10			7,985			42			0.53
Financial expense		(3,971	)		(18	)		0.45			(4,554	)		(20	)		0.44			(8,198	)		(17	)		0.21
Gain (loss) on derivative financial instruments		383						..			26			10			38.46			(551	)		58			..

Transactions with related parties concerned the ordinary course of Eni’s business and were mainly conducted on an arm’s length basis.

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Main cash flows with related parties were as follows:

(euro million)		2006		2007		2008

Revenues and other income		3,974			4,198			5,087
Costs and other expenses		(2,720	)		(3,777	)		(6,298	)
Net change in trade and other receivables and liabilities		162			(492	)		351
Dividends and net interests		790			620			798
Net cash provided from operating activities		2,206			549			(62	)
Capital expenditures in tangible and intangible assets		(733	)		(779	)		(2,022	)
Investments		(20	)		8
Change in accounts payable in relation to investments		(276	)		(8	)		27
Change in financial receivables		343			(43	)		397
Net cash used in investing activities		(686	)		(822	)		(1,598	)
Change in financial liabilities		(57	)		20			14
Net cash used in financing activities		(57	)		20			14
Total financial flows to related parties		1,463			(253	)		(1,646	)

The impact of cash flows with related parties consisted of the following:

		2006		2007		2008

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Cash provided from operating activities		17,001			2,206			12.98			15,517			549			3.54			21,801			(62	)		..
Cash used in investing activities		(7,051	)		(686	)		9.73			(20,097	)		(822	)		4.09			(16,958	)		(1,598	)		9.42
Cash used in financing activities		(7,097	)		(57	)		0.80			2,909			20			0.69			(5,025	)		14			..

38 Significant non-recurring events and operations
Non-recurring incomes (charges) consisted of the following:

(euro million)		2006		2007		2008

Curtailment of post-retirement benefits for Italian employees					83
Risk provisions for proceedings against Antitrust authorities		(184	)		(130	)		(21	)
Risk provisions for proceedings against the Italian Authority for Electricity and Gas		(55	)		39
		(239	)		(8	)		(21	)

Non-recurring income related to a gain deriving from the curtailment of the provisions accrued by Italian companies for employee termination indemnities ("TFR") following the changes introduced by Italian Budget Law for 2007 and related decrees (euro 83 million). Non recurring charges for 2007 concerned risk provisions related to ongoing antitrust proceedings against the European Antitrust authorities (euro 130 million) in the fields of paraffin and elastomers.

In 2006 a risk provision was made in connection with a proceeding against the Italian Antitrust authority regarding the field of supplies of jet fuel (euro 109 million). In addition a risk provision was made for an inquiry before the European Antitrust authorities in the field of elastomers (euro 75 million). In 2006 certain fines were imposed by the Authority for Electricity and Gas regarding an inquiry relating to the use of storage capacity in thermal year 2005-2006 (euro 45 million) and an inquiry relating to an information requirement on natural gas supplying prices (euro 10 million).

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39 Positions or transactions deriving from atypical and/or unusual operations
In 2006, 2007 and in 2008 no transactions deriving from atypical and/or unusual operations were reported.

Recent developments

On April 7, 2009 Gazprom exercised its call option to purchase a 20% interest in OAO Gazprom Neft held by Eni following agreements between the two partners. The 20% interest in Gazprom Neft was acquired by Eni on April 4, 2007 as part of a bid procedure for the assets of bankrupt Russian company Yukos. The exercise price of the call option is equal to the bid price (U.S. $ 3.7 billion) as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and related financing expenses. At the same time, Eni and Gazprom signed new cooperation agreements targeting certain development projects to be conducted jointly in Russia and other countries of interest. Terms of the call option granted to Gazprom to purchase a 51% interest in the share capital of OOO SeverEnergia, which owns 100% of the three abovementioned Russian companies engaging in gas development, are currently under review by Eni, Enel and Gazprom.

On March 19, 2009, a mandatory tender offer on the minorities of Distrigas was finalized. Shareholders representing 41.61% of the share capital of Distrigas tendered 292,390 shares on Eni’s offer. Publigaz Scrl tendered its entire interest (31.25%). The transaction has been accounted in Eni financial statements as at March 31, 2009. On April 8, 2009 Eni paid to those shareholders cash consideration amounting to euro 1,991 million. Following the tender offer, Eni owns 98.86% of the share capital of Distrigas. The squeeze-out on the residual 1.14% of the share capital has been completed early in May. Consequently Eni holds all the shares of Distrigas except for one share belonging to the Belgian State with special powers. Distrigas shares has been delisted from Euronext Brussels. For further details on this transaction see "Item 4 – Gas & Power".

On February 12, 2009, Eni’s Board of Directors approved the divestment of 100% of Italgas SpA and Stoccaggi Gas Italia SpA (Stogit) to Snam Rete Gas (50.03% owned by Eni) for total cash consideration of euro 4,720 million (euro 3,070 million and euro 1,650 million, respectively). The transaction will be financed by Snam Rete Gas through: (i) a rights issue up for a maximum of euro 3.5 billion (Eni has already committed to subscribe its relative share of the rights issue); and (ii) new medium to long-term financing for euro 1.3 billion. The main impacts expected on Eni's consolidated financial statements when the transaction closes will be: (i) a decrease of euro 1.5 billion in net borrowings and a corresponding increase in total equity as a consequence of the pro-quota subscription of the Snam Rete Gas capital increase by the minority shareholders; and (ii) a decrease in Eni’s net profit equal to 45% of the aggregate net profit of Italgas and Stogit, with a corresponding increase in net profit attributable to minorities. From an industrial perspective the transaction, expected to close in July 2009, will create significant synergies in the regulated businesses segment and maximize the value of Italgas and Stogit due to the higher visibility of regulated businesses as a part of Snam Rete Gas. For further details on this transaction see "Item 4 – Gas & Power".

By the end of May 2008, based on the approval of the full year dividend proposal made by the Company’s Annual General Shareholders Meeting on April 30, 2009, Eni expects to pay the balance of the dividend for fiscal year 2008 amounting to euro 0.65 per share. Total cash out is estimated at euro 2.36 billion.

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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 Statement of Financial Accounting Standards No. 69, "Disclosures about Oil & Gas Producing Activities". 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

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

December 31, 2007
Proved mineral interests		10,571			8,118			8,506			8,672			1,447			7,718			45,032			790
Unproved mineral interests		32			120			1,030			330			35			2,582			4,129			1,089
Support equipment and facilities		279			1,125			443			16			41			59			1,963			10
Incomplete wells and other		726			562			1,078			75			1,852			808			5,101			112
Gross capitalized costs		11,608			9,925			11,057			9,093			3,375			11,167			56,225			2,001
Accumulated depreciation, depletion and amortization		(7,440	)		(4,960	)		(5,340	)		(5,670	)		(445	)		(4,909	)		(28,764	)		(345	)
Net capitalized costs (a) (b)		4,168			4,965			5,717			3,423			2,930			6,258			27,461			1,656
December 31, 2008
Proved mineral interests		10,772			10,116			11,368			7,499			2,130			8,954			50,839			813
Unproved mineral interests		32			638			2,267			316			1,051			2,908			7,212			928
Support equipment and facilities		283			1,205			520			16			51			71			2,146			14
Incomplete wells and other		1,374			1,006			1,443			159			2,631			1,797			8,410			267
Gross capitalized costs		12,461			12,965			15,598			7,990			5,863			13,730			68,607			2,022
Accumulated depreciation, depletion and amortization		(7,943	)		(6,318	)		(7,027	)		(5,132	)		(858	)		(6,932	)		(34,210	)		(441	)
Net capitalized costs (a) (b)		4,518			6,647			8,571			2,858			5,005			6,798			34,397			1,581

i	i	i
(a)	i	The amounts include net capitalized financial charges totaling euro 441 million in 2007 and euro 537 million in 2008.
(b)	i	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 application of the "Successful Effort Method" would have led to an increase in net capitalized costs of euro 2,547 million in 2007 and euro 3,308 million in 2008 for the consolidated companies and of euro 94 million in 2007 and euro 48 million in 2008 for joint ventures and associates.

(1)	i	Eni's capitalized costs of the Kashagan field are determined based on Eni's share of 16.81% as of December 31, 2008 and 18.52% in the previous year.
(2)	i	The amounts of joint ventures and associates as at December 31, 2007 and December 31, 2008 include 60% of the three Russian companies former Yukos purchased in 2007, for which Gazprom has a call option of 51%.

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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

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

2006
Proved property acquisitions		139		10										149
Unproved property acquisitions												3		3
Exploration		128		270		471		174		25		280		1,348		26
Development (a)		1,120		892		956		478		595		766		4,807		31
Total costs incurred		1,387		1,172		1,427		652		620		1,049		6,307		57
2007
Proved property acquisitions (b)				11		451						1,395		1,857		187
Unproved property acquisitions (b)						510						1,417		1,927		1,086
Exploration (b)		104		380		298		193		36		1,181		2,192		42
Development (a) (b)		320		1,047		1,425		518		744		1,185		5,239		156
Total costs incurred		424		1,438		2,684		711		780		5,178		11,215		1,471
2008
Proved property acquisitions (b)				626		413				173		83		1,295
Unproved property acquisitions (b)				384		655		33		647				1,719
Exploration (b)		135		421		581		214		144		719		2,214		48
Development (a) (b)		644		1,388		1,884		850		1,208		1,593		7,567		163
Total costs incurred		779		2,819		3,533		1,097		2,172		2,395		12,795		211

i	i	i
(1)	i	Eni’s costs incurred of the Kashagan field are determined based on Eni’s share of 16.81% as of December 31, 2008 and 18.52% in the previous year.
(2)	i	The amounts of joint ventures and associates for December 31, 2007 and December 31, 2008 include 60% of the three Russian companies former Yukos purchased in 2007, for which Gazprom has a call option of 51%.
(a)	i	Includes the abandonment costs of the assets for euro 1,170 million in 2006, euro 173 million in 2007 and euro 628 million in 2008 and euro 16 million for joint ventures and associates.
(b)	i	Of which business combination:

Results of operations from oil and gas producing activities
Results of operations from oil and gas producing activities, including gas storage services used to modulate the seasonal variation of demand, 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

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

2006
Revenues
Sales to consolidated entities		3,601			4,185			4,817			3,295			261			712			16,871
Sales to third parties		184			3,012			967			983			721			1,873			7,740			120
Total revenues		3,785			7,197			5,784			4,278			982			2,585			24,611			120
Operation costs		(249	)		(496	)		(475	)		(481	)		(147	)		(191	)		(2,039	)		(18	)
Production taxes		(181	)		(95	)		(475	)								(82	)		(833	)		(3	)
Exploration expenses		(137	)		(273	)		(186	)		(160	)		(25	)		(293	)		(1,074	)		(26	)
D.D. & A. and provision for abandonment (a)		(457	)		(795	)		(737	)		(684	)		(80	)		(895	)		(3,648	)		(43	)
Other income and (expenses)		(315	)		(569	)		(190	)		57			(89	)		(283	)		(1,389	)		8
Pretax income from producing activities		2,446			4,969			3,721			3,010			641			841			15,628			38
Income taxes		(909	)		(2,980	)		(2,133	)		(1,840	)		(223	)		(381	)		(8,466	)		(31	)
Results of operations from E&P activities (b)		1,537			1,989			1,588			1,170			418			460			7,162			7
2007
Revenues
Sales to consolidated entities		3,171			3,000			4,439			3,125			296			512			14,543
Sales to third parties		163			4,793			693			755			833			2,260			9,497			176
Total revenues		3,334			7,793			5,132			3,880			1,129			2,772			24,040			176
Operation costs		(248	)		(542	)		(499	)		(579	)		(142	)		(271	)		(2,281	)		(27	)
Production taxes		(188	)		(91	)		(473	)								(28	)		(780	)		(6	)
Exploration expenses		(108	)		(385	)		(291	)		(193	)		(36	)		(764	)		(1,777	)		(42	)
D.D. & A. and provision for abandonment (a)		(499	)		(768	)		(685	)		(729	)		(76	)		(989	)		(3,746	)		(51	)
Other income and (expenses)		(283	)		(627	)		(297	)		(45	)		(72	)		(243	)		(1,567	)		(18	)
Pretax income from producing activities		2,008			5,380			2,887			2,334			803			477			13,889			32
Income taxes		(746	)		(3,102	)		(1,820	)		(1,419	)		(284	)		(241	)		(7,612	)		(49	)
Results of operations from E&P activities (b)		1,262			2,278			1,067			915			519			236			6,277			(17	)
2008
Revenues
Sales to consolidated entities		3,956			2,622			5,013			3,691			360			629			16,271
Sales to third parties		126			7,286			1,471			121			1,288			2,928			13,220			265
Total revenues		4,082			9,908			6,484			3,812			1,648			3,557			29,491			265
Operation costs		(260	)		(528	)		(609	)		(515	)		(173	)		(326	)		(2,411	)		(34	)
Production taxes		(195	)		(32	)		(616	)								(35	)		(878	)		(53	)
Exploration expenses		(135	)		(425	)		(529	)		(215	)		(57	)		(697	)		(2,058	)		(48	)
D.D. & A. and provision for abandonment (a)		(551	)		(1,120	)		(1,115	)		(782	)		(331	)		(1,490	)		(5,389	)		(84	)
Other income and (expenses)		(420	)		(936	)		(279	)		(63	)		(286	)		(270	)		(2,254	)		(15	)
Pretax income from producing activities		2,521			6,867			3,336			2,237			801			739			16,501			31
Income taxes		(924	)		(4,170	)		(2,262	)		(1,581	)		(315	)		(435	)		(9,687	)		(49	)
Results of operations from E&P activities (b)		1,597			2,697			1,074			656			486			304			6,814			(18	)

i	i	i
(a)	i	Includes asset impairments amounting to euro 130 million in 2006, euro 91 million in 2007 and euro 770 million in 2008.
(b)	i	The "Successful Effort Method" application would have led to an increase in results of operations of euro 220 million in 2006, euro 438 million in 2007 and euro 408 million in 2008 for the consolidated companies and of euro 15 million in 2006, euro 26 million in 2007 and no variation in 2008 for joint ventures and associates.

(1)	i	Eni's results of operations of the Kashagan field are determined based on Eni’s share of 16.81% as of December 31, 2008 and 18.52% in the previous year.
(2)	i	The amounts of joint ventures and associates for December 31, 2007 and December 31, 2008 include 60% of the three Russian companies formerly part of Yukos purchased in 2007, for which Gazprom has a call option of 51%.

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Average sale prices and production costs per unit of production

(euro million)

Italy

North Africa

West Africa

North Sea

Caspian Area

Rest of World

Total

2006
Average sales prices
Oil and condensates per BBL		($)		55.22		60.99		61.55		62.18		53.18		57.15		60.09
Natural gas. per KCF				8.23		4.17		1.05		6.89		0.39		5.09		5.29
Average production costs per BOE				6.36		3.87		9.02		6.03		5.02		4.52		5.79
2007
Average sales prices
Oil and condensates per BBL		($)		62.47		67.86		69.77		69.40		59.34		68.63		67.70
Natural gas. per KCF				8.58		4.60		1.21		6.53		0.41		5.53		5.42
Average production costs per BOE				7.89		4.22		11.53		8.56		4.90		5.33		6.90
2008 (a)
Average sales prices
Oil and condensates per BBL		($)		84.87		84.71		91.58		71.90		80.43		82.06		84.05
Natural gas. per KCF				13.06		7.14		1.50		10.21		0.53		7.56		8.01
Average production costs per BOE				9.40		3.66		15.25		8.99		5.79		6.92		7.77

(a)		In 2008 Eni’s liquid realizations amounted to $84.05 per barrel and were reduced by approximately $4.13 per barrel due to the settlement of certain commodity derivatives relating to the sale of 46 mmBBL in the year. This was part of a derivative transaction the Company entered into to hedge exposure to variability in future cash flows expected from 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, decreasing to 79.7 mmBBL by the end of December 2008.

Oil and natural gas reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under technical, contractual, economic and operating conditions existing at the time. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not of increases based upon future conditions.

Net proved reserves exclude royalties and interests owned by others.

Proved developed oil and gas reserves are proved reserves that can be estimated to be recovered through existing wells, equipment and operating methods.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

Additional oil and gas reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed, through production response, that increased recovery will be achieved.

Eni’s proved reserves have been estimated on the basis of the applicable U.S. Securities & Exchange Commission regulation, Rule 4-10 of Regulation S-X and its interpretations and have been disclosed in accordance with Statement of Financial Accounting Standard No. 69. The estimates of proved reserves, developed and undeveloped, for the years ended December 31, 2006, 2007 and 2008 are based on data prepared by Eni. Since 1991 Eni has requested qualified independent oil engineering companies to carry out an independent evaluation¹⁶ of its proved reserves on a rotation basis. Eni believes these independent evaluators to be experienced and qualified in the marketplace. In the preparation of their reports, these independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale prices and other information and data that were accepted as represented by the independent evaluators. This information was the same used by Eni in determining proved reserves and include: log, directional surveys, core and PVT analysis, maps, oil/gas/water production/injection data of wells, reservoirs and fields, reservoir studies, technical analysis relevant to field performance, reservoir performance, budget data per field, long-term development plans, future capital and operating costs. In order to calculate the economic value of reserve NPV, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information are provided. Accordingly, the work performed

 

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by the independent evaluators is an evaluation of Eni’s proved reserves carried out in parallel with the internal one. The circumstance that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support the management’s confidence that the company’s booked reserves meet the regulatory definition of proved reserves which are reasonably certain to be produced in the future. When the assessment of independent engineers is lower than internal evaluations, Eni revises its estimates based on information provided by independent evaluators. In particular, in 2008, a total of 1.5 BBOE of proved reserves, or about 22% of Eni’s total proved reserves at December 31, 2008, have been evaluated. The results of this independent evaluation have essentially confirmed, as in previous years, the internal assessment. In the 2006-2008 three-year period, 77% of Eni’s total proved reserves were subject to independent evaluations. In the last three years, the most important of Eni’s properties as at December 31, 2008 which were not subject to an independent evaluation were: Bouri and Bu Attifel (Libya), Barbara (Italy), M’Boundi (Congo) and Elgin-Franklin (UK).

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 53%, 46% and 54% of total proved reserves as of year-end 2006, 2007 and 2008, respectively, on an oil-equivalent basis.

Proved reserves associated with service and "Buy-Back" represented 2%, 1% and 2% of total proved reserves on an oil-equivalent basis as of year-end 2006, 2007 and 2008, 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 obligations represent 1.1%, 1.8% and 0.1% of total proved reserves as of year-end 2006, 2007 and 2008, respectively, on an oil-equivalent basis; (ii) volumes of natural gas used for own consumption; and (iii) volumes of natural gas held in certain of Eni’s storage fields in Italy. Proved reserves attributable to these fields include: (a) the residual natural gas volumes of the reservoirs and (b) natural gas volumes from other Eni fields input into these reservoirs in subsequent periods. Proved reserves do not include volumes owned by or acquired by third parties. Gas withdrawn from storage is produced and thereby removed from proved reserves when sold.

Numerous uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may require substantial upward or downward revision. 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 at the date when such estimates are made. Consequently, reserves evaluation could also diverge significantly from oil and natural gas volumes which will be actually 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 for the years 2006, 2007 and 2008.

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Crude oil (including condensate and natural gas liquids)

Proved oil reserves

Italy

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

(mmBBL)

Reserves at December 31, 2005		228			961			936			433			778			412			3,748			25
Revisions of Previous Estimates (a)		15			61			(85	)		20			72			(19	)		64			1
Improved Recovery					49			41						14						104			1
Extensions and Discoveries					30			11						52			10			103
Production		(28	)		(119	)		(117	)		(65	)		(23	)		(38	)		(390	)		(3	)
Sales of Minerals in Place (b)											(2	)					(170	)		(172	)
Reserves at December 31, 2006		215			982			786			386			893			195			3,457			24
Purchase of Minerals in Place								32									54			86			101
Revisions of Previous Estimates		28			(35			(26	)		14			(114	)		(31	)		(164	)		20
Improved Recovery					9			12			1									22			1
Extensions and Discoveries					43			22			1						29			95			1
Production		(28	)		(121	)		(101	)		(57	)		(26	)		(36	)		(369	)		(5	)
Reserves at December 31, 2007		215			878			725			345			753			211			3,127			142
Purchase of Minerals in Place								32						32			4			68
Revisions of Previous Estimates		(8	)		56			80			(31	)		238			56			391			4
Improved Recovery					7			25												32			1
Extensions and Discoveries		4			4			26			13			2			3			52
Production		(25	)		(122	)		(105	)		(51	)		(30	)		(38	)		(371	)		(5	)
Sales of Minerals in Place														(56	)					(56	)
Reserves at December 31, 2008		186			823			783			276			939			236			3,243			142

 

Proved developed oil reserves

Italy

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

(mmBBL)

Reserves at December 31, 2005		149		697		568		353		266		298		2,331		19
Reserves at December 31, 2006		136		713		546		329		262		140		2,126		18
Reserves at December 31, 2007		133		649		511		299		219		142		1,953		26
Reserves at December 31, 2008		111		613		576		222		321		166		2,009		33

i	i
(a)	i	Includes the redetermination of Eni’s share in the Val d’Agri concession in Italy.
(b)	i	Includes 170 mmBBL related to unilateral termination of OSA for Dación field by PDVSA.

(1)	i	Eni’s proved reserves of the Kashagan field are determined based on Eni's share of 16.81% as of December 31, 2008 and 18.52% in previous years.
(2)	i	Reserves of joint ventures and associates as at December 31, 2007 and December 31, 2008 include 60% of the three Russian companies formerly part of Yukos purchased in 2007, for which Gazprom has a call option of 51%.

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Natural gas

Proved natural gas reserves

Italy (a)

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

(BCF)

Reserves at December 31, 2005		3,676			6,117			1,965			1,864			1,774			2,105			17,501			90
Purchase of Minerals in Place											4									4
Revisions of Previous Estimates		36			154			31			53			183			47			504			(7	)
Extensions and Discoveries		19			146			34			1						132			332			8
Production		(340	)		(471	)		(103	)		(218	)		(83	)		(222	)		(1,437	)		(15	)
Sales of Minerals in Place											(7	)								(7	)
Reserves at December 31, 2006		3,391			5,946			1,927			1,697			1,874			2,062			16,897			68
Purchase of Minerals in Place								5									395			400			2,963
Revisions of Previous Estimates		(53	)		250			74			67			(222	)		6			122			5
Improved Recovery											3									3
Extensions and Discoveries		4			89			213			7			205			89			607
Production		(285	)		(534	)		(97	)		(216	)		(87	)		(261	)		(1,480	)		(14	)
Reserves at December 31, 2007		3,057			5,751			2,122			1,558			1,770			2,291			16,549			3,022
Purchase of Minerals in Place								6			8						114			128
Revisions of Previous Estimates		56			1,163			45			(51	)		773			55			2,041			6
Improved Recovery								4												4
Extensions and Discoveries		5			38			2			25						42			112
Production		(274	)		(641	)		(95	)		(204	)		(90	)		(300	)		(1,604	)		(13	)
Sales of Minerals in Place														(16	)					(16	)
Reserves at December 31, 2008		2,844			6,311			2,084			1,336			2,437			2,202			17,214			3,015

 

Proved developed natural gas reserves

Italy (a)

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

(BCF)

Reserves at December 31, 2005		2,704		3,060		1,289		1,484		1,618		1,004		11,159		70
Reserves at December 31, 2006		2,449		3,042		1,447		1,395		1,511		1,105		10,949		48
Reserves at December 31, 2007		2,304		3,065		1,469		1,293		1,580		1,256		10,967		428
Reserves at December 31, 2008		2,031		3,537		1,443		1,065		2,006		1,056		11,138		420

(a)		Including approximately 760, 754, 749 and 746 BCF of natural gas held in storage at December 31, 2005, 2006, 2007 and 2008, respectively.
(1)		Eni’s proved reserves of the Kashagan field are determined based on Eni's share of 16.81% as of December 31, 2008 and 18.52% in previous years.
(2)		Reserves of joint ventures and associates as at December 31, 2007 and December 31, 2008 include 60% of the three Russian companies formerly part of Yukos purchased in 2007, for which Gazprom has a call option of 51%.

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 prices of oil and gas to the estimated future production of proved reserves. 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 cash flows as of December 31, 2006, 2007 and 2008 include amounts that Eni’s Gas & Power segment and other gas companies pay for storage services, required to support market demand flexibility needs.

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 Statement of Financial Accounting Standard No. 69. 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

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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

North Africa

West Africa

North Sea

Caspian Area (1)

Rest of World

Total consolidated subsidiaries

Total joint ventures and associates (2)

At December 31, 2006
Future cash inflows		43,495			64,381			34,935			24,821			33,825			14,766			216,223			1,038
Future production costs		(6,086	)		(9,707	)		(8,028	)		(6,426	)		(4,162	)		(1,753	)		(36,162	)		(224	)
Future development and abandonment costs		(6,739	)		(5,383	)		(2,865	)		(2,265	)		(3,103	)		(1,473	)		(21,828	)		(79	)
Future cash inflow before income tax		30,670			49,291			24,042			16,130			26,560			11,540			158,233			735
Future income tax		(10,838	)		(24,639	)		(14,141	)		(10,901	)		(7,649	)		(3,824	)		(71,992	)		(227	)
Future net cash flows		19,832			24,652			9,901			5,229			18,911			7,716			86,241			508
10% discount factor		(11,493	)		(10,631	)		(2,994	)		(1,392	)		(13,878	)		(2,626	)		(43,014	)		(154	)
Standardized measure of discounted future net cash flows		8,339			14,021			6,907			3,837			5,033			5,090			43,227			354
At December 31, 2007
Future cash inflows		47,243			73,456			48,283			29,610			42,710			20,359			261,661			7,135
Future production costs		(5,926	)		(11,754	)		(9,875	)		(6,670	)		(4,997	)		(2,782	)		(42,004	)		(1,249	)
Future development and abandonment costs		(7,218	)		(4,643	)		(3,013	)		(2,461	)		(3,374	)		(2,459	)		(23,168	)		(1,721	)
Future cash inflow before income tax		34,099			57,059			35,395			20,479			34,339			15,118			196,489			4,165
Future income tax		(10,778	)		(29,083	)		(23,083	)		(14,375	)		(9,977	)		(5,397	)		(92,693	)		(2,009	)
Future net cash flows		23,321			27,976			12,312			6,104			24,362			9,721			103,796			2,156
10% discount factor		(13,262	)		(11,143	)		(3,953	)		(1,600	)		(17,480	)		(3,356	)		(50,794	)		(1,265	)
Standardized measure of discounted future net cash flows		10,059			16,833			8,359			4,504			6,882			6,365			53,002			891
At December 31, 2008
Future cash inflows		46,458			62,785			22,344			16,056			22,199			13,622			183,464			4,782
Future production costs		(5,019	)		(10,673	)		(6,715	)		(3,414	)		(6,380	)		(2,715	)		(34,916	)		(1,104	)
Future development and abandonment costs		(6,805	)		(6,153	)		(3,868	)		(2,166	)		(5,114	)		(1,897	)		(26,003	)		(1,845	)
Future cash inflow before income tax		34,634			45,959			11,761			10,476			10,705			9,010			122,545			1,833
Future income tax		(11,329	)		(27,800	)		(5,599	)		(7,621	)		(2,781	)		(1,901	)		(57,031	)		(1,032	)
Future net cash flows		23,305			18,159			6,162			2,855			7,924			7,109			65,514			801
10% discount factor		(13,884	)		(8,639	)		(2,155	)		(869	)		(6,272	)		(2,243	)		(34,062	)		(763	)
Standardized measure of discounted future net cash flows		9,421			9,520			4,007			1,986			1,652			4,866			31,452			38

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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 2006, 2007 and 2008.

(euro million)		2006		2007		2008

Beginning of year		55,722			43,581			53,893
Beginning of year related to joint venture and associates		(371	)		(354	)		(891	)
Beginning of year consolidated		55,351			43,227			53,002
Increase (decrease):
- sales, net of production costs		(21,739	)		(20,979	)		(26,202	)
- net changes in sales and transfer prices, net of production costs		4,097			34,999			(39,699	)
- extensions, discoveries and improved recovery, net of future production and development costs		3,629			3,982			1,110
- changes in estimated future development and abandonment costs		(6,964	)		(4,000	)		(6,222	)
- development costs incurred during the period that reduced future development costs		3,558			4,682			6,584
- revisions of quantity estimates		383			(2,995	)		5,835
- accretion of discount		9,489			7,968			10,538
- net change in income taxes		3,060			(17,916	)		21,359
- purchase of reserves in-place		10			3,521			476
- sale of reserves in-place		(1,252	)					25
- changes in production rates (timing) and other		(6,395	)		513			4,646
Net increase (decrease)		(12,124	)		9,775			(21,550	)
Standardized measure of discounted future net cash flows consolidates		43,227			53,002			31,452
Standardized measure of discounted future net cash flows joint ventures and associates		354			891			38
Standardized measure of discounted future net cash flows		43,581			53,893			31,490

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EXHIBIT 1

Eni SpA By-laws

Part I - Establishment - Name - Registered Office and Duration of the Company

ARTICLE 1

1.1

"Eni SpA" resulting from the transformation of Ente Nazionale Idrocarburi, a public law agency, established by Law 136 of February 10, 1953, is regulated by these by-laws.

ARTICLE 2

2.1		The registered head office of the company is located in Rome, Italy and the company’s two branches in San Donato Milanese (MI).
2.2		Main representative offices, affiliates and branches may be established and/or wound up in Italy or abroad in compliance with the law.

ARTICLE 3

3.1

The company is expected to exist until December 31, 2100. Its duration may be extended one or more times by resolution of the shareholders’ meeting.

Part II - Company Objects

ARTICLE 4

4.1

The company objects are the direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the field of hydrocarbons and natural vapours, such as exploration and development of hydrocarbon fields, construction and operation of pipelines for transporting the same, processing, transformation, storage, utilisation and trade of hydrocarbons and natural vapours, all in respect of concessions provided by law. The company also has the object of direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the fields of chemicals, nuclear fuels, geothermy and renewable energy sources, in the sector of engineering and construction of industrial plants, in the mining sector, in the metallurgy sector, in the textile machinery sector, in the water sector, including derivation, drinking water, purification, distribution and reuse of waters; in the sector of environmental protection and treatment and disposal of waste, as well as in every other business activity that is instrumental, supplemental or complementary with the aforementioned activities. The company also has the object of managing the technical and financial co-ordination of subsidiaries and affiliated companies as well as providing financial assistance on their behalf. The company may perform any operations necessary or useful for the achievement of the company objects; by way of example, it may initiate operations involving real estate, moveable goods, trade and commerce, industry, finance and banking asset and liability operations, as well as any action that is in any way connected with the company objects with the exception of public fund raising and the performance of investment services as regulated by Legislative Decree No. 58 of February 24, 1998. The company may take shareholdings and interests in other companies or businesses with objects similar, comparable or complementary to its own or those of companies in which it has holdings, either in Italy or abroad, and it may provide real and or personal bonds for its own and others’ obligations, especially guarantees.

Part III - Capital - Shareholdings - Bonds

ARTICLE 5

5.1		The company capital is euro 4,005,358,876.00 (four billion five million three hundred and fifty-eight thousand eight hundred and seventy-six) represented by 4,005,358,876 (four billion five million three hundred and fifty-eight thousand eight hundred and seventy-six) shares of ordinary stock with a nominal value of euro 1 (one) each.
5.2		Shares may not be split up and each share is entitled to one vote.
5.3		The fact of being a Shareholder in itself constitutes approval of these by-laws.

ARTICLE 6

6.1

Pursuant to Article 3 of Law Decree 332 of May 31, 1994, converted with amendments into Law 474 of July 30, 1994, no one, in any capacity, may own company shares that entail a holding of more than 3 per cent of voting share capital. Such maximum shareholding limit is calculated by taking into account the aggregate shareholding held by the controlling entity, either a physical or legal person or company; its directly or indirectly controlled entities, as well as entities controlled by the same controlling entity; affiliated entities as well as people related to the second degree by blood or marriage, also in the case of a legally separated spouse.

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		Control exists, with reference also to entities other than companies, in the cases envisaged by Article 2359, paragraphs 1 and 2 of the Civil Code. Affiliation exists in the case set forth in Article 2359, paragraph 3, of the Civil Code as well as between entities that directly or indirectly, by way of subsidiaries, other than those managing investment funds, are bound, even with third parties, in agreements regarding the exercise of voting rights or the transfer of shares or portions of third companies or, in any event, in agreements or pacts as per Article 122 of Legislative Decree No. 58 of February 24, 1998 regarding third party companies if said agreements or pacts concern at least 10 per cent of the voting capital, if they are listed companies, or 20 per cent if they are unlisted companies. The aforementioned shareholding limit (3 per cent) is calculated by taking into account shares held by any fiduciary nominee or intermediary. Any voting rights and any other non-financial rights attributable to voting capital held or controlled in excess of the maximum limit indicated in the foregoing cannot be exercised and the voting rights of each entity to whom such limit on shareholding applies are reduced in proportion, unless otherwise jointly provided in advance by the parties involved. In the event that shares exceeding this limit are voted, any Shareholders’ resolution adopted pursuant to such a vote may be challenged pursuant to Article 2377 of the Civil Code, if the required majority had not been reached without the votes exceeding the aforementioned maximum limit. Shares not entitled to vote are included in the determination of the quorum at shareholders’ meetings.
6.2		Pursuant to Article 2, paragraph 1 of Law Decree 332 of May 31, 1994, converted with amendments into Law 474 of July 30, 1994, as modified by Article 4, paragraph 227, of Law December 24, 2003, No. 350, the Minister of Economy and Finance retains the following special powers to be exercised in agreement with the Minister of the Economic Development and according to the criteria contained in the Decree issued by the President of the Council of Ministers on June 10, 2004:

		a)		opposition with respect to the acquisition of material shareholdings by entities affected by the shareholding limit as set forth in Article 3 of Law Decree 332 of May 31, 1994, converted with amendments into Law 474 of July 30, 1994, by which – as per Decree issued by the Minister of Treasury on October 16, 1995 – are meant those representing at least 3% of share capital with the right to vote at the ordinary shareholders’ meeting. The opposition is expressed within ten days of the date of the notice to be filed by the Board of Directors at the time request is made for registration in the Shareholders’ Register if the Minister considers that such an acquisition may prejudice the vital interests of the Italian State. Until the ten-day term is not lapsed, the voting rights and the non-asset linked rights connected with the shares representing a material shareholding may not be exercised. If the opposition power is exercised, through a duly motivated act in connection with the prejudice that may be caused by the operation to the vital interests of the Italian State, the transferee may not exercise the voting rights and the other non-asset linked rights connected with the shares representing a material shareholding and must sell said shares within one year. Failing to comply, the law court, upon request of the Minister of Economy and Finance, will order the sale of the shares representing a material shareholding according to the procedures set forth in Article 2359-ter of the Civil Code. The act through which the opposition power is exercised may be sued by the transferee before the Regional Administrative Court of Latium within sixty days as of its issue;
		b)		opposition with respect to the subscription of Shareholders’ pacts or agreements as per Article 122 of Legislative Decree No. 58 of February 24, 1998, involving – as per Decree issued by the Minister of Treasury on October 16, 1995 – at least 3% of the share capital with the right to vote at ordinary shareholders’ meetings. In order to allow the exercise of the above mentioned opposition power, Consob notifies the Minister of Economy and Finance of the relevant pacts or agreements communicated to it pursuant to the aforementioned Article 122 of Legislative Decree No. 58 of February 24, 1998. The opposition power may be exercised within ten days as of the date of the notice by Consob. Until the ten-day term is not lapsed, the voting right and the other non-asset linked rights connected with the shares held by the shareholders who have subscribed the above mentioned pacts or agreements may not be exercised. If the opposition power is exercised through the issue of an act that shall be duly motivated in consideration of the prejudice that may be caused by said pacts or agreements to the vital interests of the Italian State, the shareholders pacts or agreements shall be null and void. If in the shareholders’ meetings the shareholders who have signed shareholders’ pacts or agreements behave as if those pacts or agreements disciplined by Article 122 of Legislative Decree No. 58 of February 24, 1998 were still in effect, the resolutions approved with their vote, if determining for the approval, may be sued. The act through which the opposition power is exercised may be sued by the shareholders who joined the above mentioned pacts or agreements before the Regional Administrative Court of Latium within sixty days as of its issue;
		c)		veto power with respect to resolutions to dissolve the company, to transfer the business, to merge, to demerge, to transfer the company’s registered office abroad, to change the company objects and to amend the by-laws cancelling or modifying the powers indicated in this Article. The act through which the veto power is exercised shall be duly motivated in consideration of the prejudice the related resolution may cause to the vital interests of the Italian State and may be sued by the dissenting Shareholders before the Regional Administrative Court of Latium within sixty days as of its issue;

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d)

appointment of one Board member with no voting rights. Should such appointed Director lapse, the Minister of Economy and Finance in agreement with the Minister of the Economic Development will appoint his substitute.

ARTICLE 7

7.1

When shares are fully paid, and if the law so allows, they may be issued to the bearer. Bearer shares may be converted into registered shares and vice versa. Conversion operations are performed at the Shareholder’s expense.

ARTICLE 8

8.1

In the event, and for whatever reason, a share belongs to more than one person, the rights relating to said share may not be exercised by other than one person or by a proxy for all co-owners.

ARTICLE 9

9.1		The shareholders’ meeting may resolve to increase the company capital and establish terms, conditions and means thereof.
9.2		The shareholders’ meeting may resolve to increase the company capital by issuing shares, including shares of different classes, to be assigned for no consideration pursuant to Article 2349 of the Civil Code.

ARTICLE 10

10.1		Payments on shares are requested by the Board of Directors in one or more times.
10.2		Shareholders who are late in payment are charged an interest calculated at the official discount rate established by the Bank of Italy besides the provisions envisaged in Article 2344 of the Civil Code.

ARTICLE 11

11.1

The company may issue bonds, including convertibles and warrant bonds in compliance with the law.

Part IV - Shareholders’ meeting

ARTICLE 12

12.1		Ordinary and extraordinary shareholders’ meetings are usually held at the company registered office unless otherwise resolved by the Board of Directors, provided however they are held in Italy.
12.2		Ordinary shareholders’ meetings must be called at least once a year to approve the financial statements within 120 days of the end of the business year.

ARTICLE 13

13.1		Shareholders’ meetings are convened through a notice to be published on the Italian Official Gazette or the following newspapers: "Il Sole 24 Ore", "Corriere della Sera" and "Financial Times", according to the current legislation and in compliance with the rules in force regulating the exercise of the vote by mail. The Shareholders that, severally or jointly, represent at least one fortieth of Eni share capital, may ask, within five days as of the date of publication of the shareholders’ meeting notice, to add other items in the agenda. The request shall contain the matters to be proposed to the shareholders’ meeting. Said faculty may not be exercised on the matters upon which, pursuant to the applicable legislation, the shareholders’ meeting resolves on the basis of a proposal of the Board of Directors or on the basis of a project or report of the Board. The integrations accepted by the Board shall be published at least ten days before the shareholders’ meeting date, through a notice to be published as indicated above.
13.2		Admission to the shareholders’ meeting is subject to the delivery, also for registered shares, of the communication issued by financial intermediaries at least two labour days before the date of the shareholders’ meeting on first call.

ARTICLE 14

14.1		Each Shareholder entitled to attend the meeting may also be represented in compliance with the law by a person appointed by written proxy. Incorporated entities and companies may attend the meeting by way of a person appointed by written proxy. In order to simplify collection of proxies issued by Shareholders who are employees of the company or its subsidiaries and members of Shareholders associations incorporated under and managed pursuant to current legislation regulating proxies collection, notice boards for communications and rooms to allow proxies collection are made available to said associations according to terms and conditions agreed from time to time by the company with the associations representatives.
14.2		The Chairman of the meeting has to assure the regularity of written proxies and, in general, the right to attend the meeting.
14.3		The right to vote may also be exercised by mail according to the laws and regulations in force concerning this matter.
14.4		Eni SpA shareholders’ meetings are disciplined by Eni SpA’s shareholders’ meeting Regulation approved by the ordinary shareholders’ meeting.

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ARTICLE 15

15.1		The meeting is chaired by the Chairman of the Board of Directors, or in the event of absence or impediment, by the Chief Executive Officer; in absence of both, by another person, duly delegated by the Board of Directors, failing which the meeting may 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 Shareholders present, and may appoint one or more scrutineers.

ARTICLE 16

16.1		The ordinary shareholders’ meeting decides on all the matters for which it is legally entitled and authorises the transfer of the business.
16.2		Resolutions either at ordinary or extraordinary meetings, either on first, second or third call, must be taken with the majority required by the law in each case.
16.3		Resolutions of the meeting taken in compliance with the law and these by-laws are binding for all Shareholders even if absent or dissenting.
16.4		The minutes of ordinary meetings must be signed by the Chairman and the Secretary.
16.5		The minutes of extraordinary meetings must be drawn up by a notary public.

Part V - The Board of Directors

ARTICLE 17

17.1		The company is managed by a Board of Directors consisting of no fewer than three and no more than nine members. The shareholders’ meeting determines the number within these limits. The Minister of Economy and Finance in agreement with the Minister of the Economic Development may appoint another member, with no voting rights, pursuant to Article 6, second paragraph, letter d), of the by-laws.
17.2		The Board of Directors is appointed for a period of up to three financial years; this term lapses on the date of the shareholders’ meeting convened to approve the financial statements of the last year of their office. They may be reappointed.
17.3		The Board of Directors, except for the member appointed pursuant to Article 6.2, letter d) of these by-laws, is appointed by the shareholders’ meeting on the basis of lists presented by Shareholders and by the Board of Directors; in such lists the candidates must be listed in numerical order. Should the retiring Board of Directors present its own candidate list, it must be deposited at the company’s registered office and published in at least three Italian newspapers of general circulation, two of them business dailies, at least twenty days before the date set for the first call of the shareholders’ meeting. Candidate lists presented by Shareholders must be deposited and published as indicated in the foregoing at least ten days before the date set for the first call of the shareholders’ meeting. Each Shareholder may present or take part in the presenting of only one candidate list and vote only one candidate list. Those who are controlling or controlled entities or are under common control, as defined by Article 93 of Legislative Decree No. 58 issued on February 24, 1998, by the same entity of the shareholder presenting a list shall not present nor take part in the presentation of another candidate list, nor vote them, also through intermediaries or fiduciaries. Each candidate may appear in one list only or he will be ineligible. Only those Shareholders who, alone or together with other Shareholders, represent at least 1 per cent of voting share capital at the ordinary shareholders’ meeting may present candidate lists. In order to demonstrate the title on the number of shares necessary to present candidate lists, the Shareholders must present and/or deliver with the company’s registered office a copy of the communication issued by the authorised financial intermediaries that are depositaries of their shares at least five days prior to the date set for the first call of the shareholders’ meeting. At least one Board member, if the Board members are no more than five, or at least three Board members if the Board members are more than five, shall have the independence requirements set for the Board of Statutory Auditors members of listed companies. The independent candidates shall be expressly indicated in each list. All candidates shall also have the honorability qualifications set forth by the applicable legislation. Together with the deposit of each list, in order to assure its validity, the following documents shall be deposited: (i) the curriculum of each candidate; (ii) statements of each candidate to accept his nomination and attest, in his own responsibility, that causes for his ineligibility and incompatibility are non existing and that he possesses the aforementioned honorability and, if any, independence requirements. The Directors appointed shall communicate to the Company if they have lost the above mentioned independence and honorability requirements and if situations of ineligibility or incompatibility have arisen. The Board of Directors evaluates periodically the independence and the honorability of its members and if situations of ineligibility or incompatibility have arisen. If the honorability or independence requirements declared and set forth by the legislation in force are not present or elapse for a Board member or if situations of ineligibility or incompatibility have arisen, the Board of Directors removes said Board member and resolves upon his substitution or invites him to remove the situation of incompatibility within the term set by the Board itself; if this last condition is not met, the Director will be removed from office.

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Board members will be elected in the following manner:

		a)		seven tenths of the members to be elected will be drawn out from the candidate list that receives the majority of votes expressed by the Shareholders in the numerical order in which they appear on the list, rounded off in the event of a fractional number to the next lower number;
		b)		the remaining Board members will be drawn out from the other candidate lists; said lists shall not be linked in any way, neither indirectly, to the shareholders who have presented or voted the list that has obtained the highest number of votes; to this purpose the votes obtained by each candidate list will be divided by one or two depending on the number of the members to be elected. The quotients thus obtained will be assigned progressively to candidates of each said list in the order given in the lists themselves. Quotients thus assigned to candidates of said lists will be set in one decreasing numerical order. Those who obtain the highest quotients will be elected. In the event that more than one candidate obtains the same quotient, the candidate elected will be the one of the list that has not hitherto had a Board member elected or that has elected the least number of Board members. In the event that none of the lists has yet elected a Board member or that all of them have elected the same number of Board members, the candidate from all such lists who has obtained the largest number of votes will be elected. In the event of equal list votes and equal quotient, a new vote will be taken by the entire shareholders’ meeting and the candidate elected will be the one who obtains a simple majority of the votes;
		c)		if through the procedure described above the minimum number of independent Directors set by these by-laws is not elected, the quotient is calculated according to letter b) above in order to be assigned to the candidates present in each list; the independent candidates not yet drawn from the lists pursuant to letters a) and b) above, who have got the highest quotients will be elected in order to meet the provision of the by-laws on the number of the independent Directors. The Directors so appointed will replace the non independent Directors to whom the lowest quotients have been assigned. If the number of independent candidates is lower than the minimum limit set by the by-laws, the shareholders’ meeting will make a resolution with the majorities prescribed by the law to substitute the not independent candidates who have got the lowest quotients;
		d)		to appoint Board members for any reason not covered by the terms of the aforementioned procedure, the shareholders’ meeting will make a resolution with the majorities prescribed by the law in order, however, to assure that the Board composition complies with the current legislation and the by-laws.

		The vote by list procedure shall apply only in case of appointment of the entire Board of Directors.
17.4		The shareholders’ meeting may, even during the Board’s term of office, change the number of members of the Board of Directors, always within the limits set forth in paragraph 17.1 above, and make the relating appointments. Board members so elected will expire at the same time as the rest of the Board.
17.5		If during the term of office one or more members leave the Board, action will be taken in compliance with Article 2386 of the Civil Code with exception of the Board member appointed pursuant to Article 6.2 letter d) of these by-laws. If a majority of members leaves the Board, the whole Board will be considered lapsed and the Board must promptly call a shareholders’ meeting to appoint a new Board.
17.6		The Board may establish Board Committees that shall have advisory and consulting tasks on specific items.

ARTICLE 18

18.1		If the shareholders’ meeting has not appointed a Chairman, the Board will elect one of its members. The Director appointed pursuant to Article 6, second paragraph, letter d) of the by-laws cannot be appointed as Chairman.
18.2		The Board, at the Chairman’s proposal, appoints a Secretary, who need not belong to the company.

ARTICLE 19

19.1		The Board meets in the place indicated in the notice whenever the Chairman or, in case of absence or impediment, the Chief Executive Officer deems necessary, or when written application has been made by the majority of the members. The Board of Directors may be convened also pursuant to Article 28.4 of the by-laws. The Board of Directors’ meetings may be held by video or teleconference if each of the participants to the meetings may be identified and if each is allowed to follow the discussion and take part to it in real time. If said conditions are met, the meeting is considered duly held in the place where the Chairman and the Secretary are present.
19.2		Usually notice is given at least five days in advance. In cases of urgency notice may be sent earlier. The Board of Directors decides on how to convene its meetings.
19.3		The Board of Directors must likewise be convened when so requested by at least two Board members or by one member if the Board consists of three members to decide on a specific matter considered of particular importance, pertaining to management, matter to be indicated in the request.

ARTICLE 20

20.1

The Chairman of the Board or, in his absence, the oldest Board member in attendance chairs the meeting.

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ARTICLE 21

21.1		A majority of members of the Board having a voting right must be present for a Board meeting to be valid.
21.2		Resolutions are taken with the majority of votes of the Board members having a voting right present; should votes be equal, the person who chairs the meeting has a casting vote.

ARTICLE 22

22.1		Resolutions of the Board are entered in the minutes, which are recorded in a book kept for that purpose pursuant to the law, and said minutes are signed by the Chairman of the meeting and by the Secretary.
22.2		Copies of the minutes are bona fide if they are signed by the Chairman or the person acting for him and countersigned by the Secretary.

ARTICLE 23

23.1		The Board of Directors is invested with the fullest powers for 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 company objects, except for the acts that the law or these by-laws reserve for the shareholders’ meeting.
23.2		The Board of Directors is allowed to resolve on the following matters: - the merger and the demerger of at least 90% directly owned subsidiaries; - the establishment and winding up of branches; - the amendment to the by-laws in order to comply with the current legislation.
23.3		The Board of Directors and the Chief Executive Officer report timely, at least every three months and however in the Board of Directors meetings, to the Board of Statutory Auditors on the activities and on the most relevant operations regarding the operational, economic and financial management of the company and its subsidiaries; in particular the Board of Directors and the Chief Executive Officer report to the Board of Statutory Auditors on operations entailing an interest on their behalf or on behalf of third parties.

ARTICLE 24

24.1		The Board of Directors delegates its powers to one of its members with the exception of the Director appointed pursuant to Article 6, second paragraph, letter d) of the by-laws, in compliance with the limits set forth in Article 2381 of the Civil Code. In addition the Board of Directors may delegate powers to the Chairman for researching and promoting integrated projects and strategic international agreements. The Board of Directors may at any time withdraw the delegations of powers hereon; if the Board of Directors withdraws powers delegated to the Chief Executive Officer, a new Chief Executive Officer is simultaneously appointed. The Board of Directors, upon proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for single acts or categories of acts to other members of the Board of Directors with the exception of the Director appointed pursuant to Article 6, second paragraph, letter d) of the by-laws. The Chairman and the Chief Executive Officer, in compliance with the limits of their delegations, may delegate and empower company employees or persons not belonging to the company to represent the company for single acts or specific categories of acts. Further, 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 and determines the powers to be conferred to them. In order to make the appointment effective, the Board of Directors shall verify if the General Manager to be appointed has the honorability requirements set by the current legislation. The Board of Directors shall periodically verify said honorability requirements. The General Managers without said requirement shall be removed. Upon proposal of the Chief Executive Officer presented and in agreement with the Chairman, the Board of Directors appoints the Manager responsible for the preparation of financial reporting documents. The appointment is subject to the favourable opinion of the Board of Statutory Auditors.
		The Manager responsible for the preparation of financial reporting documents is chosen among people who, for at least three years, have exercised:

		a)		administration or control activities or directive tasks in companies listed on regulated stock exchanges in Italy or other European Union countries or other countries member of OECD with a share capital not less than two million euro or
		b)		audit activities in the companies mentioned in letter a) above, or
		c)		professional activities or teaching activities in universities in the financial or accounting sectors, or
		d)		managerial functions in public or private bodies in the financial, accounting, or control sectors.

The Board of Directors assures that the Manager responsible for the preparation of financial reporting documents is given adequate powers and means to execute his or her tasks and to respect the administrative and accounting procedures.

ARTICLE 25

25.1

Legal representation towards any judicial or administrative authority and towards third parties, together with the company signature, are vested either onto the Chairman or the Chief Executive Officer.

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ARTICLE 26

26.1

The Chairman and the members of the Board are remunerated in an amount established by the ordinary shareholders’ meeting. Said resolution, once taken, will remain valid for subsequent business years until the shareholders’ meeting decides otherwise.

ARTICLE 27

27.1

The Chairman:

		a)		represents the company according to the provisions of Article 25.1;
		b)		chairs the shareholders’ meeting pursuant to Article 15.1;
		c)		convenes and chairs meetings of the Board of Directors pursuant to Articles 19.1 and 20.1;
		d)		ascertains whether Board resolutions have been implemented;
		e)		exercises the powers delegated to him by the Board of Directors pursuant to Article 24.1 of these by-laws.

Part VI - Board of Statutory Auditors

ARTICLE 28

28.1		The Board of Statutory Auditors consists of five effective members and two alternate members. The Auditors shall have the professional and honour requirements set forth by the Ministerial Decree No. 162, dated March 30, 2000 issued by the Ministry of Justice. Pursuant to the aforementioned Ministerial Decree, the matters strictly connected to those of interest of the Company are: companies law, business economics and corporate finance. Pursuant to said Ministerial Decree, the sectors strictly connected with those of interest of the Company are the engineering and geological sectors. The Statutory Auditors may be appointed members of administration and control bodies in other companies within the limits set by Consob regulation. Until those provisions do not come in force, those who are already appointed effective auditor or supervisory board member or audit committee member in at least five companies with securities listed on regulated securities markets other than Eni SpA subsidiaries may not be appointed Statutory Auditor; if elected, they will lapse.
28.2		The Board of Statutory Auditors is appointed by the shareholders’ meeting on the basis of lists presented by the Shareholders; in such lists candidates are listed in numerical order. For the presentation, deposit and publication of candidate lists the procedures set forth in Article 17.3 shall apply and according to the rules set forth by Consob. Lists shall be divided into two sections: the first one for the candidates to be appointed effective Auditors and the second one for the candidates to be appointed alternate Auditors. At least the first candidate of each section shall be chartered accountant and have exercised audit activities for not less than three years. Three effective Auditors and one alternate Auditor will be drawn from the list that obtains the majority of votes. The other two effective Auditors and the other alternate Auditor will be appointed pursuant to Article 17.3, letter b) of the by-laws. The procedure described in this last Article shall be applied to each section of the lists involved separately. The shareholders’ meeting appoints the Chairman of the Board of Statutory Auditors among the effective Auditors appointed according to Article 17.3 letter b) of these by-laws. To appoint effective or alternate Auditors for any reason not elected according to the terms of the aforementioned procedure, the shareholders’ meeting will resolve with the majorities prescribed by the law. The vote by list procedure shall apply only in case of appointment of the entire Board of Statutory Auditors. Should an effective Auditor drawn out from the candidate list that receives the majority of votes expressed by the Shareholders be replaced, he will be succeeded by the alternate Auditor drawn out from the same candidate list; should an effective Auditor drawn out from the other candidate list be replaced, he will be substituted by the Alternate Auditor drawn by those other lists.
28.3		Retiring Auditors may be reelected.
28.4		Subject to a previous communication to the Chairman of the Board of Directors, the Board of Statutory Auditors is empowered to convene the shareholders’ meeting and the Board of Directors. At least two effective Auditors are empowered to convene the shareholders’ meetings and at least one effective Auditor is empowered to convene the Board meetings. The Board of Statutory Auditors’ meetings may be held by video or teleconference if each of the participants to the meetings may be identified and if each is allowed to follow the discussion and take part to it in real time. If said conditions are met, the Meeting is 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 business year ends on December 31 every year.

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29.2		At the end of each business year, the Board of Directors sees to the preparation of the company financial statements in conformity with the law.
29.3		The Board of Directors may, during the course of the business year, pay interim dividends to the Shareholders.

ARTICLE 30

30.1

Dividends not collected within five years of the day on which they are payable will be prescribed in favour of the company and 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 will decide the manner of liquidation, appoint one or more liquidators and determine their powers and remuneration.

Part IX - General Provisions

ARTICLE 32

32.1		For matters not expressly regulated by these by-laws, the norms of the Civil Code and specific laws concerning these matters will apply.
32.2		Pursuant to Article 3, paragraph 2, of Law Decree 332 of May 31, 1994, converted with amendments into Law 474 of July 30, 1994, Article 6.1, paragraph sixth, of these bylaws does not apply to the share owned by the Ministry of Economy and Finance, by public bodies or by entities controlled thereby.

ARTICLE 33

33.1

The company retains all assets and liabilities held before its transformation by the public law agency Ente Nazionale Idrocarburi.

 

 

 

 

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EXHIBIT 8

List of Eni’s subsidiaries for year 2008

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
Ieoc SpA		Italy		100.00
Società Oleodotti Meridionali - SOM SpA		Italy		70.00
Società Petrolifera Italiana SpA		Italy		99.96
Stoccaggi Gas Italia SpA - Stogit SpA		Italy		100.00
Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA		Italy		100.00
Agip Caspian Sea BV		Netherlands		100.00
Agip Energy & Natural Resources (Nigeria) Ltd		Nigeria		100.00
Agip Karachaganak BV		Netherlands		100.00
Agip Oil Ecuador BV		Netherlands		100.00
Astrakhan Gas and Oil Co		Russia		3.00
Burren Energy (Bermuda) Ltd		Bermuda		100.00
Burren Energy (Buguruslan) Ltd		Cyprus		100.00
Burren Energy (Congo) Ltd		British Virgin Islands		100.00
Burren Energy Drilling Services Ltd (in liquidation)		UK		100.00
Burren Energy (Egypt) Ltd		UK		100.00
Burren Energy India Ltd		UK		100.00
Burren Energy Ltd		Cyprus		100.00
Burren Energy New Ventures Ltd		UK		100.00
Burren Energy (Oman) Ltd		UK		100.00
Burren Energy Plc		UK		100.00
Burren Energy (Services) Ltd		UK		100.00
Burren Energy (Yemen) Ltd		UK		100.00
Burren Resources Petroleum Ltd		Bermuda		100.00
Burren Shakti Ltd		Bermuda		100.00
Eni AEP Ltd		UK		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		UK		100.00
Eni America Ltd		USA		100.00
Eni Angola Exploration BV		Netherlands		100.00
Eni Angola Production BV		Netherlands		100.00
Eni Australia BV		Netherlands		100.00
Eni Australia Ltd		UK		100.00
Eni BB Petroleum Inc		USA		100.00
Eni Bukat Ltd		UK		100.00
Eni Bulungan BV		Netherlands		100.00
Eni Canada Holding Ltd		Canada		100.00
Eni China BV		Netherlands		100.00
Eni Congo Holding BV		Netherlands		100.00
Eni Congo SA		Congo		100.00
Eni Croatia BV		Netherlands		100.00
Eni Dación BV		Netherlands		100.00
Eni Denmark BV		Netherlands		100.00
Eni Elgin/Franklin Ltd		UK		100.00
Eni Energy Ltd (in liquidation)		UK		100.00
Eni Energy Russia BV		Netherlands		100.00
Eni Ganal Ltd		UK		100.00
Eni Gas & Power LNG Australia BV		Netherlands		100.00

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Eni Grand Maghreb BV		Netherlands		100.00
Eni Hewett Ltd		UK		100.00
Eni India Ltd		UK		100.00
Eni Indonesia Ltd		UK		100.00
Eni International NA NV Sàrl		Luxembourg		100.00
Eni Investments Plc		UK		100.00
Eni Iran BV		Netherlands		100.00
Eni Ireland BV		Netherlands		100.00
Eni JPDA 03-13 Ltd		UK		100.00
Eni JPDA 06-105 Pty Ltd		Australia		100.00
Eni Krueng Mane Ltd		UK		100.00
Eni Lasmo Plc		UK		100.00
Eni LNS Ltd		UK		100.00
Eni Mali BV		Netherlands		100.00
Eni Marketing Inc		USA		100.00
Eni MHH Ltd (in liquidation)		UK		100.00
Eni Middle East BV		Netherlands		100.00
Eni Middle East Ltd		UK		100.00
Eni MOG Ltd (in liquidation)		UK		100.00
Eni Morocco BV		Netherlands		100.00
Eni Muara Bakau BV		Netherlands		100.00
Eni Norge AS		Norway		100.00
Eni North Africa BV		Netherlands		100.00
Eni Oil Algeria Ltd		UK		100.00
Eni Oil do Brasil SA		Brazil		100.00
Eni Oil & Gas Inc		USA		100.00
Eni Oil Holdings BV		Netherlands		100.00
Eni Pakistan Ltd		UK		100.00
Eni Pakistan (M) Ltd Sàrl		Luxembourg		100.00
Eni Papalang Ltd		UK		100.00
Eni Petroleum Co Inc		USA		100.00
Eni Petroleum US Llc		USA		100.00
Eni PetroRussia BV		Netherlands		100.00
Eni Popodi Ltd		UK		100.00
Eni Rapak Ltd		UK		100.00
Eni Resources Ltd		UK		100.00
Eni Securities Ltd		UK		100.00
Eni TNS Ltd		UK		100.00
Eni Trasportation Ltd		UK		100.00
Eni Trinidad and Tobago Ltd		Trinidad & Tobago		100.00
Eni TTO Ltd		UK		100.00
Eni Tunisia BEK BV		Netherlands		100.00
Eni Tunisia BV		Netherlands		100.00
Eni UFL Ltd		UK		100.00
Eni UHL Ltd		UK		100.00
Eni UKCS Ltd		UK		100.00
Eni UK Holding Plc		UK		100.00
Eni UK Ltd		UK		100.00
Eni ULT Ltd		UK		100.00
Eni ULX Ltd		UK		100.00
Eni USA Gas Marketing Llc		USA		100.00
Eni USA Inc		USA		100.00
Eni US Operating Co Inc		USA		100.00
Eni Venezuela BV		Netherlands		100.00
Eni West Timor Ltd		UK		100.00
First Calgary Petroleums LP		USA		100.00
First Calgary Petroleums Ltd		Canada		100.00
First Calgary Petroleums Partner Co ULC		Canada		100.00
First Calgary Petroleums UK Ltd		UK		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
Acqua Campania SpA		Italy		47.62
Compagnia Napoletana di Illuminazione e Scaldamento col Gas SpA		Italy		99.69
Eni Gas & Power Belgium SpA		Italy		100.00
Eni Gas Transport Deutschland SpA		Italy		100.00
Eni Hellas SpA		Italy		100.00
EniPower Mantova SpA		Italy		86.50
EniPower SpA		Italy		100.00
EniPower Trasmissione SpA		Italy		100.00
GNL Italia SpA		Italy		55.59
LNG Shipping SpA		Italy		100.00
Snam Rete Gas SpA		Italy		55.59
Società EniPower Ferrara Srl		Italy		51.00
Società Italiana per il Gas pA		Italy		100.00
Toscana Energia Clienti SpA		Italy		79.22
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana		Slovenia		51.00
Distribuidora de Gas Cuyana SA		Argentina		45.60
Distrigas NV		Belgium		57.24
Distri RE SA		Luxembourg		57.24
Eni Gas & Power Belgium SA		Belgium		100.00
Eni Gas & Power GmbH		Germany		100.00
Eni Gas Transport GmbH (ex Eni Gas & Power GmbH)		Germany		100.00
Eni Gas Transport International SA		Switzerland		100.00
Eni G&P France BV		Netherlands		100.00
Eni G&P Trading BV		Netherlands		100.00
Finpipe GIE		Belgium		36.24
Gas Brasiliano Distribuidora SA		Brazil		100.00
GreenStream BV		Netherlands		75.00
Inversora de Gas Cuyana SA		Argentina		76.00
Société de Financement et de Participation SA		Belgium		57.13
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-Dso Földgázelosztó Korlátolt Felelossegu Tarsasag		Hungary		50.08
Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság		Hungary		50.08
Transfin SA		Belgium		57.13
Trans Tunisian Pipeline Co Ltd		Channel Islands		100.00
REFINING & MARKETING
AgipFuel Nord SpA		Italy		100.00
Agip Rete SpA		Italy		100.00
Costiero Gas Livorno SpA		Italy		65.00
Ecofuel 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
Agip Austria GmbH		Austria		100.00
Agip Benelux BV		Netherlands		100.00
Agip Ceská Republika Sro		Czech Republic		100.00
Agip Deutschland GmbH		Germany		100.00
Agip Ecuador SA		Ecuador		100.00
Agip France Sàrl		France		100.00
Agip Hungaria Zrt		Hungary		100.00
Agip Iberia SLU (ex Eni España Comercializadora de Gas SA)		Spain		100.00
Agip Lubricantes SA		Argentina		100.00
Agip Oil Ceská Republika Sro		Czech Republic		100.00

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Agip Oil Slovensko Spol Sro		Slovakia		100.00
Agip Olaj Magyarország Kereskedelmi Korlátolt Felelõsségû Társaság		Hungary		100.00
Agip Romania Srl		Romania		100.00
Agip Schmiertechnik GmbH		Germany		100.00
Agip Slovenija doo		Slovenia		100.00
Agip Slovensko Spol Sro		Slovakia		100.00
Agip Suisse SA		Switzerland		100.00
American Agip Co Inc		USA		100.00
Eni Trading & Shipping BV (ex Eni Trading BV)		Netherlands		100.00
Eni Trading & Shipping Inc		USA		100.00
Esain SA		Ecuador		100.00
PETROCHEMICALS
Polimeri Europa SpA		Italy		100.00
Dunastyr Polisztirolgyártó Zártkoruen Mukodo Részvénytársaság		Hungary		100.00
Polimeri Europa Benelux SA		Belgium		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		UK		100.00
ENGINEERING & CONSTRUCTION
Intermare Sarda SpA		Italy		43.55
Saipem Energy Italia SpA		Italy		43.55
Saipem Energy Services SpA (ex Energy Maintenance Services SpA)		Italy		43.55
Saipem SpA		Italy		43.55
Snamprogetti Chiyoda SAS di Saipem SpA		Italy		43.51
Snamprogetti Sud SpA		Italy		43.55
Andromeda Consultoria Tecnica e Representações Ltda		Brazil		43.55
BOSCONGO SA		Congo		43.55
BOS Investment Ltd		UK		43.55
BOS - UIE Ltd		UK		43.55
Delong Hersent - Estudos, Construções Maritimas e Participações, Unipessoal Lda		Portugal		43.55
Entreprise Nouvelle Marcellin SA		France		43.55
ER SAI Caspian Contractor Llc		Kazakhstan		21.78
ERS - Equipment Rental & Services BV		Netherlands		43.55
European Marine Contractors Ltd		UK		43.55
European Marine Investments Ltd		UK		43.55
European Maritime Commerce BV		Netherlands		43.55
Frigstad Discoverer Invest Ltd		British Virgin Islands		43.55
Firgstad Discoverer Invest (S) Pte Ltd		Singapore		43.55
Global Petroprojects Services AG		Switzerland		43.55
Katran-K Llc		Russia		43.55
Moss Arctic Offshore AS		Norway		43.55
Moss Maritime AS		Norway		43.55
Moss Maritime Inc		USA		43.55
Moss Offshore AS		Norway		43.55
North Caspian Services Co		Kazakhstan		43.55
Petrex SA		Peru		43.55
Petromar Lda		Angola		30.49
PT Saipem Indonesia		Indonesia		43.55
Saibos Construções Maritimas Ltda		Portugal		43.55
Saigut SA De Cv		Mexico		43.55
Saimexicana SA De Cv		Mexico		43.55
Saipem America Inc		USA		43.55
Saipem Asia Sdn Bhd		Malaysia		43.55
Saipem (Beijing) Technical Services Co Ltd		China		43.55
Saipem Contracting Algerie SpA		Algeria		43.55
Saipem Contracting (Nigeria) Ltd		Nigeria		42.66
Saipem do Brasil Serviçõs de Petroleo Ltda		Brazil		43.55

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Saipem Holding France SAS		France		43.55
Saipem India Projects Ltd (ex Saipem India Project Services Ltd)		India		43.55
Saipem International BV		Netherlands		43.55
Saipem Logistics Services Ltd		Nigeria		43.55
Saipem Luxembourg SA		Luxembourg		43.55
Saipem (Malaysia) Sdn Bhd		Malaysia		18.02
Saipem Maritime Asset Management Luxembourg Sàrl		Luxembourg		43.55
Saipem Mediteran Usluge doo		Croatia		43.55
Saipem Misr for Petroleum Services SAE		Egypt		43.55
Saipem (Nigeria) Ltd		Nigeria		38.94
Saipem Perfurações e Construções Petroliferas Unipessoal Lda		Portugal		43.55
Saipem (Portugal) Comércio Marítimo, Sociedade Unipessoal Lda		Portugal		43.55
Saipem (Portugal) - Gestão de Participações SGPS Sociedade Unipessoal SA		Portugal		43.55
Saipem SA		France		43.55
Saipem Services México SA De Cv		Mexico		43.55
Saipem Services SA		Belgium		43.55
Saipem Singapore Pte Ltd		Singapore		43.55
Saipem UK Ltd		UK		43.55
Saipem Ukraine Llc		Ukraine		43.55
SAS Port de Tanger		France		43.55
Saudi Arabian Saipem Ltd		United Arab Emirates		26.13
Services et Equipements Gaziers et Petroliers SA		France		43.48
Sigurd Rück AG		Switzerland		43.55
Snamprogetti Canada Inc		Canada		43.55
Snamprogetti Engineering BV		Netherlands		43.55
Snamprogetti France Sàrl		France		43.55
Snamprogetti Ltd		UK		43.55
Snamprogetti Lummus Gas Ltd		Malta		43.12
Snamprogetti Management Services SA		Switzerland		43.55
Snamprogetti Netherlands BV		Netherlands		43.55
Snamprogetti Romania Srl		Romania		43.55
Snamprogetti Saudi Arabia Co Ltd Llc (ex Snamprogetti Saudi Arabia Ltd)		United Arab Emirates		43.55
Snamprogetti USA Inc		USA		43.55
Société de Construction d’Oleoducs Snc		France		43.48
Sofresid Engineering SA		France		43.55
Sofresid SA		France		43.55
Sonsub AS		Norway		43.55
Sonsub International Pty Ltd		Australia		43.55
Sonsub Ltd (in liquidation)		UK		43.55
Star Gulf FZ Co		United Arab Emirates		43.55
Varisal - Serviços De Consultadoria e Marketing Lda		Portugal		43.55
OTHER ACTIVITIES
Ing. Luigi Conti Vecchi SpA		Italy		100.00
Syndial SpA - Attività Diversificate		Italy		100.00
CORPORATE AND FINANCIAL COMPANIES
Agenzia Giornalistica Italia SpA		Italy		100.00
Eni Corporate University SpA		Italy		100.00
EniServizi SpA		Italy		100.00
Serfactoring SpA		Italy		48.81
Servizi Aerei SpA		Italy		100.00
Società Finanziamenti Idrocarburi - Sofid - SpA		Italy		99.61
Banque Eni SA		Belgium		100.00
Eni Coordination Center SA		Belgium		100.00
Eni Insurance Ltd		Ireland		100.00
Eni International Bank Ltd		Bahamas		100.00
Eni International BV		Netherlands		100.00
Eni International Resources Ltd		UK		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; and

5.

The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: May 14, 2009

 

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EXHIBIT 12.2

Certification

 

I, Alessandro Bernini, certify that:

1.

I have reviewed this annual report on Form 20-F of Eni SpA;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.

The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.

The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: May 14, 2009

 

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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, 2008 (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: May 14, 2009

 

 

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, 2008 (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: May 14, 2009

 

 

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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