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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, 2009
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
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
————————————————————
Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
                                        Ordinary shares of euro 1.00 each                                                                                                                                                                 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 (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).*

* This requirement does not apply to the registrants until their fiscal year ending December 31, 2011.   Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

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

If "Other" has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

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

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TABLE OF CONTENTS

				Page
Certain Defined Terms				ii
Presentation of Financial and Other Information				ii
Statements Regarding Competitive Position				ii
Glossary				iii
Abbreviations and Conversion Table				vi

I

I

I

III

I

PART I	II	I	II	II
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	20
I	I	History and Development of the Company	I	20
I	I	Business Overview	I	25
I	I	Exploration & Production	I	25
I	I	Gas & Power	I	52
I	I	Refining & Marketing	I	68
I	I	Engineering & Construction	I	76
I	I	Petrochemicals	I	79
I	I	Corporate and Other activities	I	81
I	I	Research and Development	I	81
I	I	Insurance	I	81
I	I	Environmental Matters	I	82
I	I	Regulation of Eni’s Businesses	I	86
I	I	Property, Plant and Equipment	I	97
I	I	Organizational Structure	I	97
Item 4A.	I	UNRESOLVED STAFF COMMENTS	I	98
Item 5.	I	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	I	98
I	I	Executive Summary	I	98
I	I	Critical Accounting Estimates	I	100
I	I	2007-2009 Group Results of Operations	I	104
I	I	Liquidity and Capital Resources	I	114
I	I	Recent Developments	I	120
I	I	Management’s Expectations of Operations	I	122
Item 6.	I	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	I	128
I	I	Directors and Senior Management	I	128
I	I	Compensation	I	132
I	I	Board Practices	I	139
I	I	Employees	I	143
I	I	Share Ownership	I	144
Item 7.	I	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	I	145
I	I	Major Shareholders	I	145
I	I	Related Party Transactions	I	145
Item 8.	I	FINANCIAL INFORMATION	I	146
I	I	Consolidated Statements and Other Financial Information	I	146
I	I	Significant Changes	I	146
Item 9.	I	THE OFFER AND THE LISTING	I	146
I	I	Offer and Listing Details	I	146
I	I	Markets	I	148
Item 10.	I	ADDITIONAL INFORMATION	I	149
I	I	Memorandum and Articles of Association	I	149
I	I	Material Contracts	I	154
I	I	Exchange Controls	I	154
I	I	Taxation	I	155
I	I	Documents on Display	I	159
Item 11.	I	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	I	159
Item 12.	I	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	I	160
12A.	I	Debt Securities	I	160
12B.	I	Warrants and Rights	I	160
12C.	I	Other Securities	I	160
12D.	I	American Depositary Shares	I	160
I	I	I	III	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	II	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	165
16F.	I	Change in Registrant's Certifying Accountant	I	165
16G.	I	Significant Differences in Corporate Governance Practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual	I	165
I	I	I	III	I
PART III	I	I	II	II
Item 17.	I	FINANCIAL STATEMENTS	I	168
Item 18.	I	FINANCIAL STATEMENTS	I	168
Item 19.	I	EXHIBITS	I	168

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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.

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

 

STATEMENTS REGARDING COMPETITIVE POSITION

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

 

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GLOSSARY

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

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

Conversion capacity		Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units.

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

Possible reserves		Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves		Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Primary balanced refining capacity		Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.

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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.
Proved reserves		Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves		Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reserve life index		Ratio between the amount of proved reserves at the end of the year and total production for the year.
Reserve replacement ratio		Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.

Ship-or-pay		Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
Strategic Storage		According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.

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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.

 

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, 2005, 2006, 2007, 2008 and 2009. The selected historical financial data presented herein are derived from Eni’s Consolidated Financial Statements included in Item 18.

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

	Year ended December 31,

	2005		2006		2007		2008		2009

CONSOLIDATED PROFIT STATEMENT DATA
Net sales from operations		73,728			86,105			87,204			108,082			83,227
Operating profit by segment (1)
Exploration & Production		12,592			15,580			13,433			16,239			9,120
Gas & Power		3,321			3,802			4,465			4,030			3,687
Refining & Marketing		1,857			319			686			(988	)		(102	)
Petrochemicals		202			172			100			(845	)		(675	)
Engineering & Construction		307			505			837			1,045			881
Other activities		(934	)		(622	)		(444	)		(346	)		(382	)
Corporate and financial companies		(377	)		(296	)		(312	)		(743	)		(474	)
Impact of unrealized intragroup profit elimination (2)		(141	)		(133	)		(26	)		125
Operating profit		16,827			19,327			18,739			18,517			12,055
Net profit attributable to Eni		8,788			9,217			10,011			8,825			4,367
Data per ordinary share (euro) (3)
Operating profit:
- basic		4.48			5.23			5.11			5.09			3.33
- diluted		4.47			5.22			5.11			5.09			3.33
Net profit attributable to Eni basic and diluted		2.34			2.49			2.73			2.43			1.21
Data per ADR ($) (3) (4)
Operating profit:
- basic		11.14			13.13			14.01			14.97			9.27
- diluted		11.12			13.12			14.00			14.97			9.27
Net profit attributable to Eni basic and diluted		5.82			6.26			7.48			7.14			3.36

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	As of December 31,

	2005		2006		2007		2008		2009

CONSOLIDATED BALANCE SHEET DATA
Total assets		83,850		88,312		101,460		116,673		117,529
Short-term and long-term debt		12,998		11,699		19,830		20,837		24,800
Capital stock issued		4,005		4,005		4,005		4,005		4,005
Minority interest		2,349		2,170		2,439		4,074		3,978
Shareholders’ equity - Eni share		36,868		39,029		40,428		44,436		46,073
Capital expenditures		7,414		7,833		10,593		14,562		13,695
Weighted average number of ordinary shares outstanding (fully diluted - shares million)		3,763		3,701		3,668		3,639		3,622
Dividend per share (euro)		1.10		1.25		1.30		1.30		1.00
Dividend per ADR ($) (3)		2.73		3.24		3.74		3.72		2.91

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(1)		From 2009, gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and settled transactions are reported as items of operating profit. Also results of the gas storage business are reported within the Gas & Power segment reporting unit, as part of the regulated businesses results, following the restructuring of Eni’s regulated gas businesses in Italy. In past years, results of the gas storage business were reported within the Exploration & Production segment. Data for the years ended December 31, 2008 and 2007 have been restated. Prior year data have not been restated.
(2)		This item mainly concerned intra-group sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of the end of the period.
(3)		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 year 2005 have been recalculated accordingly.
(4)		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 2005 through 2008 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 2009 was converted at the Noon Buying Rate recorded on the payment date of the interim dividend (euro 0.50 per share) which occurred on September 24, 2009. The balance of euro 0.50 per share payable on May 24 and May 27, 2010 for the holders of the Eni share and the ADR, respectively, was translated at the Noon Buying Rate as recorded on December 31, 2009. On April 9, 2010 the Noon Buying Rate was $1.35 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, 2005, 2006, 2007, 2008 and 2009. 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,

	2005		2006		2007		2008		2009

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)		3,748		3,457		3,127		3,243		3,377
of which developed		2,331		2,126		1,953		2,009		2,001
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)		25		24		142		142		86
of which developed		19		18		26		33		34
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF)		17,501		16,897		16,549		17,214		16,262
of which developed		11,159		10,949		10,967		11,138		11,650
Proved reserves of natural gas of equity-accounted entities at period end (BCF)		90		68		3,022		3,015		1,588
of which developed		70		48		428		420		234
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)		6,796		6,400		6,010		6,242		6,209
of which developed		4,275		4,032		3,862		3,948		4,030
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end (a)		41		36		668		666		362
of which developed		31		27		101		107		74
Reserve replacement ratio (2)		43		38		38		136		95
Average daily production of liquids (KBBL/d)		1,111		1,079		1,020		1,026		1,007
Average daily production of natural gas available for sale (mmCF/d) (3)		3,344		3,679		3,819		4,143		4,074
Average daily production of hydrocarbons available for sale (KBOE/d) (3)		1,693		1,720		1,684		1,748		1,716
Hydrocarbon production sold (mmBOE)		614.9		625.1		611.4		632.0		622.8
Oil and gas production costs per BOE (4)		5.59		5.79		6.90		7.77		7.49
Profit per barrel of oil equivalent (5)		12.20		14.97		14.03		15.80		7.96

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(a)		Mainly refers to Eni’s share of proved reserves relating to three Russian companies purchased in 2007 and participated by the joint venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%). On September 23, 2009 the two partners divested a 51% stake in the venture to Gazprom in line with the call option arrangement.
(1)		Includes approximately 760, 754, 749, 746 and 769 BCF of natural gas held in storage in Italy as of December 31, 2005, 2006, 2007, 2008 and 2009, respectively.
(2)		Referred to Eni’s subsidiaries. Consists of: (i) the increase in proved reserves of consolidated subsidiaries attributable to: (a) purchases of minerals in place; (b) revisions of previous estimates; (c) improved recovery; and (d) extensions and discoveries, less sales of minerals in place; divided by (ii) production during the year as set forth in the reserve tables, in each case prepared in accordance with Topic 932. See the unaudited supplemental oil and gas information in Item 18 – Notes to the Consolidated Financial Statements. Expressed as a percentage.
(3)		Natural gas production volumes exclude gas consumed in operations (251, 286, 296, 281 and 300 mmCF/d in 2005, 2006, 2007, 2008 and 2009, 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 production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements”.
(5)		Expressed in U.S. dollars. Results of operations from oil and gas producing activities, 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. 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,

	2005		2006		2007		2008		2009

Sales of natural gas to third parties (6)		77.08		79.63		78.75		83.69		83.79
Natural gas consumed by Eni (6)		5.54		6.13		6.08		5.63		5.81
Sales of natural gas of affiliates (Eni’s share) (6)		7.08		7.65		8.74		8.91		7.95
Total sales and own consumption of natural gas of the Gas & Power segment (6)		89.70		93.41		93.57		98.23		97.55
E&P natural gas sales in Europe and in the Gulf of Mexico (6) (7)		4.51		4.69		5.39		6.00		6.17
Worldwide natural gas sales (6)		94.21		98.10		98.96		104.23		103.72
Transport of natural gas for third parties in Italy (6)		30.22		30.90		30.89		33.84		37.27
Length of natural gas transport network in Italy at period end (8)		30.7		30.9		31.1		31.5		31.5
Electricity sold (9)		27.56		31.03		33.19		29.93		33.96
Refinery throughputs (10)		36.68		36.27		37.15		35.84		34.55
Balanced capacity of wholly-owned refineries (11)		524		534		544		544		554
Retail sales (in Italy and rest of Europe) (10)		13.72		12.48		11.80		12.03		12.02
Number of service stations at period end (in Italy and rest of Europe)		6,282		6,294		6,441		5,956		5,986
Average throughput per service station (in Italy and rest of Europe) (12)		2,479		2,470		2,486		2,502		2,477
Petrochemical production (10)		7.28		7.07		8.80		7.37		6.52
Engineering & Construction order backlog at period end (13)		10,122		13,191		15,390		19,105		18,730
Employees at period end (units)		72,258		73,572		75,862		78,880		78,417

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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.
(13)		The sum of the order backlog of Saipem SpA and Snamprogetti SpA, expressed in euro million.

 

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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,
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
2009		1.51		1.25		1.39		1.43

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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 2009		1.51		1.47		1.50
December 2009		1.51		1.42		1.43
January 2010		1.45		1.39		1.39
February 2010		1.40		1.35		1.37
March 2010		1.38		1.33		1.35
April 2010 (through April 9, 2010)		1.36		1.34		1.35

Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on April 9, 2010 was $1.35 per euro 1.00.

 

Risk Factors

Competition

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

Eni faces 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-owned oil companies in a number of geographic markets for obtaining exploration and development rights, and developing and applying new technologies 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 of those competitive pressures, Eni fails to obtain new exploration and development acreage or to apply and develop new technologies, its growth prospects and future results of operations and cash flows may be adversely affected.
•		In its natural gas business, Eni faces increasingly strong competition on both the Italian market and the European market driven by weak prospects for demand growth over the short and medium-term, and increasing gas availability on the marketplace. Significant investments to expand import capacity to Europe via pipeline and LNG have been made by a number of operators including Eni, in recent years. At the same time, forecasts for demand growth in Europe have been overestimated and the economic

 

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		downturn has caused a much larger-than-anticipated demand contraction. As natural gas is a commodity, gas oversupply may lead suppliers to compete more aggressively on pricing thus leading to lower gas margins for the whole sector. The condition of oversupply is signaled by current trends in differentials between spot price and long-term prices for natural gas, whereby the former no longer appear to be correlated to oil-linked formulas that determine gas prices in long-term supply contracts. Management believes that a better balance between demand and supply on the European market will not be achieved until 2013 at the earliest. The circumstances described above might negatively affect the Company’s future results of operations and cash flow in its natural gas business, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of natural gas in accordance to its long-term gas supply contracts that include take-or-pay clauses. See the sector-specific risk section below. In Italy, competitive pressures are fostered by the liberalization of the Italian natural gas market that was mandated 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, and the power of the Italian Authority for Electricity and Gas to regulate natural gas pricing in the residential sector and access to infrastructures. Increasingly high levels of competition in the Italian natural gas market may lead to lower natural gas selling margins (see below). 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.
•		In its domestic electricity business, Eni competes with other producers and traders from Italy or outside of Italy who sell electricity on the Italian market. The Company expects in the near future increasing competition due to the weak GDP growth expected in Italy and Europe over the next one to two years causing outside players to place excess production on the Italian market.
•		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, there is pressure from political and administrative entities, including the Italian Antitrust Authority, to increase 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.
•		In the Petrochemical segment we face intense competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized market segments. Many of those competitors may benefit from cost advantages due to larger scale, looser environmental regulations, availability of oil-based feedstock, and more favorable location and proximity to end-markets. Excess capacity and sluggish economic growth may exacerbate competitive pressures. The Company expects continuing margin pressures in the foreseeable future as a result of those trends.
•		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 lower demand for oil services.

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

 

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.

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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 in 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. In addition, we may fail to secure a market for the quantities of oil and gas that are discovered, for example because there is no economic or practicable means to transport such quantities to the final market. 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. Particularly, Eni plans to explore for oil and gas offshore, frequently in deep waters or at deep drilling depths, where 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. The Company plans to conduct risky exploration projects offshore in the Gulf of Mexico, Libya, Angola, Nigeria, Norway and Indonesia. In 2009, the Company invested euro 1.23 billion in executing exploration projects and it plans to spend approximately euro 1.17 billion per annum on average over the next four years.

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. Certain projects are planned to develop reserves in high risk areas, particularly offshore and in remote and hostile environments. Eni’s future results of operations and liquidity 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 suppliers of goods and services;
•		the ability to design development projects so as to prevent the occurrence of technical inconvenience;
•		delays in manufacturing and delivery of critical equipment, or shortages in the availability of such equipment, causing cost overruns and delays;
•		risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
•		changes in operating conditions and costs. In recent years prior to 2009, we experienced a sharp rise in procurement costs and costs for leasing third party equipment or purchase services such as drilling rigs as a result of industry-wide cost inflation, resulting in cost overruns. Notwithstanding the global economic downturn, costs for industry-specific services and materials and equipment decreased less-than-anticipated or actually increased compared to the previous year as oil prices recovered fairly quickly from the lows seen at the end of 2008 and beginning of 2009. The Company expects that costs in its upstream operations will remain at the same level or post a slightly rising trend in future years compared to the level seen in 2009;
•		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.

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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. Specifically, based on the new plan that was sanctioned by relevant Kazakh Authorities in 2008, the Company increased estimated expenditures to develop the phase 1 of the project from an original amount of U.S. $10.3 billion (Eni’s interest being at the time 18.52%) – subject to adjustment to take into account cost inflation up to 2007 – to a revised expenditure budget 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). Eni will fund those investments in proportion to its participating interest of 16.81%. First oil is expected late in 2012 based on the new plan, while the original development plan that was filed with Kazakh Authorities in 2004 forecast first oil in 2008. The change in production start-up and the relevant cost increase over the original budget were driven by a number of factors including 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. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the Kashagan project.

In 2009, we experienced significant cost overruns to develop our operated Blacktip project, offshore Australia, leading us to record an impairment charge of euro 153 million to take into account the reduced project profitability.

See "Item 4 – Business Overview – Exploration & Production". In the event the Company is unable to develop and operate major projects as planned, particularly if the Company fails to exercise tight control over costs and time schedules, it could incur significant impairment charges associated with costs overruns and project delays in future years with an 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. In addition to being a function of production and new discoveries, the Company’s reserve replacement is also 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 is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditures. In 2009, the Company’s reserve replacement was negatively affected by reduced entitlements in its PSAs for an estimated amount of 100 mmBOE, which was the principal factor leading to a reserve replacement ratio of 95% for Eni’s subsidiaries (meaning that the Company replaced less reserves than those produced). 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.

 

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 fluctuations in future cash flows due to crude oil price movements. As a consequence, Eni’s profitability depends heavily on crude oil and natural gas prices.

Crude oil and natural gas prices are subject to international supply and demand and other factors that are beyond Eni’s control, including among other things:

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(i)		the control on production exerted by OPEC member countries which control a significant portion of the world's supply of oil and can exercise substantial influence on price levels;
(ii)		global geopolitical and economic developments, including sanctions imposed on certain oil-producing countries on the basis of resolutions of the United Nations or bilateral sanctions;
(iii)		global and regional dynamics of demand and supply of oil and gas; 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 flow. In 2009, the average price of the Brent barrel decreased by 36.6% compared to 2008 in dollar terms; gas prices experienced an even sharper decline driven by weak spot prices due to large gas availability on the marketplace. Spot prices of gas at the Henry Hub market, which is a highly liquid spot market in the U.S. declined by 55.4% in dollar terms. As a consequence of those trends in the market benchmarks, realized prices of the Company’s equity oil and gas decreased by 31.2% on average in dollar terms. Reduced prices negatively impacted the operating profit reported by the Exploration & Production segment which was down by 43.8%, or euro 7,119 million from a year ago.

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

 

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 will ultimately be recovered. Additionally, any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition.

 

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. In 2009 management estimates that the tax rate of the Company’s Exploration & Production segment was approximately 60%, representing an increase of an estimated 4% compared to 2008 as a result of new mechanisms that were implemented to calculate income taxes currently payable in a number of non OECD countries, namely Libya. See "Item 5 – Operating and Financial Review and Prospects – Taxation for the year". Management believes that adverse changes are possible in

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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. See "Political considerations" below. 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%, thus reversing a reduction in the statutory tax rate of the same amount that was enacted the previous year. In 2009, the above mentioned 5.5% supplemental tax rate was increased by another percentage point to 6.5% thus bringing the Italian statutory tax-rate to 34%. Also 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 a treaty between Italy and Libya. This tax rate increased tax payables by approximately euro 239 million for the full year 2009.

Adverse changes in the tax rate applicable to the Group profit before income taxes would have a negative impact 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 decrease 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. As of December 31, 2009, 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 2009, approximately 60% 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. Eni is facing increasing competition from state-owned oil companies who are partnering with Eni in a number of oil and gas projects and titles in the host countries where Eni conducts its upstream operations. These state-owned oil companies can change contractual terms and other conditions of oil and gas projects in order to obtain a larger profit share from a given project, thereby reducing Eni’s profit share. For example, Sonatrach, the Algerian 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 country’s tax regime. In case those negotiations result 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". Furthermore, in 2009 we recorded a loss amounting to euro 205 million on certain receivables versus local co-venturers as certain contractual clauses relating to cost recovery were unfavorably interpreted and applied. As of the balance sheet date receivables for euro 461 million relating to cost recovery under a petroleum contract in a non-OECD country were the subject of arbitration proceedings. Similar issues are also being experienced in Kazakhstan where there is a dispute in relation to certain unresolved items of expenditure incurred by the operating company Karachaganak Petroleum Operating BV which has led to the Kazakh Authorities making certain claims against the company on the base of audits performed relating to prior years 2003-2006. Parties are negotiating in order to settle the dispute;
(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 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 2009, security problems have continued to impact our operations. See "Item 4 – Exploration & Production".

In 2008 we incurred asset impairments for euro 989 million in our Exploration & Production business mainly driven by changes in contractual arrangements and regulatory provisions and environmental obligations leading the

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Company to reassess the recoverable amounts of a number of its oil and gas properties, particularly in Turkmenistan.

See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves". While the occurrence of those events is unpredictable, it is likely that the occurrence of such events could cause Eni to incur material losses or facility disruptions, by this way adversely impacting Eni’s results of operations and cash flows.

 

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 contemplates sanctions to be imposed by the President of the United States 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 10 years. Management may decide to invest amounts in excess of $20 million per year in the country in the future. No sanctions have been imposed to date on Eni’s activities in the country. Eni’s current activities in Iran are primarily limited to carrying out residual activities relating to certain buy-back contracts it entered into in 2000 and 2001. Specifically, activities are progressing to hand over operatorship of the Darquain oilfield to the local partners as development activities were concluded at this field in 2009. Darquain remained the sole activity operated by Eni in the Country. Regarding another project that was handed over in past years, Eni’s involvement consists essentially in being reimbursed for its past investments. In 2009, Eni’s production in Iran was 35 KBOE/d, approximately 2% of the Group’s total production. Eni does not believe that its activities in Iran have a material impact on the Group’s results.

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 – Rest of Asia". 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 or limit investment by certain investors in our securities and so possibly impact adversely our share price.

 

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand in response to economic cycles, 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, intense competitive pressures and excess installed production capacity. Furthermore, Eni’s petrochemical operations face increasing competition from Asian companies and national oil companies’ petrochemical divisions which can leverage on long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. Particularly, Eni’s petrochemical operations are located mainly in Italy and Western Europe where the 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. Additionally, our petrochemical operations lack sufficient scale and competitiveness in a number of sites. Due to weak industry fundamentals, intense competitive pressures and high feedstock costs, our petrochemicals operations incurred operating losses in both 2009 and 2008 of euro 675 million and euro 845 million, respectively. Results were also affected by the recognition of impairment losses amounting to euro 121 million and euro 278 million respectively as recoverable amounts of certain petrochemicals plants were

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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. Management does not expect any significant recovery in industry fundamentals and the trading environment for 2010, making it likely that further operating losses will be incurred.

 

Risks in the Company Gas & Power business segment

i) Market risks

In 2009 the Company’s results of operations and cash flow were negatively affected by the severe contraction in gas demand due to the economic downturn and increasing competitive pressures resulting from large gas availability on the market place

In 2009 European gas demand was severely impacted by the economic downturn, as a fall in both producing activities and demand for electricity reduced gas consumption. European gas demand decreased by 7.4% from 2008, excluding seasonal effects. The Italian market was particularly hit by the downturn as demand fell by approximately 9 BCM from 2008, down 10%, and almost 10 BCM from the pre-crisis levels seen in 2007, down 12%, excluding seasonal effects. At the same time, new gas supplies entered the market as several operators, including Eni, completed plans to upgrade gas import pipelines from gas producing countries or projects to build new facilities to import gas to Europe via LNG carriers. In particular, Eni finalized plans to upgrade the import capacity of its two main pipelines from Russia and Algeria increasing capacity by an overall amount of 13 BCM/y (the gas pipelines TAG and TTPC), with new capacity entirely sold to third parties. A new LNG terminal with a capacity of 8 BCM/y commenced operations late in 2009, operated by a consortium of competitors. As a result, gas availability on the Italian market increased at a time when demand actually shrunk, resulting in oversupply. Accordingly, Eni’s results of the gas marketing business, sales volumes and average gas selling margins¹ were driven down by rising competition and weak demand both in Italy and Europe. Large gas availability on other European markets also prevented the Company from disposing of part of its gas availability by selling it on European markets. This situation was exacerbated by lower gas consumption in the U.S. driven by the economic downturn and recent developments in extracting gas by unconventional sources. As a result of these trends, large amounts of LNG were re-directed towards Europe. The condition of oversupply on the European market is signaled by the circumstance that gas spot prices no longer appear correlated to trends in oil prices. This trend has resulted in Eni being less competitive as its supply costs are based on the price formulas of long-term supply agreements which link the price of gas to the price of oil.

 

The outlook for the European gas sector is challenging as current imbalances between demand and supply in Europe and Italy might negatively affect the Company’s results of operation and cash flows in future years

The outlook for gas supply and demand both in Europe and Italy is challenging as GDP growth in the EU 27 Countries is expected to remain weak over the next few years and gas demand is expected to recover only gradually to pre-crisis levels. Currently, management does not expect that demand will recover to 2008 levels before 2013 and expects gas prices on spot markets to remain depressed for another one or two years. Gas availability will remain abundant on the marketplace as the Company expects that new infrastructures will be finalized over the next five to ten years, as publicly announced by certain consortia of competitors. In particular, it has been announced that a new pipeline will be built from Algeria to Italy via Sardinia with a 5 BCM capacity and a new LNG terminal will be started up in a yet to be identified location in Italy with 8 BCM capacity.

In addition, ongoing trends towards energy preservation and rising competition from renewable or alternative sources of energy will further dampen the recovery perspectives of gas demand. Specifically, at the March 2007 European Council, the European Heads of Government decided to adopt the Climate Action and Renewable Energy Package. This legislation was voted into law by the European Parliament in December 2008. The package, also known as "20-20-20 European Policy", includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as an improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020. To factor in those trends, management has revised downwards its long-term projections of both European and Italian gas demand growth. For further information see "Item 4 – Gas & Power". The expected sluggish growth of demand, coupled with ample gas availability on the marketplace may adversely affect the Company’s results of operations and cash flow in its gas marketing business in future years.

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

In order to secure long-term access to gas availability, particularly with a view to supplying the Italian gas market, the Company signed in the past a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts will ensure approximately 62.4 BCM of gas availability in 2010 (excluding the contribution of other subsidiaries and associates), have a residual life of approximately 20 years, and provide take-or-pay clauses whereby the Company is required to off-take minimum predetermined volumes of gas each year of the contractual term or, in case of failure, to pay the whole price, or a portion of it, up to the minimum contractual quantity. The take-or-pay clause entitles the Company to off-take pre-paid volumes of gas in later years during the term of the contract execution. The amount of price that is required being paid in advance and the schedules for off-taking pre-paid gas vary from contract to contract. Generally speaking, cash pre-payments are calculated on the basis of the energy prices prevailing in the year of non-fulfillment with the balance due in the year when the gas is actually off-taken. Amounts of pre-payments range from 10 to 100 percent of the full price. Right to off-take pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements.

In addition, rights to off-take pre-paid gas in future years can only be exercised if the Company has fulfilled its minimum take obligation in a given year. In this case, Eni will pay the residual price for the gas that was not off-taken initially based on a purchase price calculated as average of market prices prevailing in the year when the gas is actually off-taken. Similar considerations apply to ship-or-pay contractual obligations.

Management believes that the current outlook for gas demand and large gas availability on the marketplace, as well as the possible evolution of sector-specific regulation, present significant risks to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts.

In accordance with the terms of its long-term supply contracts, in 2009 Eni off-took lower volumes than the contractual minimum and recognized a trade payable amounting to euro 255 million corresponding to the amount of gas that the Company was required contractually to off-take.

Management believes that over the next two years the Company will experience failure to fulfill its take-or-pay obligations with respect to significant volumes of gas, unless demand fundamentals improve substantially and a better balance between demand and supply is achieved on the marketplace.

If Eni fails to off-take the contractual minimum amounts, it will be exposed to a price risk, because the purchase price Eni will ultimately be required to pay is based on prices prevailing after the date on which the off-take obligation arose. In addition, Eni is subject to the risk of not being able to dispose of pre-paid volumes. The Company also expects to incur financing costs to pay cash advances corresponding to contractual minimum amounts. As a result, the Company’s selling margins, results of operations and cash flow may be negatively 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 2009. Should Eni fail to increase natural gas sales in Europe as planned due to poor strategy execution or competition, Eni’s future growth prospects, results of operations and cash flows might be adversely affected also taking account that Eni might be unable to fulfill its contractual obligations to purchase certain minimum amounts of natural gas based on its take-or-pay purchase contracts currently in force.

 

ii) Risks associated with sector-specific regulations in Italy

The opening of the Italian natural gas market as per Legislative Decree No. 164/2000 has gradually increased competition on the market thus reducing margins

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. Specifically, these antitrust thresholds are effective until December 31, 2010 and prescribe that: (i) operators transmit a volume of imported or domestically produced gas into the national

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transport network which shall not be higher than a predetermined 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; and (ii) 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.

These antitrust thresholds enabled new competitors to enter the Italian gas market, resulting in declining selling margins on gas. In addition, certain competitors of Eni are supplied by the Company itself, generally on the basis of long-term contracts. This is a result of the fact that, 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.

 

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

The Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing. Specifically, the Authority for Electricity and Gas holds a general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users consuming less than 200,000 CM/y (qualified as non eligible customers as of 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. 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 that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account of the new indexation mechanism of the raw material cost component. This indexation mechanism has been recently updated based on Resolution No. 64/2009 of the Authority, which provides that changes in a preset basket of hydrocarbons are transferred to the cost of the supply to those customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. The Company does not expect any material impact following enactment of Resolution No. 64/2009.

However, management cannot exclude the possibility that in the future the Authority could implement measures in this matter which may negatively affect Eni results of operations and liquidity. On March 26, 2010 the Authority for Electricity and Gas published a consultation document regarding certain proposed amendments to the current mechanism that is used to update the raw material cost component in supplies to residential users. The document addresses Italian gas importers, including Eni. The Authority reaffirmed its belief that such cost component should continue being linked to supply prices as provided by the long-term contracts held by Eni as the incumbent operator in the Italian gas market, as evidence suggests that there have not been sufficiently liquid spot markets in Italy. However, the Authority considers that Eni still holds as large market power as to influence wholesale gas prices. Based on that belief, the Authority suggests that the incumbent operator disposes of predetermined amounts of gas at preset economic conditions that take into account the supply costs of an efficient portfolio of long-term supply contracts which could be lower than current wholesale prices realized by Eni. Alternatively, those gas disposals might be in favor of an independent buyer for amounts that might possibly cover the entire capacity of the wholesale market in Italy. Those proposals require establishment of adequate rules by relevant administrative authorities. In case the rules are not implemented, the Authority plans to continue updating the raw material component in supplies to residential customers on the base of the current updating mechanism as it schedules to do in the fourth quarter of 2010. The eventual update will take into account of any effects associated with ongoing renegotiations of long-term supply contracts and may lead to lower wholesale gas prices.

 

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

Other risk factors deriving from the regulatory framework are associated with the regulation of the access to the Italian gas transport network that is currently set by Decision No. 137/2002 of the Authority for Electricity and Gas. The decision is fully incorporated into the network code presently in force as prepared by the system’s operator. The

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decision sets priority criteria for transport capacity entitlements at points where the Italian transport network connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, operators that are holders of take-or-pay contracts, as in the case of Eni, are entitled to a priority in allocating available transport capacity within the limit of average daily contractual volumes. Gas volumes exceeding average daily contractual volumes are not entitled to any priority and, in case of congestion at any entry points, they are entitled available capacity on a proportionate basis together with all pending requests for capacity assignments. Under its take-or-pay purchase contracts, Eni has the right to off-take daily volumes larger than average daily contractual volumes. This flexibility is important to Eni’s commercial programs as it is used when demand peaks, usually during the wintertime. In the event congestion occurs at entry points to the Italian transport network, based on current regulations, 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. However, in planning its commercial flows, the Company normally assumes to make full use of its contractual flexibility and to obtain all necessary capacity entitlements at the entry points to the national transport network. Those assumptions may be inconsistent with rules sets by Decision No. 137/2002 specifically with regard to priority criteria governing capacity entitlements. Eni considers Decision No. 137/2002 to be illegitimate as it is, in Eni’s view, in contrast with the rationale of the European regulatory framework on the gas market as provided in European Directive 03/55/CE. The Company based on that belief has commenced an administrative procedure to repeal Decision No. 137/2002 before an administrative court which recently confirmed in part Eni’s position. An administrative appeals court also confirmed the Company’s position. Specifically, the Court stated that the purchase of the contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in access to the network, also in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure such to impairing Eni’s marketing plans. Management cannot predict a final outcome of this proceeding. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power".

Management also believes that Eni’s results of operations and cash flows could be adversely affected should a combination of market conditions and regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill its minimum take contract obligations. See "Item 5 – Management Expectations of Operations".

 

A number of mandatory gas release measures have been recently implemented in Italy resulting in a negative impact on Eni’s results of operations and liquidity. Management cannot exclude that similar measures will be implemented in future years

Gas release measures are administrative acts whereby Eni is obliged to dispose of certain amounts of gas at set prices and conditions as provided in the relevant gas release measure. Those measures are intended to increase flexibility and liquidity in the gas market. This measure strongly affected Eni’s marketing activity in Italy. In 2004, based on certain agreements with the Antitrust Authority, Eni released in a four-year period a total amount of 9.2 BCM (2.3 BCM/y between October 1, 2004 and September 30, 2008) and the related transport capacity. In addition, in 2007 Eni agreed to adhere to a new gas release program involving 4 BCM which were disposed of in a two-year period (from October 1, 2007 and September 30, 2009). For thermal year 2009/2010 Italian Law No. 99/2009 introduced a new obligation for Eni to make additional sales for a total of 5 BCM of gas in yearly and half-yearly amounts. Although the allotment procedure (bid) was based on a minimum price set by the Ministry for Economic Development as proposed by the Authority for Electricity and Gas only a 1.1 BCM portion of the gas release was awarded out of the 5 BCM which had been planned. The price set by the Ministry is lower than the average price of Eni’s sales in Italy.

For the next few years, based on indications made by the AEEG (in a report to the Parliament on the situation of the gas and electricity market in Italy as provided in Resolution PAS 3/2010), Eni cannot exclude the possibility that new gas release programs will be imposed on it. As a consequence, future results and cash flows could be negatively affected.

 

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 administrative and governmental institutions 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

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matter. For a full discussion of laws and procedures described herein see "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power".

Italian Parliament is required to enact the third European Directive on the gas market No. 73 by March 2011. The Directive prescribes that member states choose one of two options for ensuring carriers’ independence in case transport systems belong to a vertically integrated company. One of these options provides that a parent company involved in both gas production and marketing and transport divests its interests in the carrier subsidiary. Eni currently owns a majority stake in the Italian carrier company Snam Rete Gas which owns and manages approximately 97% of the Italian natural gas transport infrastructure (Eni’s share being 52.54%). Following an internal reorganization, Snam Rete Gas also manages all of Eni’s activities in the distribution sector and in storage. See "Item 4 – Gas & Power – Reorganization of the regulated businesses in Italy". Eni is not able to predict developments on this matter.

Also in 2003, Law No. 290 was enacted in Italy which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 52.54% interest in Snam Rete Gas). 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-scheduled in a 24-month deadline following enactment of the decree from the Italian Prime Minister. Currently, Eni is unable to predict a deadline for this disposal.

In recent years, both the Italian Authority for Electricity and Gas and the Italian Antitrust Authority (the "Antitrust Authority") have conducted several reviews and inquiries on the Italian natural gas market, targeting the overall level of competition of the Italian natural gas market, the degree of opening to competition of the residential sector, levels of entry-exit barriers, and other areas such as sub-investment in the storage sector. Virtually the entire storage capacity belong to Eni through its indirect interest in Stoccaggi Gas Italia SpA, which is wolly owned by Snam Rete Gas SpA. In 2009, the Italian Antitrust commenced an inquiry targeting the possible existence of entry barriers in the residential sector and alleged anti-competitive practices on the part of sellers which are integrated in the activity of gas distribution, including Eni and the subsidiary Italgas (which is wolly owned by Snam Rete Gas SpA). See Note 28 to the Consolidated Financial Statements for a full description of such proceeding. Both the Authority for Electricity and Gas and the Antitrust Authority both believe that the vertical integration of Eni in the supply, transport, distribution, storage and marketing of gas may hamper the development of competition 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.

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 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 the fact that Eni is the incumbent operator in those markets in Italy and a large European gas player. See Note 28 to the Consolidated Financial Statements for a full description of Eni’s main pending antitrust proceedings. Our main antitrust matter relates to an ongoing proceeding before the European Commission with respect to alleged anti-competitive practices designed to harm competition in the European gas market in violation of Article No. 82 of the EU Treaty and Article No. 54 of the SEE. The proceeding involved Eni and other European players. Eni received a statement of objections from the European Commission which alleged that during the 2000-2005 period Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas, thus restricting gas availability in Italy. On February 4, 2010, Eni formally submitted the European Commission a set of structural remedies relating certain international gas pipelines. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test, Eni will be in the position to settle the matter without imposition of any fine or other remedial measures.

Based on available information and its knowledge of the proceeding, the Company is currently unable to determine the outcome of the matter.

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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. Generally, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining, petrochemicals and other Group operations, limit or prohibit drilling activities in certain protected areas, provide for measures to be taken to protect the safety of the workplace and health of communities involved by the company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees or communities health and safety resulting from oil, natural gas, refining, petrochemical and other Group’s operations.

These laws and regulations also regulate emissions of substances and pollutants, handling of hazardous materials and discharges to surface and subsurface water resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Breach of environmental, health and safety laws 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 current and proposed fuel and product specifications, emission controls and implementation of increasingly strict measures decided at both international and country level to reduce greenhouse gas emissions. For more discussion about this topic see "Item 4 – Environmental regulations".

 

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's belief that Eni adopts high operational standards to ensure safety of its operations and to protect the environment and health of people and employees, it is possible that incidents like blow-outs, spill-overs, contaminations and similar events could occur that would result in damage to the environment, employees and communities. Environmental laws also require the Company to remediate and clean-up the environmental impacts of prior disposals or releases of chemicals or petroleum substances and pollutants by the Company. Such contingent liabilities may exist for various sites that the Company disposed of, closed or shut-down in prior years where the Group products have been produced, processed, stored, distributed or sold, such as chemicals plants, mineral-metallurgic plants, refineries and other facilities. Particularly, Eni is performing a number of remedial plans to restore and clean-up certain industrial sites that were contaminated by the Group’s industrial activities in previous years, mainly in Italy. Remedial actions are expected to continue in the foreseeable future, impacting our liquidity as 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. In 2009, the Company’s environmental provision increased by euro 280 million.

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 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

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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; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of future environmental restoration and remediation programs are often inherently difficult to estimate.

 

Legal Proceedings

Eni is party to a number of civil actions and administrative proceedings arising in the ordinary course of business. In 2009, we increased our legal proceeding provision by euro 372 million due to the estimated probable losses associated with ongoing litigations. Of that amount, euro 250 million related to the possible resolution of the investigation related to the TSKJ consortium based on the current status of the ongoing discussions with U.S. Authorities. The matter is fully disclosed in the section "Legal Proceedings" in Note 28 to the Consolidated Financial Statements. This estimate in particular should be read in light of the qualifications set forth in the last sentence of this paragraph. In addition to existing provisions accrued as of the balance sheet date to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate.

 

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 in part 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 residential customers in Italy in accordance with applicable regulations from the Italian Authority for Electricity and Gas. 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.

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

Results of operations of the 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 represents a cost advantage when market prices of heavy crudes are relatively cheaper than the marker Brent price. In 2009, Eni refining margins decreased substantially due to the rapid recovery in oil prices which the Company was unable to transfer on to final prices of refined products due to weak demand, high worldwide and regional inventory levels and excess refining capacity. Also, Eni’s results of operation in its refining segment were affected by narrowing differential between heavy and light crude qualities resulting in poor margins on complex throughputs. Management does not expect any significant recovery in industry fundamentals in 2010. The sector as a whole will continue to suffer from weak demand and excess capacity, while the cost of oil feedstock is seen rising and price differentials to remain compressed. In this context, management expects that the Company refining margins will remain at below break-even levels.

 

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 2009, the profitability of Eni’s petrochemical segment was significantly affected by lower selling margins for commodity petrochemical products due to high purchase costs for oil-based feedstock that were not fully transferred to selling prices of products, as well as weak demand and competitive pressures. These negative factors also triggered asset impairments. Management’s outlook for 2010 remains challenging, as industry fundamentals are not expected to improve substantially. Weak demand, competition, and high oil-based feedstock costs will continue to negatively affect Eni’s results of operations and liquidity in this business segment.

 

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 – an important risk, among other matters, that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. We also 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 not experienced in the past 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. In 2009 Consolidated Financial Statements we made a further allowance for doubtful accounts amounting to euro 260 million, mainly relating to the Gas & Power business. Management believes that the Gas & Power business is particularly exposed to the ongoing impacts of the economic and financial crisis due to its large and diversified customer base which include a large number of middle and small businesses and retail customers.

 

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

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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. This trend reversed in 2009 resulting in an addition to reported operating profit which was estimated in euro 500 million.

 

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.

 

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, power generation, petrochemicals, oilfield services and engineering industries. Eni has operations in 77 countries and 78,417 employees as of December 31, 2009.

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.

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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.com.

The name of the agent of Eni in the United States is De Luca Vincenzo, 485 Madison Avenue, New York, NY 10002.

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations in 40 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia and Australia. In 2009, Eni produced 1,716 KBOE/d on an available for-sale basis. As of December 31, 2009, Eni’s total proved reserves of subsidiaries stood at 6,209 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 362 mmBOE. In 2009, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 23,801 million and operating profit of euro 9,120 million.

Eni’s Gas & Power segment engages in supply, transport, distribution, storage, re-gasification and marketing of natural gas, electricity and LNG. This segment also includes the activity of power generation that is ancillary to the marketing of electricity. In 2009, Eni’s worldwide sales of natural gas amounted to 103.72 BCM, including 6.17 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S. Sales in Italy amounted to 40.04 BCM, while sales in European markets were 55.45 BCM that included 10.48 BCM of gas sold to certain importers to Italy. In 2009, following the reorganization of the regulated businesses the parent company Eni SpA concluded the sale of the entire share capital of its fully-owned subsidiaries Italgas SpA and Stoccaggi Gas Italia SpA to its 52.54 per cent-owned subsidiary Snam Rete Gas.

Through Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,531-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. Snam Rete Gas, through its 100 percent-owned subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,322 municipalities through a low pressure network consisting of approximately 49,973 kilometers of pipelines as of December 31, 2009. Snam Rete Gas, through its wholly-owned subsidiary Stoccaggi Gas Italia operates in natural gas storage activities in Italy through eight storage fields. Eni produces power and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of 5.3 GW as of December 31, 2009. In 2009, sales of power totaled 33.96 TWh. Eni operates a re-gasification terminal in Italy and holds indirect interest or capacity entitlements in a number of LNG facilities in Europe, Egypt and in certain projects under construction in the U.S. In 2009, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 30,447 million and operating profit of euro 3,687 million.

Eni’s Refining & Marketing segment engages in refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2009, processed volumes of crude oil and other feedstock amounted to 34.55 mmtonnes and sales of refined products were 45.59 mmtonnes, of which 26.68 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.02 mmtonnes including Italy and the rest of Europe. In 2009, Eni’s retail market share in Italy through its Agip-branded network of service stations was 31.5%. In 2009, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 31,769 million and operating net loss of euro 102 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 2009, Eni sold 4.3 mmtonnes of petrochemical products. In 2009, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 4,203 million and an operating net loss of euro 675 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 2009, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 9,664 million and operating profit of euro 881 million.

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

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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 2009 economic downturn and uncertain perspectives for global energy demand. Specifically, the Company is planning for:

•		growing profitably oil and gas production in the Exploration & Production business;
•		preserving profitability in the Gas & Power business by leveraging on the Company’s competitive position on the European market in spite of an uncertain demand outlook and increasing competition;
•		improving profitability and cash generation in the Refining & Marketing business by implementing cost reduction initiatives and tightly selecting our capital projects in the face of a difficult trading environment, also boosting profitability of marketing operations;
•		improving revenues and profitability in our Engineering & Construction business leveraging on our strong order backlog and technologically-advanced assets; and
•		managing efficiently and effectively our petrochemicals business.

In executing this strategy, management intends to pursue integration opportunities among businesses and within them and to strongly focus on efficiency improvement through technology upgrading, cost efficiencies, commercial and supply optimization and continuing process streamlining across all businesses. Over the next four-years, Eni plans to execute a capital expenditure program amounting to euro 52.8 billion to support continuing organic growth in its businesses. In 2010, Eni plans to invest approximately euro 14 billion, an amount roughly in line with 2009. Eni plans to fund those capital expenditure plans mainly by means of cash flows provided by operating activities. Capital projects will be assessed and implemented in accordance with tight financial criteria. Those will be the levers whereby the Company intends to preserve a solid capital structure targeting an optimal mix between net borrowings and shareholders’ equity. The Company intends to remunerate its shareholders through a progressive dividend policy. In 2010 management plans to distribute a dividend in line with 2009. In subsequent years, dividends are planned to be increased in line with OECD inflation. This dividend policy is based on the Company’s planning assumptions of Brent oil prices at $65 per barrel flat in the next four years and other assumptions (see “Item 5 – Management’s Expectations of Operations” and “Item 3 – Risk Factors”).

Further details on each business segment strategy are discussed throughout this item. For a description of risks and uncertainties associated with the Company’s outlook and the capital expenditure program see "Item 5 – Management of Expectations of Operations".

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.4 billion 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 2009 and to date in 2010 were the following:

•		In January 2010, Eni leading a consortium of international companies and the Iraqi National Oil Companies, South Oil Co and Missan Oil Co signed a technical service contract, under a 20-year term with an option for further 5 years, to develop the Zubair oil field (Eni 32.8%). The field was awarded in October 2009 to the Eni-led consortium following a successful first bid round and was offered under a competitive bid starting on June 30, 2009. The partners of the project plan to gradually increase production to a target plateau level of 1.2 mmBOE/d by 2016. The contract provides that the consortium will earn a remuneration fee on the incremental oil production once production has been raised by 10 percent from its current level of approximately 180,000 BBL of oil per day and will recover its expenditures through a cost recovery mechanism based on the revenues from the field production.
•		In January 2010, Eni and the Venezuelan National Oil Company PDVSA signed an agreement for the joint development of the giant field Junin 5 with 35 BBBL of certified heavy oil in place, located in the Orinoco oil belt. Production start-up is planned for 2013 at an initial level of 75 KBBL/d and a long term production plateau of 240 KBOE/d is targeted. Development will be conducted through an "Empresa Mixta" (Eni 40%, PDVSA 60%). At the time of the establishment of the Empresa Mixta Eni will disburse a bonus of $300 million, and further $346 million will be paid upon the achievement of certain project milestones. The agreement also includes an option to deploy Eni’s proprietary technology in hydrogenation for the conversion of heavy oils. Finally, Eni will present a project for the construction of a power plant in the Guiria peninsula.

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•		In April 2009, Gazprom exercised its call option to purchase a 20% interest in OAO Gazprom Neft held by Eni based on the existing agreements between the two partners. The exercise price of the call option collected by Eni on April 24, 2009 amounting to euro 3,070 million is equal to the price ($3.7 billion) outlined in the bid procedure held on April 4, 2007 for the assets of bankrupt Russian company Yukos as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and financing collateral expenses. A gain amounting to euro 172 million was recognized in the profit of the period as remuneration of the capital invested and recovery of collateral expenses.
•		In September 2009, Eni and its Italian partner Enel in the 60-40% owned joint-venture OOO SeverEnergia completed the divestment of a 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. Eni collected euro 155 million (or $230 million at the EUR/USD exchange rate of 1.48 as of the transaction date) corresponding to approximately 25% of the whole amount of the transaction ($940 million net to Eni). The remaining 75%, amounting to euro 526 million (or approximately $710 million at the EUR/USD exchange rate of 1.35 as of the transaction date) was collected on March 31, 2010. A gain amounting to euro 100 million was recognized in the profit for the year 2009. The gain was associated with interest income at an annual rate of 9.4% accruing on the initial investment in the venture when it was acquired on April 4, 2007 based on the contractual arrangements between Eni and Gazprom. The three partners are committed to producing first gas from the Samburskoye field by June 2011, targeting a production plateau of 150 KBOE/d within two years from the start of production.

In addition, in 2009 Eni closed the following transactions:

•		In February 2009, Eni signed the project for the feasibility study addressing the utilization of associated gas feeding a new onshore power plant and upstream sector initiatives in the Angola onshore basins, as well as other projects in sustainability. Similar agreements were made in Egypt, the Democratic Republic of Congo and Pakistan.
•		On May 12, 2009 Eni and the Ministry for Oil of Egypt agreed on a ten-year extension of the concession for the giant Belayim field. Eni will invest approximately $1.5 billion over the next five years to execute development expenditures, upgrading actions and operating costs.
•		On May 15, 2009 Eni and Gazprom have agreed upon a new scope of work in the development project of the South Stream pipeline, aimed at increasing its transport capacity from an originally planned amount of 31 BCM/y to 63 BCM. Eni and Gazprom confirmed their full commitment to developing the project which, if the ongoing feasibility study produces a positive outcome, will build a new route to supply Russian gas to Europe.
•		In June 2009, Eni finalized the acquisition from Quicksilver Resources Inc of a 27.5% interest in the Alliance area, in Northern Texas, covering approximately 53 square kilometers, with gas shale reserves. Quicksilver will retain the 72.5% of the interests and operatorship of the properties. The cash consideration for the transaction amounted to $280 million. The expected production from the acquired assets will amount to 4,000 BOE/d net to Eni for the full year 2009, ramping up to approximately 10,000 BOE/d by 2011.
•		In October 2009, Eni and its commercial partners in Turkey and Russia, working on the construction of the Samsun-Ceyhan pipeline, signed a Memorandum of Understanding committing to discuss the definition of the economic and contractual conditions for Russian companies to participate in the Samsun-Ceyhan Project in order to ensure the volume of crude that would guarantee the economic sustainability of the project. On the same occasion, representatives of the governments of Italy, Turkey and Russia reaffirmed their support to the project which will build a by-pass to facilitate safer transport across the Bosphorus and Dardanelles Straits as well as reduce the impact on the region’s complex and delicate ecosystem.
•		In November 2009, Eni was awarded a 37.8% stake in the Indonesian Sanga Sanga license for the production of coal bed methane. Recent preliminary studies in the block showed a resource potential of about 3,920 BCF of gas to be verified through an appraisal program that will commence in 2010.
•		In November 2009, Eni and the Kazakh National Oil Company KazMunayGas signed a co-operation agreement for initiatives in the fields of developing, explorating and producing hydrocarbon resources and industrial facilities in the Country. Under the agreement, Eni and KazMunayGas will jointly execute exploration studies, studies for the optimization of gas usage in Kazakhstan and the evaluation of a number of industrial initiatives including the upgrading of the Pavlodar refinery, in which KMG holds a majority interest.
•		In December 2009, Eni signed a memorandum of understanding with Turkmenistan aimed at promoting and reinforcing the partnership in the development of the oil industry of the Country. Eni will co-operate with the State companies and Agency for Hydrocarbons to carry out studies to ascertain the oil and gas potential of the country. Eni will contribute its expertise in technology and the sustainability field.
•		In January 2010, Eni signed an agreement for the acquisition of a number of marketing activities of refined products in Austria, including a retail network of 135 service stations, wholesale activities as well as commercial assets in aviation business and complementary logistic and storage activities. The finalization of the transaction is subject to the approval of the relevant antitrust authorities.

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In 2009, capital expenditures amounted to euro 13,695 million, of which 86% related to the Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 7,478 million) deployed mainly in Kazakhstan, the United States, Egypt, Congo, Italy and Angola, and exploration projects (euro 1,228 million) carried out mainly in the United States, Libya, Egypt, Norway and Angola; (ii) the acquisition of proved and unproved properties amounting to euro 697 million mainly related to the acquisition of a 27.5% interest in assets with gas shale reserves from Quicksilver Resources Inc and extension of the duration of oil and gas properties in Egypt following the agreement signed in May 2009; (iii) the development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 919 million and euro 278 million, respectively) as well as the development and increase of the storage capacity (euro 282 million); (iv) projects aimed at improving the conversion capacity and flexibility of refineries, and at building and upgrading service stations in Italy and outside Italy (totaling euro 608 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,630 million).

In 2009, Eni’s acquisitions amounted to euro 2.32 billion and mainly related to the completion of the acquisition of Distrigas NV. Following the acquisition of the 57.243% majority stake in the Belgian company Distrigas NV from French company Suez-Gaz de France, Eni made an unconditional mandatory public takeover bid on the minorities of Distrigas (42.76% stake). On March 19, 2009, the mandatory tender offer on the minorities of Distrigas was finalized. Shareholders representing 41.61% of the share capital of Distrigas, including the second largest shareholder, Publigaz SCRL with a 31.25% interest, tendered their shares. The squeeze-out of the residual 1.14% of the share capital was finalized on May 4, 2009. After this, Distrigas shares have been delisted from Euronext Brussels. The total cash consideration amounted to approximately euro 2.05 billion.

In 2008, capital expenditures amounted to euro 14,562 million, of which 84% related to the Exploration & Production, Gas & Power and Refining & Marketing divisions and concerned mainly: (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.

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BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 40 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the U.S., Kazakhstan, Russia, Algeria, Australia, Venezuela and Iraq. In 2009, Eni produced 1,716 KBOE/d on an available for-sale basis. As of December 31, 2009, Eni’s total proved reserves amounted to 6,571 mmBOE; proved reserves of subsidiaries stood at 6,209 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 362 mmBOE.

Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth leveraging on the Company’s portfolio of assets and pipeline of development projects. We plan to achieve a production growth rate higher than 2.5% on average over the 2010-2013 periods, targeting a production level in excess of 2 mmBOE/d based on our long-term Brent price assumptions of 65 $/BBL and certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under "Item 5 – Management’s Expectations of Operations". Management plans to achieve that target via organic developments, leveraging on the Company’s asset portfolio. We plan to achieve 75% of that production level by continuing production ramp-up at our existing fields and 25% by successfully starting to production 41 new fields that based on management estimates are forecast to add up to 560 KBOE/d to the Company’s production level by 2013. We have already sanctioned half of new projects and expect to sanction a further 40% in 2010. Management plans to maximize product contribution from existing fields, particularly those with long-life cycles, by applying its advanced recovery technologies, reservoir management capabilities and implementing actions to offset natural field depletion.

Eni intends to pay special attention to reserve replacement in order to ensure the medium-to long-term sustainability of the business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, and divesting non-strategic or marginal assets. Eni also intends to develop certain LNG project in order to monetize its large base of gas reserves mainly in West Africa. We also plan to exercise tight cost control by achieving cost efficiencies associated with scale of operations and leveraging on our well-established presence in areas such as Africa where we believe development and production costs are lower than in other areas and increasing exposure to operated-projects.

In exploration activities, Eni intends to concentrate expenditures in well established areas of presence where availability of production facilities and existing know-how and competencies will enable the Company to readily put in production discovered reserves, reducing time-to-market and achieving cost efficiencies. Approximately 45% of planned exploration expenditures will be directed to such core areas (located mainly in the United States, Libya, Angola, Nigeria, Norway, Egypt, Congo and Indonesia). Eni also plans to selectively pursue high risk/high reward opportunities in areas with high mineral potential and to appraise the resource potential in recently entered areas like Gabon and Ghana. Eni expects to purchase new exploration permits and to divest or exit marginal or non strategic areas.

Management plans to invest approximately euro 37 billion to explore for and develop new reserves over the next four years; approximately euro 0.5 billion of which will be spent to build transportation infrastructures and execute LNG projects through equity-accounted entities. For the year 2010, management plans to spend euro 10.5 billion in reserves development and exploration projects.

 

Disclosure of Reserves

Overview

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

Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions.

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Prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements. In prior periods, year-end liquids and natural gas prices were used in the estimate of proved reserves in accordance with then applicable rules.

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information. Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under Production Sharing Agreements are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (cost oil) and on the profit oil set contractually (profit oil). A similar scheme applies to buy-back and service contracts.

 

Reserves Governance

Eni has always exercised centralized rigorous control over the process of booking proved reserves.

The Reserves Department of the Exploration & Production Division is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.

Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has affirmed their compliance with the SEC rules²; D&M has also stated that the company formal guidelines, whenever SEC rules do not provide specific prescription, provide a reasonable interpretation in line with the generally accepted practices in the industry. When participating in exploration and production activities operated by others entities, Eni also estimates its proved reserves on the basis of the above guidelines.

The process for evaluating reserves, as described in the internal procedure, involves: (i) business unit manager (geographic units) and Local Reserves 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 evaluation carried out by business unit managers; (iii) the Planning and Control Department which provides the economic evaluation of reserves; and (iv) the Reserve Department which, through Division Reserves Evaluators (DRE), provides independent reviews of the fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserve data.

The head of the Reserve Department attended the "Politecnico di Torino" and received a Master of Science degree in Mining Engineering in 1985. She has more than 20 years of experience in the oil and gas industry and more than 10 years of experience specifically in evaluating reserves.

Staff involved in the reserves evaluation process fulfill the professional qualifications requested and maintain the highest level of independence, objectivity and confidentiality in accordance with professional roles of conduct. Eni’s Reserves Evaluators qualifications comply with international standards established by the Society of Petroleum Engineers.

 

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent audit³ of its proved reserves on a rolling basis. The description of qualifications of the person primarily responsible for the reserve audit is included in the third party audit report⁴. In the preparation of their reports, those independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. This data, equally used by

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Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs.

In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided. In 2009, Ryder Scott Co and DeGolyer and MacNaughton provided an independent evaluation of almost 28% of Eni’s total proved reserves as of December 31, 2009⁵, confirming, as in previous years, the reasonableness of Eni’s internal evaluations⁶.

In the 2007-2009 three-year period, 86% of Eni total proved reserves were subject to independent evaluation. As of December 31, 2009 among the most important Eni properties, the only property which was not subject to an independent review was Barbara (Italy).

 

Summary of proved oil and gas reserves

The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2009, 2008 and 2007. Reserves data for 2009 is based on the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Data for 2008 and 2007 are based on the last day price of the Company’s fiscal year in accordance with then applicable rules.

HYDROCARBONS

(mmBOE)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Equity-accounted entities

Total

Year ended Dec. 31, 2007		747		638		1,879		1,095		1,061		198		259		133		6,010		668		6,678
Developed		534		537		1,183		766		494		127		158		63		3,862		101		3,963
Undeveloped		213		101		696		329		567		71		101		70		2,148		567		2,715
Year ended Dec. 31, 2008		681		525		1,922		1,146		1,336		265		235		132		6,242		666		6,908
Developed		465		417		1,229		827		647		168		133		62		3,948		107		4,055
Undeveloped		216		108		693		319		689		97		102		70		2,294		559		2,853
Year ended Dec. 31, 2009		703		590		1,922		1,141		1,221		236		263		133		6,209		362		6,571
Developed		490		432		1,266		799		614		139		168		122		4,030		74		4,104
Undeveloped		213		158		656		342		607		97		95		11		2,179		288		2,467

 

LIQUIDS

(mmBBL)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Equity-accounted entities

Total

Year ended Dec. 31, 2007		215		345		878		725		753		44		138		29		3,127		142		3,269
Developed		133		299		649		511		219		35		81		26		1,953		26		1,979
Undeveloped		82		46		229		214		534		9		57		3		1,174		116		1,290
Year ended Dec. 31, 2008		186		277		823		783		911		106		131		26		3,243		142		3,385
Developed		111		222		613		576		298		92		74		23		2,009		33		2,042
Undeveloped		75		55		210		207		613		14		57		3		1,234		109		1,343
Year ended Dec. 31, 2009		233		351		895		770		849		94		153		32		3,377		86		3,463
Developed		141		218		659		544		291		45		80		23		2,001		34		2,035
Undeveloped		92		133		236		226		558		49		73		9		1,376		52		1,428

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NATURAL GAS

(BCF)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Equity-accounted entities

Total

Year ended Dec. 31, 2007		3,057		1,675		5,751		2,122		1,770		880		696		598		16,549		3,022		19,571
Developed		2,304		1,364		3,065		1,469		1,580		530		442		213		10,967		428		11,395
Undeveloped		753		311		2,686		653		190		350		254		385		5,582		2,594		8,176
Year ended Dec. 31, 2008		2,844		1,421		6,311		2,084		2,437		911		600		606		17,214		3,015		20,229
Developed		2,031		1,122		3,537		1,443		2,005		439		340		221		11,138		420		11,558
Undeveloped		813		299		2,774		641		432		472		260		385		6,076		2,595		8,671
Year ended Dec. 31, 2009		2,704		1,380		5,894		2,127		2,139		814		629		575		16,262		1,588		17,850
Developed		2,001		1,231		3,486		1,463		1,859		539		506		565		11,650		234		11,884
Undeveloped		703		149		2,408		664		280		275		123		10		4,612		1,354		5,966

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 674 mmBOE as of December 31, 2009 (679 and 676 mmBOE as of December 31, 2008 and 2007, respectively). Said volumes are not included in reserves volumes shown in the table herein.

 

Activity of the year

	Subsidiaries		Equity-accounted entities

	2007		2008		2009		2007		2008		2009

Additions to proved reserves		237			882			605			639			6			(296	)
of which purchases and sales
of reserves-in-place		156			32			25			617						(314	)
Production for the year		(627	)		(650	)		(638	)		(7	)		(8	)		(8	)

 

	Subsidiaries

	2007		2008		2009

Proved reserves replacement ratio of subsidiaries		38		136		95

Eni’s proved reserves of subsidiaries as of December 31, 2009 totaled 6,209 mmBOE (oil and condensates 3,377 mmBBL; natural gas 16,262 BCF) representing a decrease of 33 mmBOE, or 5.3%, from December 31, 2008. Additions to proved reserves booked in 2009 were 605 mmBOE and derived from: (i) revisions of previous estimates (261 mmBOE) mainly reported in Egypt, Italy, Congo, the United Kingdom and the United States which were partly offset by the unfavorable effect of higher oil prices on reserve entitlements in certain PSAs and buy-back contracts (down 100 mmBOE) resulting from higher oil prices from a year ago (the Brent price used in the reserve estimation process was 59.9 $/BBL in 2009 compared to 36.5 $/BBL in 2008). Higher oil prices also resulted in upward revisions associated with improved economics of marginal productions; (ii) extensions and discoveries (282 mmBOE), with main increases reported in Norway, Algeria, Iraq and Libya; (iii) improved recovery (37 mmBOE) mainly reported in Angola, Norway and Libya; and (iv) purchases and sales of mineral in place (25 mmBOE).

The largest additions were related to following fields/projects: Goliat in Norway, CAFC and MLE in Algeria, Belayim in Egypt due to the new extension terms that were agreed upon with relevant Egyptian authorities, M’Boundi in Congo and Bahr Essalam in Libya as a result of continuing development activities and revisions as well as Zubair in Iraq due to the signing of the technical service contract.

Acquisitions for 26 mmBOE related mainly to a 27.5% stake purchased from Quicksilver Resources Inc in the Alliance area, in Texas.

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As of December 31, 2009 Eni’s share of proved reserves of equity-accounted entities amounted to 362 mmBOE, a decrease of 304 mmBOE compared to December 31, 2008, mainly due to the divestment of a 51% stake in the joint venture OOO SeverEnergia (Eni’s interest was 60%, currently 29.4%) after the call option exercised by Gazprom.

The new SEC rules allow the use of reliable technology (i.e. seismic, wireline formation test, logs and core) to justify the reserves estimate if it produces consistent and repeatable results. We did not have any material additions of proved reserves due to application of new reliable technologies.

Proved developed reserves of subsidiaries as of December 31, 2009 amounted to 4,030 mmBOE (2,001 mmBBL of liquids and 11,650 BCF of natural gas) representing 65% of total estimated proved reserves (63% and 64% as of December 31, 2008 and 2007, respectively).

The reserve replacement ratio for Eni’s subsidiaries was 95% in 2009 (136% in 2008 and 38% in 2007). 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 FASB Extractive Activities - Oil & Gas (Topic 932) (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. Management considers the reserve replacement ratio to be an important indicator 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 recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks. Specifically, in recent years Eni’s reserves replacement ratio 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 2009 this trend resulted in a lower amount of booked reserves associated with the Company’s PSAs as the oil price was averaged higher than the previous year. See "Item 3 – Risks associated with exploration and production of oil and natural gas" and – "Uncertainties in estimates of oil and natural gas reserves".

The average reserve life index of Eni’s proved reserves was 10.2 years as of December 31, 2009 which included reserves of both subsidiaries and equity-accounted entities.

 

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2009 totaled 2,467 mmBOE. At year-end, liquids proved undeveloped reserves amounted to 1,428 mmBBL, mainly concentrated in Africa and Kazakhstan. Natural gas proved undeveloped reserves accounted for 5,966 BCF, mainly located in Africa and Russia.

In 2009, total proved undeveloped reserves decreased by 386 mmBOE. The main reasons for the variation are: (i) reclassification to proved developed reserves; (ii) divestment of a 51% stake in the joint-venture OOO SeverEnergia (Eni’s interest being 60%) after the call option exercised by Gazprom; and (iii) addition from new projects and revisions.

During 2009, Eni converted approximately 370 mmBOE of proved undeveloped reserves to proved developed reserves. The main reclassification to proved developed were related to development activities and the start-up of the following fields: Blacktip (Australia), PY1 (India), Lennox (UK), Karachaganak (Kazakhstan), Longhorn (USA), Val d’Agri (Italia), and Poinsettia (Trinidad & Tobago).

Main additions of proved undeveloped reserves were recorded in Rest of Europe, North Africa and Rest of Asia.

In 2009, capital expenditure amounted to approximately euro 2.2 billion and were made to progress the development of proved undeveloped reserves.

Reserves that remain proved undeveloped for five or more years are a result of several physical factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities and contractual limitations that establish production levels.

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The Company estimates that approximately 0.8 BBOE of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to the Kashagan project (Kazakhstan), where development activities are progressing and production start-up is expected by the end of 2012.

 

Delivery commitments

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

Eni is contractually committed under existing contracts or agreements to deliver over the next three years natural gas to third parties for a total of approximately 1,908 BCF from producing properties located in Australia, Egypt, India, Indonesia, Libya, Nigeria, Norway, Pakistan, Tunisia and the United Kingdom.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced to the market price for crude oil, natural gas or other petroleum products.

Management believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 70% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2009.

 

Oil and gas production, production prices and production costs

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

In 2009, oil and natural gas production available for sale averaged 1,716 KBOE/d (liquids 1,007 KBBL/d; natural gas 4,074 mmCF/d), representing a decline of 32 KBOE/d from 2008, or 1.8%. Excluding OPEC cuts (down 28 KBOE/d) production was barely unchanged. Lower production uplifts associated with weak European gas demand, unplanned facility downtime, continuing security issues in Nigeria and mature field declines negatively affected full-year performance. Production increases were driven by continuing production ramp-ups/start-ups in Angola, Congo, Egypt, Kazakhstan, Venezuela and the Gulf of Mexico as well as the positive price impact reported in the Company’s PSAs and similar contractual schemes (up 35 KBBL/d). The share of oil and natural gas produced outside Italy was 90% (89% for the year ended December 31, 2008).

Liquids production amounted to 1,007 KBBL/d for the year ended December 31, 2009 which was down 1.9% from 2008 due to OPEC cuts. Excluding OPEC cuts, the unplanned facility downtime in Libya and mature field declines, mainly in Italy and the North Sea were offset by production increases achieved in: (i) Angola due to the start-up of the Tombua-Landana project (Eni’s interest 20%) and improved performance in Block 0 (Eni’s interest 9.8%); (ii) Congo due to the ramp-up of the Awa Paloukou project (Eni’s interest 90%); (iii) Kazakhstan due to a better performance; (iv) the Gulf of Mexico due to the start-up of the Thunderhawk (Eni’s interest 25%), Pegasus (Eni’s interest 58%) and Longhorn (Eni’s interest 75%) projects; and (v) Venezuela due to the ramp-up of the Corocoro field (Eni’s interest 26%).

Natural gas production (4,074 mmCF/d for the year ended December 31, 2009) declined from 2008 (down 1.7%). Production decreased in Libya due to lower gas demand on the European market and the mentioned technical reasons, and for mature field declines, mainly in Italy. Main increases were registered in the Gulf of Mexico, Congo due to the contribution of M’Boundi gas project (Eni’s interest 83%), and Croatia due to the start-up of Annamaria field (Eni’s interest 50%).

Oil and gas production sold amounted to 622.8 mmBOE for the year ended December 31, 2009. The 22.9 mmBOE difference over production (645.7 mmBOE for the year ended December 31, 2009) reflected volumes of natural gas consumed in operations (19.1 mmBOE). Approximately 60% of liquids production sold (365.2 mmBBL) was destined to Eni’s Refining & Marketing division (of which 17% was processed in Eni’s refinery); about 30% of natural gas production sold (1,479 BCF) was destined to Eni’s Gas & Power division.

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The tables below provide Eni’s production, by final product sold of liquids and natural gas by geographical area for each of the last three fiscal years.

LIQUIDS PRODUCTION ⁽¹⁾

(KBBL/d)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2007		75		157		337		280		70		37		53		11		1,020
2008		68		140		338		289		69		49		63		10		1,026
2009		56		133		292		312		70		57		79		8		1,007

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(1)

Data includes Eni’s share of production of affiliates and joint ventures accounted for under the equity method of accounting amounting to 17, 14 and 12 KBBL/d in 2009, 2008 and 2007, respectively.

NATURAL GAS PRODUCTION AVAILABLE FOR SALE ^{(1) (2)}

(mmCF/d)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2007		763		607		1,357		220		222		380		232		38		3,819
2008		725		588		1,661		204		227		396		304		38		4,143
2009		630		608		1,503		213		241		417		416		46		4,074

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(1)		Data includes Eni’s share of production of affiliates and joint ventures accounted for under the equity method of accounting amounting to 29, 26 and 28 mmCF/d in 2009, 2008 and 2007, respectively.
(2)		It excludes production volumes of natural gas consumed in operations. Said volumes were 300, 281 and 296 mmCF/d in 2009, 2008 and 2007, 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 97 KBOE/d, 93 KBOE/d and 75 KBOE/d in 2009, 2008 and 2007, respectively.

The tables below provide Eni’s average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. Also Eni’s average production cost per unit of production is disclosed. The average production cost does not include any ad valorem or severance taxes.

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT

($)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2007
Oil and condensate, per BBL		62.47		70.84		67.86		69.77		59.34		64.73		66.37		71.23		67.70
Natural gas, per KCF		8.58		6.71		4.60		1.21		0.41		4.34		6.69		5.94		5.42
Average production cost, per BOE		7.89		8.35		4.22		11.53		4.90		3.13		7.17		10.35		6.90
2008
Oil and condensate, per BBL		84.87		71.90		84.71		91.58		79.06		75.08		88.69		82.80		84.05
Natural gas, per KCF		13.06		10.55		7.14		1.50		0.53		5.50		8.81		9.59		8.01
Average production cost, per BOE		9.40		8.67		3.66		15.25		5.86		3.69		10.27		8.50		7.77
2009
Oil and condensate, per BBL		56.02		56.46		55.97		59.75		52.34		55.23		55.74		50.40		56.95
Natural gas, per KCF		9.01		7.06		5.78		1.66		0.45		4.30		4.05		8.14		5.62
Average production cost, per BOE		9.69		8.28		4.05		13.15		5.20		3.49		8.25		9.56		7.49

 

Drilling and other exploratory and development activities

In 2009, a total of 69 new exploratory wells⁷ were drilled (37.6 of which represented Eni’s share), as compared to 111 exploratory wells drilled in 2008 (58.4 of which represented Eni’s share) and 81 exploratory wells drilled in 2007 (43.5 of which represented Eni’s share).

Overall commercial success rate was 41.9% (43.6% net to Eni) as compared to 36.5% (43.4% net to Eni) and 40% (38% net to Eni) in 2008 and 2007, respectively.

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In 2009, a total of 418 development wells were drilled (175.1 of which represented Eni’s share) as compared to 366 development wells drilled in 2008 (155.1 of which represented Eni’s share) and 349 development wells drilled in 2007 (156.7 of which represented Eni’s share).

The table below provides the number of net productive and dry exploratory and development oil and natural gas wells completed in the years indicated by the Group companies and its equity-accounted entities.

NET EXPLORATION AND DEVELOPMENT DRILLING ACTIVITY

(units)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2007 Exploratory		4.0		1.4		15.3		1.7		0.2		0.2		9.6		0.6		33.0
Productive		0.5				7.7		0.5				0.2		3.6				12.5
Dry (a)		3.5		1.4		7.6		1.2		0.2				6.0		0.6		20.5
Development		17.0		27.3		45.8		18.5		1.3		37.8		8.4		0.6		156.7
Productive		17.0		27.2		45.8		18.5		1.3		34.1		5.9		0.6		150.4
Dry (a)				0.1								3.7		2.5				6.3
2008 Exploratory		0.7		3.7		22.9		7.4				16.2		3.4		1.4		55.7
Productive				0.7		8.7		4.0				9.4		1.4				24.2
Dry (a)		0.7		3.0		14.2		3.4				6.8		2.0		1.4		31.5
Development		12.9		5.5		47.6		37.2		2.6		43.0		6.3				155.1
Productive		11.3		5.5		46.4		36.4		2.6		36.5		6.3				145.0
Dry (a)		1.6				1.2		0.8				6.5						10.1
2009 Exploratory		1.0		4.3		8.6		2.7				6.2		4.8		2.2		29.8
Productive				4.1		4.8						2.3		1.0		0.8		13.0
Dry (a)		1.0		0.2		3.8		2.7				3.9		3.8		1.4		16.8
Development		18.3		12.5		41.1		37.7		3.8		42.9		16.6		2.2		175.1
Productive		18.3		12.5		40.7		35.8		3.8		38.6		15.6		2.2		167.5
Dry (a)						0.4		1.9				4.3		1.0				7.6

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(a)

A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well.

 

Present activities

The table below provides the number of exploratory and development oil and natural gas wells in the process of being drilled by the Group companies and its equity-accounted entities as of December 31, 2009. A gross well is a well in which Eni owns a working interest.

DRILLING ACTIVITY IN PROGRESS

(units)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

As of December 31, 2009 Exploratory (a)
Gross		6.0		25.0		26.0		60.0		13.0		19.0		22.0		1.0		172.0
Net		4.4		6.6		18.6		15.4		2.3		8.8		8.4		1.0		65.5
Development
Gross		6.0		8.0		16.0		23.0		2.0		13.0		47.0		1.0		116.0
Net		5.8		1.2		6.9		8.2		0.7		6.2		12.1		0.1		41.2

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(a)

Includes temporary suspended wells pending further evaluation.

 

Oil and gas properties, operations and acreage

As of December 31, 2009, Eni’s mineral right portfolio consisted of 1,246 exclusive or shared rights for exploration and development in 40 countries on five continents for a total acreage of 347,862 square kilometers of which 41,794 square kilometers was developed acreage and 306,068 square kilometers was undeveloped acreage.

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In 2009, total net acreage increased mainly due to: (i) the acquisition of a 27.5% interest in the Alliance area, in Northern Texas from Quicksilver Resources Inc and of a 37.8% interest in the Sanga Sanga license in Indonesia, both in the development of non-conventional gas resources; (ii) the awarding of the giant Zubair oil field (Eni’s interest 32.8%); and (iii) new leases in Angola, China, Ghana, the Gulf of Mexico, India, Norway and Yemen for a total acreage of approximately 40,000 square kilometers net to Eni.

Main decreases were in Mali due to the release of exploration licenses covering an undeveloped acreage of 100,000 square kilometers. Other exploration licenses were released in Congo, Egypt, Italy, Morocco, Norway, Russia, the United Kingdom and the United States mainly related to undeveloped areas.

The table below provides certain information about the Company’s oil and gas properties. It discloses the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2009. A gross acreage is one in which Eni owns a working interest.

	December 31, 2008		December 31, 2009

Total net acreage (a)

Number of interests

Gross developed (b) acreage (a)

Gross undeveloped acreage (a)

Total gross acreage (a)

Net developed (b) acreage (a)

Net undeveloped acreage (a)

Total net acreage (a)

EUROPE		30,511		315		17,918		33,643		51,561		11,794		19,813		31,607
Italy		20,409		167		11,641		15,537		27,178		9,692		12,346		22,038
Rest of Europe		10,102		148		6,277		18,106		24,383		2,102		7,467		9,569
Croatia		988		2		1,975				1,975		987				987
Norway		3,861		51		2,277		8,907		11,184		338		3,074		3,412
United Kingdom		1,450		89		2,025		3,140		5,165		777		692		1,469
Other countries		3,803		6				6,059		6,059				3,701		3,701
AFRICA		249,672		276		70,121		230,549		300,670		19,865		138,884		158,749
North Africa		31,088		119		30,820		54,725		85,545		13,431		32,580		46,011
Algeria		909		38		2,152		17,458		19,610		727		16,517		17,244
Egypt		9,741		57		4,445		18,652		23,097		1,571		6,757		8,328
Libya		18,164		13		17,947		18,427		36,374		8,951		9,214		18,165
Tunisia		2,274		11		6,276		188		6,464		2,182		92		2,274
West Africa		156,557		151		39,301		98,600		137,901		6,434		54,090		60,524
Angola		3,323		67		4,532		16,317		20,849		590		2,803		3,393
Congo		8,244		25		1,865		13,724		15,589		991		7,197		8,188
Gabon		7,615		6				7,615		7,615				7,615		7,615
Ghana				2				2,300		2,300				1,086		1,086
Mali		128,801		1				47,500		47,500				31,668		31,668
Nigeria		8,574		50		32,904		11,144		44,048		4,853		3,721		8,574
Other countries		62,027		6				77,224		77,224				52,214		52,214
ASIA		93,710		80		18,924		204,274		223,198		6,369		119,272		125,641
Kazakhstan		880		6		324		4,609		4,933		105		775		880
Rest of Asia		92,830		74		18,600		199,665		218,265		6,264		118,497		124,761
China		192		7		237		18,461		18,698		39		18,283		18,322
East Timor		9,779		5				9,999		9,999				7,999		7,999
India		9,091		14		303		27,861		28,164		143		9,946		10,089
Indonesia		17,316		12		1,735		25,940		27,675		656		15,863		16,519
Iraq				1		1,950				1,950		640				640
Iran		820		4		1,456				1,456		820				820
Pakistan		18,855		21		9,122		24,782		33,904		2,708		15,493		18,201
Russia		3,891		5		3,597		3,039		6,636		1,058		1,265		2,323
Saudi Arabia		25,844		1				51,687		51,687				25,844		25,844
Turkmenistan		200		1		200				200		200				200
Yemen		3,598		2				23,296		23,296				20,560		20,560
Other countries		3,244		1				14,600		14,600				3,244		3,244
AMERICAS		12,043		558		4,737		17,234		21,971		3,090		8,433		11,523
Brazil		1,389		2				1,389		1,389				1,067		1,067
Ecuador		2,000		1		2,000				2,000		2,000				2,000
Trinidad & Tobago		66		1		382				382		66				66
United States		6,648		543		1,977		9,120		11,097		926		5,524		6,450
Venezuela		614		3		378		1,178		1,556		98		516		614
Other countries		1,326		8				5,547		5,547				1,326		1,326
AUSTRALIA AND OCEANIA		29,558		17		1,057		48,216		49,273		676		19,666		20,342
Australia		29,520		16		1,057		47,452		48,509		676		19,628		20,304
Other countries		38		1				764		764				38		38
Total		415,494		1,246		112,757		533,916		646,673		41,794		306,068		347,862

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

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The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had interests as of December 31, 2009. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same bore hole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 7,181 (2,417.2 of which represent Eni’s share).

PRODUCTIVE OIL AND GAS WELLS

(units)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

Number of productive wells as of Dec. 31, 2009 (a) Oil wells
Gross		185.0		384.0		1,103.0		2,764.0		85.0		355.0		125.0		4.0		5,005.0
Net		145.7		64.5		469.2		474.3		27.6		255.1		56.3		2.6		1,495.3
Gas wells
Gross		481.0		198.0		120.0		501.0				658.0		207.0		11.0		2,176.0
Net		421.1		75.2		49.1		36.6				264.3		72.6		3.0		921.9

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(a)

Includes approximately 2,144 gross (633 net) multiple completion wells (more than one producing into the same well bore).

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

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Eni is the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region in southern Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is fed by 24 production wells of the 47 foreseen by the sanctioned development plan and is supported by the Viggiano oil center with a treatment capacity of 104 KBBL/d. Oil produced is carried to Eni’s refinery in Taranto via a 136-kilometer long pipeline. Gas produced is treated at the Viggiano oil center and then delivered to the national grid system. In 2009, the Val d’Agri concession produced 78 KBOE/d (42 net to Eni) representing 25% of Eni’s production in Italy.

Eni is the operator of 15 production concessions onshore and offshore in Sicily. Its main fields are Gela, Ragusa, Giaurone, Fiumetto and Prezioso, which in 2009 accounted for 10% of Eni’s production in Italy.

Full year development activities mainly related to: (i) the completion of the first development phase in the Val d’Agri concession through the connection to the oil treatment plant of the first wells located in the Cerro Falcone, with a production of 6 KBOE/d; (ii) the start-up of LPT Tresauro oil field in Sicily and the installation of a production platform on Annamaria B where production started in March 2010; and (iii) production optimization activities on producing fields by means of sidetrack, work over and rigless activities (Annalisa, Antares, Barbara, Cervia, Giovanna, Gela, Luna and Trecate fields). Offshore activities in Sicily related to the development of three recent gas discoveries (Panda, Argo and Cassiopea). Start-up is expected in 2013.

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

Rest of Europe Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the United Kingdom. In 2009, the Rest of Europe accounted for 14% of Eni’s total worldwide production of oil and natural gas. Croatia. Eni has been present in Croatia since 1996. In 2009, Eni’s production of natural gas averaged 92 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula. Exploration and production activities in Croatia are regulated by PSAs. The main producing gas fields are Ivana, Ika & Ida, Marica and Katarina operated by Eni through a 50/50 joint operating company with the Croatian oil company INA. The fields start-up in 2009 are: (i) Annamaria (Eni’s interest 50%), with a production of approximately 13 mmCF/d net to Eni; and (ii) Irina (Eni’s interest 50%) and Vesna (Eni’s interest 50%), with an overall production at approximately 3 mmCF/d net to Eni.

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Exploration activities yielded positive results with the Ika SW 2 appraisal well, which confirmed the mineral potential of the area.

Norway. Eni has been operating in Norway since 1964. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 123 KBOE/d in 2009.

Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a few years with possible extensions. In May 2009 following an international bid procedure Eni was awarded the operatorship of exploration licenses PL 533 (Eni’s interest 40%) and PL 529 (Eni’s interest 40%) in addition to a 30% stake in PL 532 in the Barents Sea. Eni holds interests in 6 production areas in the Norwegian Sea. The principal producing fields are Aasgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.12%), Mikkel (Eni’s interest 14.9%) and Norne (Eni’s interest 6.9%), which in 2009 accounted for 65% of Eni’s production in Norway. Full year production start-up was achieved in: (i) the Yttergryta (Eni’s interest 9.8%) field, with a production of approximately 71 mmCF/d; and (ii) the Tyrihans (Eni’s interest 6.23%) field, with a production of approximately 3 KBBL/d. Development activities progressed in recent oil and gas discoveries near the Aasgard field (Eni’s interest 14.82%). In particular the development plan of the Morvin discovery (Eni’s interest 30%) provides linkage to existing production facilities that will be upgraded. Production start-up is expected in 2010 with peak production at 12 KBOE/d net to Eni in 2014.

Eni holds interests in four production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018, which in 2009 produced approximately 56 KBOE/d net to Eni and accounted for 44% of Eni’s production in Norway. The license expires in 2028, and extension negotiations are ongoing. Ongoing projects aim at maintaining and optimizing production at Ekofisk by means of infilling wells, the development of the South Area, upgrading of existing facilities and optimization of water injection.

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 Goliat 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 license expires in 2042. The project is progressing according to schedule. Commencement is expected in 2013 with a production plateau at 100 KBBL/d. In 2009, the final investment decision of the Goliat project was sanctioned.

Exploration activities yielded positive results in the Prospecting License 128 (Eni’s interest 11.5%) with the Dompap gas discovery. 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 2009 Eni’s net production of oil and gas averaged 100 KBOE/d.

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

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%), Mac-Culloch (Eni’s interest 40%) and West

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Franklin (Eni’s interest 21.87%), which in 2009 accounted for 61% of Eni’s production in the United Kingdom. Development activities consist of infilling actions at the Elgin/Franklin, Mac-Culloch (Eni’s interest 40%) and Jade (Eni’s interest 7%) fields to maintain production levels. Pre-development activities are underway at the following discoveries: (i) the Burghley field (Eni’s interest 21.92%) with expected start-up in 2010; (ii) the Kinnoul oil and gas field (Eni’s interest 16.67%) to be developed in synergy with the production facilities of the Andrew field (Eni’s interest 16.21%) and expected start-up in 2012; (iii) the Jasmine gas field (Eni’s interest 33%) with expected start-up in 2012; and (iv) the Mariner field (Eni’s interest 8.89%) with expected start-up in 2015.

Eni holds a 53.9% interest in 6 production fields in the Liverpool Bay area in the Eastern section of the Irish Sea. The main fields are Douglas, Hamilton and Lennox and their extension which in 2009 accounted for 21% of Eni’s production in UK. Upgrades to the facilities are underway.

Eni holds interest in 6 production permits located east of the Shetland Islands. The main fields are Ninian (Eni’s interest 12.94%) and Magnus (Eni’s interest 5%), which in 2009 accounted for 4% of Eni’s production in the United Kingdom. In 2009, maintenance and optimization actions were performed with the drilling of infilling wells.

Exploration activities yielded positive results in Block 22/25a (Eni’s interest 16.95%) with the Culzean gas discovery near the Elgin/Franklin producing field (Eni’s interest 21.87%). A study of the development activities is underway.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2009, North Africa accounted for 32% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2009, 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: (i) Blocks 403 a/d (Eni’s interest 100%); (ii) Blocks 401a/402a (Eni’s interest 55%); (iii) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); and (iv) under development Blocks 212 (Eni’s interest 22.38%), 208 (Eni’s interest 12.25%) and 405b (Eni’s interest 75%), the latter purchased in 2008 from Canadian company First Calgary.

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Relevant authorities confirmed the acquisition of the operatorship of the Kerzaz exploration area (Blocks 319a, 321a and 316b) covering a total acreage of 16,000 square kilometers. Exploration activities are underway. Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts. Production in Block 403a/d is supplied mainly by the HBN and Rom and satellite fields which represented approximately 28% of Eni’s production in Algeria in 2009. The main project underway is the Rom Integrated project, designed to develop the Rom and satellites reserves (Zea, Zek and Rec) following the mineral potential revaluation. Current production is collected at the Rom Central Production Facility (CPF) and delivered to the treatment plant in Bir Rebaa North. Drilling and work over activities were started in 2009. An export pipeline and a new multiphase pumping system are underway in compliance with applicable Country law to reduce gas flaring. Production in Blocks 401a/402a is supplied mainly by the Rod and satellite fields and accounted for approximately 22% of Eni’s production in Algeria in 2009. Infilling activities are being performed in order to maintain the current production plateau. The main fields in Block 403 are BRN, BRW and BRSW which accounted for approximately 16% of Eni’s production in Algeria in 2009. Exploration activities for appraising the mineral potential of the area are planned.

In Block 405b, the development activity relates to the MLE and CAFC integrated project. During 2009 the MLE final investment decision was sanctioned. This project provides the construction of a NGL plant with a capacity of 350 mmCF/d. Production start-up is expected in November 2011. The CAFC final investment decision will be sanctioned in 2010. The CAFC project will provide the construction of an oil treatement plant with a capacity of 35 KBBL/d and installation of water/gas injection systems. The development of the two fields will ensure a production plateau of approximately 33 KBOE/d net to Eni by 2012. Drilling activities are underway. In 2009 the EPC contract for the construction of a gas treatment plant, gathering and exporting facilities has been awarded. As of December 31, 2009, 11% of the project was completed. The PSA expires in 2037.

Block 208 is located south of Bir Rebaa. In 2009, the final investment decision of El Merk was sanctioned. During the year all EPC contracts for the development of facilities were awarded and drilling activity started. 24% of the project was completed and start-up is expected in 2012.

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 greater than 125 KBOE/d, reflecting the development and integration of the First Calgary acquired assets.

Egypt. Eni has been present in Egypt since 1954. In 2009, Eni’s share of production in this country amounting to 220 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%), in the Western Desert mainly Melehia concession (56% interest) and Ras Qattara (75% interest). 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 2009, production from these concessions also includes a portion of liquids accounting for more than 80% of Eni’s production in Egypt.

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Exploration and production activities in Egypt are regulated by concession contracts and PSAs.

In May 2009, Eni signed a cooperation agreement with Egypt’s Ministry for Oil to increase and widen cooperation in development activities. The agreement provides for: (i) an extension of the concession of the giant Belayim field in the Gulf of Suez until 2030, with Eni’s commitment to spending $1.5 billion over the next five years related to development expenditures, upgrading actions and operating costs; (ii) a joint study to evaluate a number of industrial initiatives to monetize the natural gas reserves at high depth; and (iii) training and knowledge management. In 2009, in the offshore area of the Nile Delta, the North Bardawil (Eni operator with a 60% interest) and Thekah fields (Eni operator with a 50% interest) started-up by linking to El Gamil facilities with an overall production plateau at approximately 190 mmCF/d. The basic engineering is ongoing at the Belayim field for the upgrading of water injection facilities to recover residual reserves. Other development activities concerned the Tuna project, the second phase at the Denise field and upgrading of the el Gamil compression plant by adding new capacity to support production.

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Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 BCF/y of feed gas. Eni is currently supplying 35 BCF/y for a twenty-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 KBOE/d net to Eni of feed gas.

In the medium-term, management expects that Egypt will remain among Eni’s largest oil and gas producing countries.

Libya. Eni started operations in Libya in 1959. In 2009, Eni’s oil and gas production averaged 238 KBOE/d, the portion of liquids being 45%. Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area. Under the agreement signed in 2008 with the Libyan national oil company ("NOC"), Eni’s assets have been grouped into six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Sicily Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%). In the exploration phase, Eni is operator of four onshore blocks in the Muzurk basin (161/1, 161/2&4, 176/3), in the Kufra area (186/1, 2, 3 & 4) and in the contract Areas A, B and D. Exploration and production activities in Libya are regulated by six Exploration and Production Sharing contracts (EPSA). The terms of Eni’s assets in Libya have been extended until 2042 and 2047 for oil and gas properties respectively, taking into account the extension clauses.

Main development activities underway include the Western Libyan Gas project (Eni’s interest 50%) for the exploitation of gas reserves ratified in the strategic agreements between Eni and NOC. In particular upgrading of plants and facilities in order to increase gas sales by 49 BCF/y was completed. Additional gas volumes are also expected to be on stream by 2015 from a portfolio of undeveloped fields. Gas production at Wafa and Bahr Essalam will be maintained by increasing compression capacity at Wafa field and drilling of additional wells in both fields.

In 2009, volumes delivered through the GreenStream pipeline were 309 BCF. In addition, 43 BCF were sold on the Libyan market for power generation and to fuel the GreenStream pipeline compression plant.

Other projects underway related to: (i) a plan to exploit flaring gas and associated condensates from the Bouri oil field (Eni’s interest 50%) that will be pre-treated in the area and then delivered at the Mellitah plant for the final treatment; and (ii) ongoing activities aimed at maintaining the El Feel field (Eni’s interest 33.3%) production plateau through water injection.

In the medium-term, management expects to increase Eni’s production in Libya due to the expected ramp-up of new gas developments the schedule of which will depend upon future trends in the gas market with the support of the upgrade of the GreenStream pipeline, despite mature field declines. In the medium-term Libya is expected to remain the largest producing country by volume in Eni’s portfolio.

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Tunisia. Eni has been present in Tunisia since 1961. In 2009, Eni’s production amounted to 15 KBOE/d. Eni’s activities are located mainly in the Southern desert areas and in the Mediterranean offshore facing Hammamet.

Exploration and production in this country are regulated by concessions.

Production mainly comes from 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 projects mainly related to the optimization of production at the Adam, Djebel Grouz (Eni’s interest 50%), Oued Zar and El Borma blocks.

The development plan of Maamoura concession (Eni operator with a 49% interest) is almost completed with early production started-up in late 2009. The Baraka (Eni operator with a 49% interest) development project is in the final stage with production peaking at 11 KBOE/d which is expected in 2010.

Exploration activities yielded positive results with four discovery wells among five drilled. In 2009 gas production was started in one well, while two more wells are expected to start-up in 2010.

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

West Africa

Eni’s operations in West Africa are conducted mainly in Angola, Congo and Nigeria. In 2009, West Africa accounted for 20% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2009, Eni’s production averaged 125 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

The main blocks with Eni’s participation are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) west of the Angolan coast; (ii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; and (iii) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo basin. Eni also holds interests in other minor concessions, in particular in some areas of Block 3 (with interests varying from 12 to 15%) and in the Lianzi Development Area (former 14K/A IMI Unit Area-Eni’s interest 10%). In the exploration and development phase, Eni is operator of Block 15/06 (35% interest), holds 12% interest in Block 3/05-A, 10% interest in Cabinda North (onshore) and 20% interest in the Open Areas of the Gas Project. Exploration and production activities in Angola are regulated by concessions and PSAs. In February 2009, three agreements were finalized as part of the Memorandum of Understanding signed in August 2008 with Angola’s National Oil Company Sonangol, providing for: (i) a feasibility study to assess the economics of the utilization of associated gas in feeding a grass-root onshore power plant; (ii) a joint study to evaluate and collect data on certain Angolan onshore basins in view of identifying upstream opportunities; and (iii) the design of a number of educational and training projects targeting Angolan professionals in the development of energy resources. In 2009, production started-up at the Mafumeira field in Block 0 in the Cabinda A area (Eni’s interest 9.8%) and the Landana-Tombua fields in the

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Development Areas of the former Block 14. Peak production at 33 KBOE/d and 136 KBOE/d is expected in 2010 and 2011, respectively.

Within the activities for reducing gas flaring, projects progressed at the Nemba field in Block 0. Start-up is expected in 2013 reducing flared gas by approximately 85%. In 2009, the development activity of Takula field was completed. Gas flared is re-injected in the field; condensates will be shipped to the Malongo treatment plant, nearing completion.

Main projects underway in the Development Areas of former Block 15 were as follows: (i) development activities started-up at the satellites of Kizomba project-phase 1. The project provides for the drilling of 18 producing wells linked to the FPSO vessels existing in the area. Associated gas will be initially re-injected in the reservoirs in the Kizomba area, and thereafter delivered to the A-LNG liquefaction plant. Start-up is expected in 2012. Peak production at 100 KBOE/d (21 net to Eni) is expected in 2013. The second phase provides for production from nearby discoveries; and (ii) the Gas Gathering project, entailing the construction of a pipeline collecting all gas from the Kizomba, Mondo and Saxi/Batuque areas, is underway. Completion is expected in 2011.

Eni holds a 13.6% interest in the Angola LNG Ltd (A-LNG) consortium responsible for the construction of an LNG plant in Soyo, 300 kilometers north of Luanda. It has been designed with a processing capacity of about 1.1 BCF/d of natural gas and to produce 5.2 mmtonnes/y of LNG. The project has been sanctioned by relevant Angolan authorities. It envisages the development of 10,594 BCF of associated gas reserves in 30 years. Start-up is expected in the first quarter of 2012. The LNG will be delivered to the United States market at the re-gasification plant in Pascagoula currently under construction (Eni’s capacity 45%, amounting to approximately 205 BCF/y) in Louisiana. Start-up is expected in late 2011.

In addition, Eni finalized another agreement with the national Angolan company and other partners to be part of a second gas consortium which will explore further potential gas discoveries (Gas project) to support the feasibility of a second LNG train. Eni is the technical advisor for this consortium, with a 20% interest.

Exploration activities yielded positive results in: (i) Block 3 (Eni’s interest 12%), the Punja-4 appraisal well showed the presence of liquids and natural gas; (ii) the Development Areas of former Block 14 (Eni’s interest 20%) with the Malange-2 appraisal well containing oil; (iii) the Development Areas of former Block 15 (Eni’s interest 20%) with the Mondo-4 appraisal well containing oil; and (iv) Block 15/06 (Eni operator with a 35% interest) where the Cabaça Norte, Nzanza and Cinguvu discoveries showed the presence of oil and yielded 6.5 KBBL/d, 1.5 KBBL/d and 6.4 KBBL/d in test production, respectively.

In the medium-term, management expects to increase Eni’s production to approximately 180 KBBL/d reflecting contributions from ongoing development projects, despite mature field declines. Congo. Eni has been present in Congo since 1968. In 2009, production averaged 99 KBOE/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. Eni’s main operated oil producing interests in Congo are the Zatchi (Eni’s interest 65%) and Loango (Eni’s interest 50%), Ikalou (Eni’s interest 100%), Djambala, Foukanda e Mwafi (Eni’s interest 65%), Kitina (Eni’s interest 35.75%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%) and Kouakouala (Eni’s interest 75%) fields. Other relevant producing areas are a 35% interest in the Pointe Noire Grand Fonde and PEX permits. In the exploration phase, Eni also holds interests in the Mer Très Profonde Sud deep offshore block (Eni’s interest 30%), the Noumbi onshore permit (Eni’s interest 37%), the Marine XII offshore permit (Eni operator with a 65% interest) and the Le Kouilou onshore permit (Eni operator with an 85% interest).

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

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In 2009, the development plan of Awa-Paloukou field was completed. Production start-up was 12 KBBL/d.

Activities on the M’Boundi operated 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. The permit expires in 2027. In 2009, Eni signed a long term agreement to supply associated gas from the M’Boundi field to feed three facilities in the Pointe Noire area: (i) the Koilou potassium plant, owned by Canadian Company MAG Industries and under construction; (ii) the CED (Centrale Electrique du Djeno) existing power plant; and (iii) the new built CEC (Centrale Electrique du Congo - Eni’s interest 20%). The facilities will also receive gas in the future from the offshore discoveries of the Marine XII permit.

The development activities to build the CEC power plant moved forward in 2009 as scheduled in the Cooperation Agreement signed by Eni and the Republic of Congo in 2007, and the start-up of the first turbo-generator occurred by the end of March 2010.

Also the studies related to the possible exploitation of unconventional oil reserves from the Tchikatanga and Tchikatanga-Makola areas have progressed, according to the cooperation agreement signed in 2008, with the particular aim to identify area where it would be possible to withstand the stringent Eni’s environmental and sustainability requirements for development.

Exploration activities yielded positive results in: (i) the Marine XII permit with two discoveries wells which confirmed the mineral potential of the area. The related PSA was signed; and (ii) the Le Kouilou permit with the Zingali field, confirmed by subsequently long production test.

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 150 KBOE/d by 2013.

Ghana. On September 28, 2009, Eni acquired the operatorship of the offshore exploration permits for Cape Three Point South and Cape Three Point (Eni’s interest 47.2%). Exploration activities yielded positive results in the latter with the Sankofa discovery containing oil and natural gas.

Nigeria. Eni has been present in Nigeria since 1962. In 2009, Eni’s oil and gas production averaged 124 KBOE/d located mainly in the onshore and offshore of the Niger Delta.

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%), holding interests in OML 118 (Eni’s interest 12.5%) as well as in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the country, Eni also holds a 5% interest in 30 onshore blocks and a 12.86% interest in 5 conventional offshore blocks.

In the exploration phase Eni is operator of offshore 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).

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

In 2009, production from the Oyo offshore field in Blocks OML 120/121 (Eni’s interest 40%) has started with peak production of 25 KBBL/d.

In Blocks OML 60, 61, 62 and 63 (Eni operator with a 20% interest), within the activities aimed at guaranteeing production to feed gas to the Bonny liquefaction plant (Eni’s interest 10.4%), the development of gas reserves continued by upgrading treatment capacity at the Obiafu/Obrikom plant as well as the installation of a new treatment plant and transport facilities for carrying 155 mmCF/d net to Eni of feed gas for 20 years. To the same end the development plan of the Tuomo gas field has been progressing along with its linkage to the Ogbainbiri treatment plant.

An integrated oil and gas project is underway in the Gbaran-Ubie area. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of about 1 BCF/d of gas and 120 KBBL/d of liquids, the drilling of producing wells and the construction of a pipeline to carry the gas to the Bonny liquefaction plant. The first gas is expected in the third quarter of 2010.

Eni holds a 10.4% interest in Nigeria LNG Ltd which is responsible for the management of the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG from 6 trains. The seventh unit is

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being engineered as it is in the pre-fid phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 BCF/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture (Eni’s interest 5%) and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 (Eni’s interest 20%). In 2009, total supplies were 1,798 mmCF/d (130 mmCF/d net to Eni corresponding to 23 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 also has a 17% interest in the Brass LNG Ltd Co for the construction of a natural gas liquefaction plant that will be built near the existing Brass terminal which is 100 kilometers west of Bonny. This plant is expected to start operating in 2015 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 BCF/y (approximately 60 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 onshore OMLs 60 and 61. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity (corresponding to approximately 81 BCF/y). The LNG will be delivered to the United States market mainly at the re-gasification plant in Cameron, located in Louisiana. Eni’s capacity amounts to approximately 201 BCF/y. Front end engineering activities continued during 2009 and the final investment decision is expected at the end of 2010.

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

Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2009, Eni’s operations in Kazakhstan accounted for 7% of its total worldwide production of oil and natural gas.

In November 2009, Eni signed a co-operation agreement with the Kazakh national oil company KazMunaiGas. This agreement envisages joint studies and activities to be performed on: (i) the preliminary evaluation of the Isatay and Shangala exploration areas located in the Northern Caspian Sea; (ii) gas utilization in Kazakhstan; and (iii) a

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number of industrial initiatives including the upgrading of the Pavlodar refinery, in which KMG holds a majority interest.

Kashagan. Eni holds a 16.81% participating interest in the NCSPSA. The NCSPSA defines terms and conditions for the exploration and development activities to be performed in an area encompassing approximately 4,600 square kilometers. The Kashagan field was discovered in the northern section of the contractual area in the year 2000. Management believes this field contains a large amount of hydrocarbon resources which will be developed in phases. The PSA on Kashagan will expire at the end of 2041.

The participating interest in the NCSPSA has been redefined, effective as of January 1, 2008, in line with an agreement signed in October 2008 with Kazakh authorities which proportionally diluted the participating interest of the international companies in favor of the Kazakh national oil company, KazMunaiGas. The Kazakh partner will pay the other co-venturers an aggregate amount of $1.78 billion for the transaction. Eni partners of the international consortium are the Kazakh national oil company, KazMunaiGas, and the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, ConocoPhillips with 8.40%, and Inpex with 7.56%.

Exploration and development activities in the Kashagan field and in the other discoveries made in the contractual area are executed through an operating model which entails an increased role of the Kazakh partner and defines the International parties’ responsibilities in the execution of the subsequent development phases of the project. The North Caspian Operating Company (NCOC) BV, participated by the seven partners of the consortium has taken over the operatorship of the project in January 2009. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the consortium: Eni will retain responsibility for the Phase 1 of the project (the so-called “Experimental Program”) and for the onshore operations of Phase 2.

In conjunction with the agreement signed in October 2008, the Kazakh authorities approved a new schedule which foresees the production start-up by the end of 2012 and a revised expenditure budget of Phase 1 of the project, amounting to $32.2 billion (excluding general and administrative expenses) of which: $25.4 billion for the execution of the original scope of work of Phase 1 (tranches 1 and 2) and the remaining portion for the execution of tranche 3 and construction of certain exporting facilities. Eni will fund those investments in proportion to its participating interest of 16.81%. Management is targeting first oil by the end of 2012. In the following 12-15 months processing facilities and compression units for gas re-injection will be entirely commissioned to enable an installed production capacity of 370 KBBL/d in 2014. Afterwards, production capacity of Phase 1 is expected to step up to 450 KBBL/d, leveraging on availability of further compressor capacity for gas re-injection associated with the Phase 2 offshore facilities.

Phase 2 is currently in the stage of Front End Engineering Design (FEED).

The development plan of the Kashagan field was originally approved by the Kazakh authorities in February 2004, contemplating a phased 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 1, 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, submitted to 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 1 at U.S. $19 billion. As outlined above the amended development plan sanctioned in October 2008 forecasts production start-up in late 2012 and an expenditure budget for Phase 1 amounting to $25.4 billion. The production delay and cost overruns were driven by a number of factors, such as: (i) depreciation of the U.S. dollar versus the euro and other currencies; (ii) cost price escalation of goods and services required to execute the project; (iii) an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; and (iv) design changes to enhance the operability and safety standards of the offshore facilities.

Management believes that 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. The achievement of the full field production plateau will require a relevant amount of expenditures in addition to the development expenditures needed to complete the execution of Phase 1. However, taking into account that future development expenditures will be incurred over a long time period, 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 upgrade or 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; and (ii) construction of transportation systems needed for phases subsequent to the experimental program. In this respect, it is worth mentioning the project aimed at building a line

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connecting the onshore Bolashak production center 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 the construction of a new transport system linking Samsun on the Turkish coast of the Black Sea to Cehyan on the Mediterranean coast in order to bypass the congested Turkish Straits of Bosporus and Dardanelles.

As of December 31, 2009, Eni’s proved reserves booked for the Kashagan field amounted to 588 mmBOE, recording a decrease of 6 mmBOE with respect to 2008.

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.

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, 2009, the aggregate costs incurred by Eni for the Kashagan project capitalized in the consolidated financial statements amounted to $4.5 billion (euro 3.1 billion at the EUR/USD exchange rate of December 31, 2009). This capitalized amount included: (i) $3.4 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $1.1 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years.

As of December 31, 2008, the aggregate costs incurred by Eni for the Kashagan project capitalized in the consolidated 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. 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 2009, production of the Karachaganak field averaged 238 KBBL/d of liquids (70 net to Eni) and 883 mmCF/d of natural gas (241 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

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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 a fourth oil treatment unit has been progressing towards completion and will enable to increase the export to western markets of currently non-stabilized liquids delivered to the Orenburg terminal. 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 2010.

The engineering activities of Phase 3 of the Karachaganak project identified a staged approach to best develop the field. The project provides for the installation of gas producing and re-injection facilities to increase gas sales at the Orenburg plant up to 565 BCF/y and the liquids production up to approximately 14 mmtonnes/y. With the view to sanctioning the Phase 3, technical and commercial discussions with the relevant authority are ongoing.

As of December 31, 2009, Eni’s proved reserves booked for the Karachaganak field amounted to 633 mmBOE, recording a decrease of 107 mmBOE with respect to 2008 in connection to a downward revisions due to the impact of higher oil prices and the production of the year.

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 as a result of the upward revisions of previous estimates that were 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, 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 that mainly related to the finalization of a revised gas sale contract.

Rest of Asia In 2009, Eni’s operations in the rest of Asia accounted for 8% of its total worldwide production of oil and natural gas. China. Eni has been present in China since 1984 and its activities are located in the South China Sea. In 2009 Eni’s production amounted to 8 KBOE/d. Exploration and production activities in China are regulated by Production Sharing Agreements. Hydrocarbons are produced from the offshore blocks 16/08 and 16/19 operated by the CACT-Operating Group (Eni’s interest 16.33%). Oil, which is sold into the domestic market, is produced from seven platforms connected to a FPSO; the greater portion of Eni oil production derives from the HZ25-4 field (Eni’s interest 49%). Natural gas production from the HZ21-1 field is delivered through a sealine to the Zhuhai Terminal, close to Macao and sold to the Chinese National Company CNOOC. During 2009, development activities were mainly focused on the HZ25-4 and the HZ25-3/1 fields. The development of the HZ25-4 field, on stream since 2007, continued with the drilling of additional producing wells as planned, while on HZ25-3/1, following the installation of the production platform, the drilling of the producing wells continued.

In 2009 Eni signed the PSAs related to Blocks 3/27 and 28/20 located in the South China Sea covering a total acreage of 18,194 square kilometers. Eni’s participating interest in the exploration stage is equal to 100%.

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India. Eni has been present in India since 2005.

In 2008, Eni acquired control of the Indian company Hindustan Oil Exploration Co Ltd (HOEC) following the 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. In 2009 production started-up from the PY-1 gas field which is part of the assets acquired from Hindustan Oil Exploration Co Ltd. Gas production is sold to the local national oil company. Other activities are related to the 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%). Indonesia. Eni has been present in Indonesia since 2001. In 2009, Eni’s production, mainly composed of gas, amounted to 18 KBOE/d. Activities are concentrated in the eastern offshore and onshore of Borneo, the offshore Sumatra, and the offshore and onshore area of the West Timor; in total, Eni holds interest in 12 blocks. In November 2009, Eni was awarded a 37.8% participating interest in the new Sanga Sanga PSA in connection with coal bed methane (CBM) production. The PSA defines terms and conditions for the exploration, development and production of gas from

shallow levels of coal within a contractual area that mostly coincides with the one regulated by the Sanga Sanga PSA for the production of conventional hydrocarbons. Exploration activity start-up is expected in 2010. If the results of these preliminary activities are positive, the project will benefit from the opportunities of synergy provided by the existing production and treatment facilities in Sanga Sanga and the Bontang LNG plant. Exploration and production activities in Indonesia are regulated by PSAs. In 2009, the development plan of the Jau field in the Krueng Mane Block (Eni’s interest 75%) located offshore of Sumatra was submitted to the relevant Authority. Eni is evaluating major development opportunities for the development of the oil and gas discoveries in the Bukat permit (Eni operator with a 66.25% interest) and for the five gas discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%). Positive results in the exploration activity were achieved with the Jangkrik gas discovery located in the Muara Bakau Block (Eni’s interest 55%) offshore Borneo. Iraq. On January 22, 2010 Eni leading a consortium of international companies and the Iraqi national oil companies, South Oil Co and Missan Oil

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Co signed a technical service contract, with a 20-year term with an option for further 5 years, to develop the Zubair oil field (Eni 32.8%). The field was awarded in October 2009 to the Eni-led consortium following a successful first bid round and was offered under a competitive bid process beginning on June 30, 2009. The partners of the project plan to gradually increase production to a target plateau level of 1.2 mmBOE/d over the next six years. The contract provides that the consortium will earn a remuneration fee on the incremental oil production once production has been raised by 10 percent from its current level of approximately 180 KBBL/d and will recover its expenditures through a cost recovery mechanism based on the revenues from the field’s production.

The field development will take place in two phases: (i) the Rehabilitation Plan, which will improve the existing production rate to gain full knowledge of the reservoir and (ii) the Redevelopment Plan, which will increase production to the target plateau.

Iran. Eni has been present in Iran since 1957. Eni’s activities in Iran are currently limited mainly to the implementation of two buyback contracts signed between 2000 and 2001. Specifically, in 2009 activities were executed on the Darquain project which related to plant commissioning and start-up in view of making formal hand over of operations to local partners at some point in 2010. Darquain was the sole Eni-operated project in the country. With regard to another project, Eni’s involvement essentially consists of being reimbursed for its past investments. In 2009, Eni’s production in Iran was 35 KBOE/d, approximately 2% of the Group’s worldwide production. Eni does not believe that its activities in Iran have a material impact on the Group’s results.

Pakistan. Eni has been present in Pakistan since 2000. In 2009 Eni’s production averaged 56 KBOE/d and is 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 which foresees the possible development of a number of important upstream, midstream and downstream projects in the country. This deal is in line with Eni’s strategy of consolidating its position as principle international operator in the country. Eni will provide its know-how as well as new technologies developed in the oil and gas sector.

Eni’s main permits in the Country are Bhit (Eni’s interest 40%), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2009 accounted for 88% of Eni’s production in Pakistan

Development activities were focused on: (i) the Bhit field with the ongoing installation of a compressor plant aimed at maintaining the current production plateau; (ii) the Sawan field where construction activity of a compressor plant is ongoing; and (iii) the Zamzama permit where activities on the third treatment plant for the production of high calorific value (HCV) gas are aimed at optimizing current production. During the year additional activities were targeted at optimizing production from the Bhit, Sawan and Kadanwari fields by drilling additional wells.

Positive results from exploration activity were obtained with discoveries in the Badhra (Eni operator with a 40% interest), Kadanwari (Eni operator with an 18% interest) and Miano (Eni’s interest 15%) areas. The start-up timing of these recent discoveries will benefit from the proximity to existing producing facilities.

Russia. Eni has been present in Russia since 2007 following the acquisition of Lot 2 in the liquidation of Yukos.

In September 2009, Eni and its Italian partner Enel in the 60-40% owned joint-venture OOO SeverEnergia completed the divestment of the 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. Currently Eni’s interest is 29.4%. Eni collected the total cash consideration ($940 million), 25% of which had been collected at the transaction date and the remaining 75% on March 31, 2010. A gain in amount of euro 100 million was recognized in the profit and loss account for the year ended December 31, 2009. The gain was associated with interest income at an annual rate of 9.4% accruing on the initial investment in the venture when it was acquired on April 4, 2007 based on the contractual arrangements between Eni and Gazprom. The three partners are committed to producing the first gas from the Samburskoye field by June 2011, targeting a production plateau of 150 KBOE/d within two years from the start of production.

In April 2009, Gazprom exercised its call option to purchase a 20% interest in OAO Gazprom Neft held by Eni based on the existing agreements between the two partners. The exercise price of the call option collected by Eni on April 24, 2009 amounted to euro 3,070 million is equal to the price ($3.7 billion) outlined in the bid procedure for the assets of the bankrupt Russian company Yukos as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and financing collateral expenses. Eni and Gazprom signed new cooperation agreements targeting certain development projects to be conducted jointly in Russia and other countries of interest.

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Americas

In 2009, Eni’s operations in America area accounted for 9% of its total worldwide production of oil and natural gas.

Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2009, Eni’s production averaged 67 mmCF/d and its activity is concentrated offshore north of Trinidad.

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

Production is provided by the Chaconia, Ixora 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 relates to the Poinsettia, Bougainvillea and Heliconia fields in the North Coast Marine Area 1. The project provides for the installation of a production platform on the Poinsettia field and the linkage to the Hibiscus treatment facility which was already upgraded. The drilling program on Heliconia and Bougainvillea fields is underway. Start-up is expected in 2010. In 2009 production started at the Poinsettia field.

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

In 2009, Eni’s oil and gas production is mainly derived from the Gulf of Mexico with an average of 117 KBOE/d.

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

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Eni holds interests in 370 exploration and production blocks in the Gulf of Mexico of which 60% are operated by Eni.

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 May 2009, Eni signed a strategic alliance with Quicksilver Resources Inc, an independent U.S. natural gas producer, to acquire a 27.5% interest in the Alliance area, located in the Fort Worth basin of Texas. The acquisition for cash consideration amounting to $280 million includes gas shale production assets with 40 mmBBL of resources base. Production plateau at 10 KBOE/d net to Eni is expected in 2011. In 2009, production start-up was achieved in the Gulf of Mexico as follows: (i) the Thunderhawk field (Eni’s interest 25%) through the drilling of underwater wells and linkage to a semi submersible production unit with a treatment capacity of 45 KBBL/d of oil and about 71 mmCF/d of natural gas; (ii) the Longhorn field (Eni’s interest 75%) through the drilling of underwater wells and installation of production platform with a treatment capacity of approximately 247 mmCF/d; and (iii) the Leo field (Eni’s interest 75%) by means of the linkage to the Longhorn production facilities. The development plan of the Appaloosa discovery (Eni’s interest 100%) was approved. The discovery is planned to be developed in synergy with the Longhorn production facilities. Start-up is expected in 2010 with production peaking at 1.5 KBOE/d. Offshore exploration activities yielded positive results in the following blocks: (i) Green Canyon 859 (Eni’s interest 12.5%) with the oil and gas Heidelberg-1 discovery; and (ii) Keathley Canyon 919 (Eni’s interest 25%) with the oil and gas Hadrian West discovery.

Eni holds interests in 173 exploration and development blocks in Alaska, with interests ranging from 10 to 100% and over half of these blocks, Eni is the operator.

The Oooguruk oil field (Eni’s interest 30%), in the Beaufort Sea, was Eni’s only producing asset in Alaska. In 2009, production amounted to 6 KBBL/d (2 KBBL/d net to Eni).

There are ongoing activities relating to the phased development plan of the Nikaitchuq field (Eni’s interest 100%) which is located in the North Slope basins. The first oil is expected in 2011 with peaking production at 28 KBBL/d.

Venezuela. Eni has been present in Venezuela since 1998. In 2009, Eni’s production averaged 8 KBBL/d.

Activity is concentrated in the Gulf of Venezuela and in the Gulfo de Paria.

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 the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP).

The Corocoro (Eni’s interest 26%) field is Eni’s only producing asset in the country. A second development phase is expected to be designed based on the results achieved in the first development phase relating to the well

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production rate and field performance under water and gas injection. A production peak of 40 KBBL/d (10 net to Eni) is expected in 2012.

A large gas discovery was made in the Perla field, located in the Cardon IV block (Eni 50%) in the Gulf of Venezuela, yielding 21 mmCF/d (approximately 3.7 KBOE/d) during flow tests. The field has been estimated to contain significant amount of resources. The Perla 2 well has been successfully drilled. The appraisal activity is progressing. Management expects to rapidly commence development activities, targeting early production in 2013.

On January 26, 2010 Eni and the Venezuelan National Oil Company, PDVSA, signed an agreement for the joint development of the giant field Junin 5, located in the Orinoco oil belt. Production start-up is planned for 2013 at an initial level of 75 KBBL/d and a target of long term production plateau of 240 KBOE/d. Development will be conducted through an "Empresa Mixta" (Eni 40%, PDVSA 60%). At the time of the establishment of the "Empresa Mixta", Eni will pay a bonus of $300 million, and additional amount of $346 million will be paid upon the achievement of certain project milestones. Finally, Eni will present a project for the construction of a power plant in Guiria peninsula.

Eni also holds interest in the Blanquilla and Tortuga exploration blocks in the Caribbean Sea, both with a 20% interest over an area of approximately 5,000 square kilometers.

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

Australia and Oceania

Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2009, Australia and Oceania area accounted for 1% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2000. In 2009 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-33-L (Eni’s interest 100%), 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 8 as operator and in 4 of which with a 100% interest), of particular interest are the Alberts blocks (WA-362/363/386/387-P) and JPDA 06-15 (Eni’s interest 40%), where the Kitan discovery is located. The Kitan development activities started in April 2010.

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

In 2009, production start-up was achieved at the Blacktip gas field (Eni’s interest 100%) located in the north western offshore in the South Bonaparte basin by means of a production platform linked to an onshore treatment plant with a capacity of 42 BCF/y. Natural gas produced from this field is sold under a 25-year contract signed with Power & Water Utility Co to fuel a power plant. In 2010 a production of 71 mmCF/d is expected.

Ongoing further development phase (phase 2) of the Bayu Undan field (Eni’s interest 10.99%) is underway aimed at increasing liquids production and maintaining the field’s production profile.

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

 

Capital Expenditures

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

 

 

Gas & Power

Eni’s Gas & Power segment engages in supply, transport, distribution, storage, re-gasification and marketing of natural gas, electricity and LNG. This segment also includes the activity of power generation that is ancillary to the marketing of electricity.

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In the context of a changed demand outlook and stronger competitive pressures both on the European and Italian markets, Eni’s strategy in its Gas & Power segment aims at: (i) increasing international sales with the support of the integration of Distrigas; (ii) maintaining market share and profitability of Italian gas marketing operations; and (iii) increasing operational efficiency and effectiveness in the marketing, in the regulated businesses (i.e. Italian transport, distribution and storage activities) and power generations activities.

In 2009, the market environment was extremely difficult and the outlook for 2010 remains uncertain. Demand is slowly recovering from the huge contraction registred in 2009 as a severe economic downturn caused lower consumption, in particular in the power generation and industrial sectors. Assuming normal seasonal effects, European gas demand in 2009 declined by 7.4% from 2008 and the Italian market contracted by approximately 9 BCM from 2008, down 10%, and almost 10 BCM from the pre-crisis levels of 2007, down 12%.

In a period of lower demand, new gas supplies entered the market as several operators, including Eni, completed plans to upgrade gas import pipelines from gas producing countries or to build new facilities to import gas to Europe. In particular, Eni finalized plans to upgrade the import capacity of its two main pipelines from Russia and Algeria (the gas pipelines TAG and TTPC) by 13 BCM/y with new capacity entirely sold to third parties. A new LNG terminal with a capacity of 8 BCM/y commenced operations late in 2009, operated by a consortium of competitors. A situation of oversupply emerged from those trends. This situation was exacerbated by increased availability of LNG on the marketplace as the main market for LNG, the U.S., reduced its dependence on LNG imports due to greater production of gas from non-conventional sources. Large gas availability at the European hubs drove down spot prices which fell below the level of gas prices based on oil-linked formulas. Considering that a number of projects have been announced or sanctioned by Eni’s competitors in order to further expand gas import capacity to Europe, management believes that the situation of oversupply will persist for some time which will continue to resulting in price and margin pressures.

Additionally, ongoing patterns towards energy preservation and rising competition from renewable or alternative sources of energy will further dampen recovery perspectives of gas demand. Specifically, at the March 2007 European Council, the European Heads of Government decided to adopt the Climate Action and Renewable Energy Package. This legislation was voted on by the European Parliament in December 2008. The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 from emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as a 20% improvement in energy efficiency within the EU Member States by 2020 and a 20% increase in renewable energy by 2020.

The combined impact of all these trends will weigh on the perspectives of a rapid demand recovery. Based on current assumptions and its ongoing perception of market trends, management expects that the gas market will recover the consumption levels of 2008 by 2013. Beyond 2013, management forecasts that demand will resume growing as gas is the cleanest fossil fuel due to its higher environmental compatibility as compared to other fossil fuels, widespread use of gas in power generation and economic and demographic development.

In consideration of a changed demand outlook, management has decreased its long-term projections of European gas demand growth from a previous compound average growth rate (c.a.g.r.) of 2% until 2020 to a revised 1.5% c.a.g.r. These assumptions imply an overall consumption level of approximately 600 BCM by 2020 compared to a previous forecast of 720 BCM. Management also expects the Italian market to grow less than anticipated at an annual rate that will be slightly lower than 2%, implying a level of consumption amounting to 94 BCM versus a previous forecast of 107 BCM by 2020. Considering that the European internal production of natural gas is declining, Europe will be increasingly dependent on gas imports. In such a scenario, Eni’s long-term supply contracts and access to transport infrastructures will a remain competitive advantage.

For more detailed information about this topic and risks associated with those obligations, see "Item 3 – Risk Factors", "Item 5 – Contractual Obligations" and "Item 5 – Management expectations".

In spite of an unfavorable trading environment and weak demand outlook, management intends to drive sales growth and support marketing margins. Planned actions are targeted to expand sales volumes and revenues in the European markets where the Company’s presence is well established and market opportunities are being created. Those markets will include France, Germany, the Benelux countries and continental hubs in North Europe. Management plans to achieve sales volumes in Europe (excluding Italy) of approximately 59 BCM by 2013, with an annual growth rate of 6% from 2009 when sales in European markets amounted to 47 BCM (this amount comprises 44.97 BCM of sales of the Gas & Power segment and approximately 2 BCM of the Exploration & Production segment). The drivers of this growth are expected to be the integration of Distrigas activities, Eni’s competitive advantages ensured by gas availability under long-term supply contracts and equity gas, also including benefits associated with contract re-negotiations, access to infrastructures, long-term relationships with key producing countries (mainly Russia, Algeria and Libya), market knowledge, a widespread commercial sale force and a diversified portfolio of clients.

In Italy, management intends to preserve profitability against the backdrop of a weak demand outlook and increased competition by leveraging on a number of marketing initiatives designed to enhance the Company’s gas

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offer, by: (i) diversifying the offer in terms of combinations of pricing and services designed to better suit different customers’ needs; (ii) implementing a market approach tailored on local conditions; (iii) increasing capillarity through wide sale-force presence; and (iv) developing the combined offer of gas and power (“dual offer”) to drive sales to both business and retail customers.

Overall, Eni plans to increase worldwide gas sales targeting a volume of 118 BCM by 2013 with an average annual growth rate higher than 3% in the 2010-2013 period.

The achievement of sales and margin targets in both European markets and the Italian market will be supported by the impact of recent renegotiations of the Company’s long-term supply contracts with producers. The Company also expects that renegotiations will enable it to gain more operational flexibility in fulfilling contractual obligations with respect to off-taking minimum annual quantities. See discussion on the Company’s take-or-pay contracts below.

Management plans to strongly focus on cost control as a way to improve marketing margins. The action on costs will include a planned reduction in the cost to serve residential clients and optimizing operating and maintenance costs in power generation.

In the regulated businesses in Italy, management plans to deliver steady profitability as new investments will come on line benefiting from guaranteed returns from the Italian Authority for Electricity and Gas, as well as operating synergies deriving from the integration of all regulated Italian businesses in a single entity.

Over the medium term management intends to sustain the Company’s actions by a disciplined capital expenditure plan focused in particular on the regulated businesses in Italy. Specifically, in the next four-year period Eni plans to invest approximately euro 8.3 billion in the Gas & Power segment of which euro 6.4 billion will mainly be devoted to: (i) expanding and upgrading transport networks in order to match the requirements of additional flexibility and security of the system. More than 80% of the total transport capital expenditures will continue to receive a 2% or 3% premium on the base allowed return; (ii) upgrading storage regulated capacity, both through the development of new fields and the expansion of existing capacity; and (iii) upgrading and developing local distribution networks. In addition, management plans to invest the remaining euro 1.8 billion capital expenditures in marketing activities by completing power plant upgrading and increasing generation flexibility (euro 0.7 billion), as well as in international marketing activities (euro 1.1 billion), including a storage project in the Hewett area off the British coast, to sustain growth in European markets.

The matters regarding future natural gas demand and sales target discussed in this section and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future natural gas demand include changes in underlying economic factors, changes in regulation, population growth or shrinkage, changes in the relative mix of demand for natural gas and its principal competing fuels, and unexpected developments in the markets for natural gas and its principal competing fuels.

 

Supply of natural gas

In 2009, Eni’s consolidated subsidiaries supplied 88.65 BCM of natural gas, a decrease of 1 BCM, or 1.1%, from 2008, due to declining gas demand whose impact was partly offset by the full consolidation of Distrigas.

Gas volumes supplied outside Italy (81.79 BCM from consolidated companies), imported in Italy or sold outside Italy, represented 91% of total supplies, an increase of 0.14 BCM, or 0.2%, from 2008, mainly due to the full contribution of Distrigas, whose main sources of supplies are long-term contracts with Norway, the Netherlands and Qatar via LNG, as well as spot markets in Western Europe. As a result, in 2009 higher volumes were purchased from: (i) Norway (up 5.68 BCM); (ii) Qatar (up 2.20 BCM); and (iii) the Netherlands (up 1.90 BCM).

Due to market trends, in particular a weak demand environment in Italy, the Gas & Power segment reduced its gas purchases from: (i) Algeria (down 5.40 BCM) which was also impacted by damage incurred to the TMPC pipeline in late December 2008; (ii) Libya (down 0.73 BCM); and (iii) Russia, where the Company reduced its off-takes by 2.75 BCM directed mainly to Italy. In addition, the reduction reflected the implementation of agreements with Gazprom which provided their entrance into the supplies market to Italian importers whereby Eni agreed to reduce its off-takes. This line item also includes volumes purchased to be resold on the Hungarian market.

Supplies in Italy (6.86 BCM) declined by 1.14 BCM from 2008, or 14.3%, due to lower domestic production.

In 2009, main gas volumes from equity production derived from: (i) Italian gas fields (6.5 BCM); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2009 these two fields supplied 2.5 BCM net to Eni; (iii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.9

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BCM); and (iv) other European areas (in particular Croatia with 0.8 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 20.7 BCM representing 20% of total volumes available for sale.

In 2009, volumes from storage deposits owned by Eni’s subsidiary Stoccaggi Gas Italia increased to 1.25 BCM compared to net input of natural gas volumes of 0.08 BCM in 2008.

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

Natural gas supply		2007		2008		2009

(BCM)

Italy		8.65			8.00			6.86
Outside Italy		75.15			81.65			81.79
Russia		23.44			22.91			22.02
Algeria (including LNG)		18.41			19.22			13.82
Libya		9.24			9.87			9.14
the Netherlands		7.74			9.83			11.73
Norway		5.78			6.97			12.65
the United Kingdom		3.15			3.12			3.06
Hungary		2.87			2.84			0.63
Qatar (LNG)		-			0.71			2.91
Other supplies of natural gas		2.20			4.07			4.49
Other supplies of LNG		2.32			2.11			1.34
Total supplies of subsidiaries		83.80			89.65			88.65
Withdrawals from (input to) storage		1.49			(0.08	)		1.25
Network losses, measurement differences and other changes		(0.46	)		(0.25	)		(0.30	)
Volumes available for sale of Eni’s subsidiaries		84.83			89.32			89.60
Volumes available for sale of Eni’s affiliates		8.74			8.91			7.95
E&P volumes		5.39			6.00			6.17
Total volumes available for sale		98.96			104.23			103.72

In order to secure long-term access to gas availability, in particular in view of supplying the Italian gas market, the Company has signed a number of long-term gas supply contracts with the key producing countries that supply the European gas markets. These contracts will ensure approximately 62.4 BCM of gas availability in 2010 (excluding the contribution of other subsidiaries and associates) with a residual life of approximately 20 years, and provide take-or-pay clauses whereby the Company is required to collect minimum predetermined volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of it, of uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. Amounts of cash pre-payments and time schedules for collecting pre-paid gas vary from contract to contract. Generally speaking, cash pre-payments are calculated on the basis of the energy prices current in the year of non-fulfillment with the balance due in the year when the gas is actually collected. Amounts of pre-payments range from 10 to 100 percent of the full price. The right to collect pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, rights to collect pre-paid gas in future years can be exercised provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity that can be collected in each contractual year. In this case, Eni will pay the residual price calculating it as the percentage that complements 100, based on the arithmetical average of monthly base prices in place in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.

Management believes that the current outlook for gas demand and large gas availability on the marketplace, as well as the possible evolution of sector-specific regulation, represent risks factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts. In 2009, Eni collected lower volumes than its minimum take due to an unfavorable demand environment. As a result, the Company deferred the relevant purchase costs to future periods by recognizing a non-current asset in the consolidated balance sheet. The non-current asset was recorded against a trade payable for an amount of euro 255 million based on the contractual purchase price formula provided in the relevant contractual arrangements and the contractual percentage of advance, as aligned to their net realizable value as of year end. The Company expects to collect the underlying gas volumes over a period longer than the next twelve months.

Management believes that over the next two years the Company will experience failure in fulfilling its take-or-pay obligations associated with significant volumes of gas, unless demand fundamentals improve substantially and a

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better balance between demand and supply is achieved in the marketplace. Currently, the Company is unable to forecast the timing of such a recovery.

However, based on management’s projections for sales volumes and prices for the four-year plan and subsequent years, volumes for which an obligation to pay cash advances might arise due to take or pay clauses, will be off-taken within contractual terms, thus recovering cash advances. Even if financing associated with cash advances are factored in, the net present value associated with those long-tem contracts discounted at the weighted average cost of capital for the Gas & Power segment still remains positive and consequently those contracts do not fall within the category of an onerous contract as prescribed by IAS 37. The assessment of the Company’s take-or-pay supply contracts also considered the impact of contract renegotiations that have recently been finalized or are progressing whereby the Company has improved both its purchase costs and operational flexibility.

For more detailed information about this topic and risks associated with those obligations, see "Item 3 – Risk Factors" and "Item 5 – Contractual Obligations".

 

Marketing

Natural Gas Sales for the Year 2009

In 2009, worldwide natural gas sales of 103.72 BCM, including own consumption, sales by affiliates and E&P sales in Europe and in the Gulf of Mexico, declined slightly from 2008 (down 0.51 BCM, or 0.5%) mainly due to the negative effects of sharply lower gas demand in Italy (down 10%) and Europe (down 7.4% both percentages net of seasonal swings). These decreases were partially offset by the contribution of the Distrigas acquisition (up 12.02 BCM) and the organic growth recorded in the European markets.

Natural gas sales in Italy were 40.04 BCM (including own consumption and sales by affiliates) a decline of 12.83 BCM from 2008, or 24.3%.

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, that 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, 2009, Eni’s customers in Italy were 6.88 million.

In Italy, sales volumes decreased by 12.83 BCM, or 24.3%, to 40.04 BCM reflecting sharply lower supplies to power generation utilities (down 8.01 BCM), industrial customers (down 2.01 BCM) and wholesalers (down 1.60 BCM) dragged down by a decline in industrial production following the economic downturn and competitive pressures, especially in the last part of the year which was affected by new gas availability. Volumes sold to the residential sector increased slightly due to higher weather-related sales, particularly in the first and fourth quarter of 2009 and higher volumes destined to Eni’s power generation business.

Sales to importers in Italy (10.48 BCM) decreased by 0.77 BCM, or 6.8%.

Gas sales in European markets (44.97 BCM including affiliates and the contribution of Distrigas acquisition) increased by 13.19 BCM, or 41.5%, benefiting from the contribution of Distrigas (up 12.02 BCM) and also reflecting market share gains. Excluding the impact of Distrigas, sales of natural gas on European markets amounted to 27.72 BCM, increasing by 1.17 BCM, or 4.4%, mainly due to the growth registered in: (i) France (up 1.27 BCM) and in Northern Europe (up 1.10 BCM). These increases were offset in part by lower volumes reported in supplies to importers in Italy (down 0.77 BCM), in the Iberian Peninsula (down 0.63 BCM) and Hungary (down 0.24 BCM) as a result of decreased demand.

Sales to markets outside Europe (2.06 BCM) decreased by 0.27 BCM from 2008.

E&P sales in Europe and the United States increased by 0.17 BCM, or 2.8%.

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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		2007		2008		2009

(BCM)

Total sales of subsidiaries		84.83		89.32		89.60
Italy (including own consumption)		56.08		52.82		40.04
Rest of Europe		27.86		35.61		48.65
Outside Europe		0.89		0.89		0.91
Total sales of Eni’s affiliates (Eni’s share)		8.74		8.91		7.95
Italy		0.05		0.05		-
Rest of Europe		7.16		7.42		6.80
Outside Europe		1.53		1.44		1.15
Total sales of G&P		93.57		98.23		97.55
E&P in Europe and in the Gulf of Mexico (a)		5.39		6.00		6.17
Worldwide gas sales		98.96		104.23		103.72

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(a)

E&P sales include volumes marketed by the Exploration & Production division in Europe (3.59, 3.36 and 2.57 BCM in 2007, 2008 and 2009, respectively) and in the Gulf of Mexico (1.80, 2.64 and 3.60 BCM in 2007, 2008 and 2009, respectively).

 

Natural gas sales by market		2007		2008		2009

(BCM)

ITALY		56.13		52.87		40.04
Wholesalers		10.01		7.52		5.92
Gas release		2.37		3.28		1.30
Italian gas exchange and spot markets		1.90		1.89		2.37
Industries		11.77		9.59		7.58
Medium-sized enterprises and services		1.00		1.05		1.08
Power generation		17.21		17.69		9.68
Residential		5.79		6.22		6.30
Own consumption		6.08		5.63		5.81
INTERNATIONAL SALES		42.83		51.36		63.68
Rest of Europe		35.02		43.03		55.45
Importers in Italy		10.67		11.25		10.48
European markets		24.35		31.78		44.97
Iberian Peninsula		6.91		7.44		6.81
Germany-Austria		5.03		5.29		5.36
Belgium		-		4.57		14.86
Hungary		2.74		2.82		2.58
Northern Europe		3.15		3.21		4.31
Turkey		4.62		4.93		4.79
France		1.62		2.66		4.91
Other		0.28		0.86		1.35
Extra European markets		2.42		2.33		2.06
E&P in Europe and in the Gulf of Mexico		5.39		6.00		6.17
WORLDWIDE GAS SALES		98.96		104.23		103.72

 

Marketing of Electricity

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market mainly on the open market, at industrial sites and on the Italian Exchange for electricity. Supplies of electricity include both own production volumes through gas-fired, combined-cycles facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value-chain leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and middle to large industrial users, the Company has been developing a commercial offer that provides the combined supply of gas and power. In 2009, the program for expanding the combined integrated offer of gas and power progressed in accordance with the Company’s expansion plans.

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Notwithstanding weaker domestic demand, in 2009 sales of power amounted to 33.96 TWh, an increase of 4.03 TWh, or 13.5%, from 2008, also as a result of leveraging the dual-offer penetration. The increase mainly related to: (i) higher sales on open markets, in particular the retail market, with an increased number of clients served following intensive marketing campaigns, and to wholesalers due to the start of VPP (Virtual Power Plant) supply agreements signed at the end of 2008. Sales to large clients, on the other hand declined due to a reduction in the customer base and the impact of the economic downturn; and (ii) higher volumes traded on the Italian power exchange (up 0.88 TWh, or 23%).

Sales of power were directed to the free market (73%), the Italian power exchange (14%), industrial sites (9%) and others (4%).

Power availability		2007		2008		2009

(TWh)

Power generation sold		25.49		23.33		24.09
Trading of electricity (a)		7.70		6.60		9.87
		33.19		29.93		33.96
Power sales by market
Free market		20.73		22.89		24.74
Italian Exchange for electricity		8.66		3.82		4.70
Industrial plants		2.81		2.71		2.92
Other (a)		0.99		0.51		1.60
		33.19		29.93		33.96

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(a)

Include positive and negative imbalances.

 

Planned Actions and Sales Target

(i) Italy

Over the medium-term, management expects that the Italian gas market will experience by weak growth and greater competition as a result of the economic slowdown and the entry on the market of new supplies related to the upgrade of import infrastructures and the coming on stream of new LNG facilities. Adding further to the risk of oversupply, certain competitors have recently announced plans to build new import facilities targeting the longer-term.

In order to support sales volumes and profitability of its marketing operations in Italy, Eni intends to implement an effective marketing policy, setting up new offer structures that fully match the diversified requirements of Eni’s customers, especially for the business segments. In the retail market Eni plans to adopt an approach tailored on local specific conditions, leveraging on the capillarity of its commercial presence. The combined offer of gas and power (dual offer) is expected to drive sales growth to both business and retail customers. Large industrial clients will be retained based on selective marketing policies targeting the most valuable and profitable ones. Volumes sold to thermoelectric utilities are expected to remain at current levels.

Eni expects significant margin pressures due to the impact of increasing competition and actions from competitors intended to gain market share. Management is focused on preserving gas margins by means of tight cost control. Cost efficiencies are expected to derive from 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 deriving from the dual offer in terms of process integration for acquiring, retaining and handling customers. Management also expects that the Company’s supply costs for raw material will be more aligned with current market conditions as the Company has renegotiated or is in the process of renegotiating its main long-term supply contracts.

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(ii) European Markets

In the future, Eni intends to strengthen its presence in the European gas markets, targeting to increase both sale volumes and market shares. By implementing this growth strategy, the Company intends to make for lower growth prospects on the Italian market. A review of Eni’s presence in the key European markets is presented below.

Benelux. The integration with Distrigas granted Eni a strong presence in the gas market of the Benelux countries (Belgium, the Netherlands and Luxembourg) and a significant exposure to spot markets in Western Europe. Distrigas is a key operator in Benelux, particularly 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. In 2009, Distrigas sales amounted to 15.72 BCM. Distrigas has diversified sources of supply with its long-term supply contracts from the Netherlands, Norway and Qatar, as well as spot markets and access to relevant transport infrastructures. Most importantly, Distrigas’ presence on spot markets ensures a high degree of flexibility as the Company is able to dispose of part of its gas availability under long-term contracts whenever market opportunities arise. In 2009, Eni delivered the planned synergies of integrating Distrigas operations by picking revenue opportunities and cost optimizations. Over the medium term, Eni plans to achieve further synergies by leveraging on market opportunities associated with Distrigas access to transport infrastructures, its presence in the main European markets and cost efficiencies to be achieved by integrating commercial operations, including optimization of logistics, reductions in general and administrative costs and back-end expenses. The Company also expects to deliver synergies by optimizing the supply portfolio of Eni and Distrigas.

France. Eni sells natural gas to industrial clients, wholesalers and power generation as well as to the segments of small business and retail segments. Eni’s presence consists of direct commercial activities and the partnerships with Altergaz in which it holds a 41.62% interest and Gaz de Bordeaux SAS with a 17% interest (and a further 17% interest held by Altergaz). Altergaz supplies approximately 69,000 clients, of which 58,000 are residential customers (23,000 in 2008, of which 17,000 residentials). Eni will benefit from Altergaz’s development plans as Eni already supplies 1.3 BCM/y to its associate. Gaz de Bordeaux engages in selling natural gas in the municipality of Bordeaux. Eni plans to develop this partnership.

Furthermore, the integration with Distrigas’ marketing activities will provide Eni with further opportunities to expand its market share in the country.

Germany-Austria. Eni is present in the German natural gas market through its associate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 3.98 BCM in 2009 (1.99 BCM being Eni’s share), and through a direct marketing structure which sold in 2009 approximately 2.5 BCM in Germany and 0.8 BCM in Austria.

Iberian Peninsula

Portugal. Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%) which sold approximately 4.34 BCM in 2009 (1.45 BCM being Eni’s share).

Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2009 UFG gas sales in Europe amounted to 4.68 BCM (2.34 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 (42.5% and 18.9%, respectively). In 2009 Eni sales in Spain amounted to 5.36 BCM representing a slight decline from a year ago.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2009 sales amounted to 4.79 BCM, a decrease of 2.8% from a year ago.

UK/Northern Europe. Eni through its subsidiary North Sea Gas & Power (Eni UK Ltd) markets in the UK the equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF).

Projects in the Hewett area. Eni is assessing the technical and economic aspects of a project intended to build an offshore storage facility in the Hewett area (Eni’s interest 89%) located in the Southern Gas Basin in the North Sea, near the Bacton terminal, where certain depleted fields are expected to be converted to gas storage deposits. Peak working gas is estimated at 5.6 BCM with a production of approximately 60 mmCM/d. An appraisal well is planned to be drilled shortly, whose outcome will provide further data to confirm those estimates. The storage capacity will support Eni’s production, sales and trading activities in Europe by providing the necessary flexibilityto manage seasonal swings of gas demand in the United Kingdom. The activity of gas storage in the UK is de-regulated and results from this project are expected be reported within the “Marketing business”.

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The project sanction is expected in 2010 with start-up planned in 2015.

 

(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 all phases of the LNG business: liquefaction, shipping, regasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is tied to the Company’s plans to develop its large gas reserve base in Africa. The LNG business has been deeply impacted by the economic downturn of 2009 and structural modifications in the U.S. market where large availability of gas from non traditional sources promise to reduce in perspective the country’s dependence from gas imports via LNG.

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

Italy. Eni, through Snam Rete Gas, operates the re-gasification 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.

Management is planning to upgrade the Panigaglia terminal capacity from the current 3.5 BCM to 8 BCM in the future.

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

Egypt. Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant which produces approximately 5 mmtonnes/y of LNG which equates to a feedstock of 7.56 BCM/y in natural gas. In 2009, the Gas & Power segment withdrew 0.96 mmtonnes of LNG (approximately 1.4 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 9.6 BCM/y. At present, Eni’s capacity entitlement amounts to 1.9 BCM/y of gas.

Eni through Unión Fenosa Gas also holds a 9.45% interest in the El Ferrol regasification plant, located in Galicia, which started operations in November 2007, with a treatment capacity of approximately 4.0 BCM/y, of which 0.35 BCM/y being Eni’s capacity entitlements.

USA

Cameron. In the third quarter of 2009, operations started at the Cameron re-gasification plant located on the banks of the Calcasieu River, approximately 15 miles south of Lake Charles in Louisiana, USA.

In consideration of a changed demand outlook, Eni renegotiated certain terms of the contract with the U.S. company Cameron LNG, relating to the farming out of a share of the regasification capacity. The new agreement provides that Eni will be entitled to a daily send-out of 572,000 mmBTU (approximately 5.7 BCM/y) and a dedicated storage capacity of 160 thousand CM, which will provide Eni more flexibility in managing seasonal swings in gas demand.

Taking into account current conditions of oversupply on the U.S. gas market, Eni rescheduled the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant. The start-up is now expected in 2015.

Pascagoula. This project is part of an upstream development related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 BCM/y) for the North American market in order to market part of the Company’s gas reserves. As part of the downstream leg of the project, Eni signed a 20 year contract with Gulf LNG to buy 5.8 BCM/y of the regasification capacity of the plant under construction near Pascagoula in Mississippi. The expected start-up is by the end of 2012 which is in line with the start-up of the upstream project in Angola.

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At the same time Eni Usa Gas Marketing Llc entered a 20-year contract for the purchase of approximately 0.9 BCM/y of regasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG.

LNG sales		2007		2008		2009

(BCM)

G&P sales		8.0		8.4		9.8
Italy		1.2		0.3		0.1
Rest of Europe		5.6		7.0		8.9
Extra european markets		1.2		1.1		0.8
E&P sales		3.7		3.6		3.1
Liquefaction plants:
- Bontang (Indonesia)		0.7		0.7		0.8
- Point Fortin (Trinidad & Tobago)		0.6		0.5		0.5
- Bonny (Nigeria)		2.0		2.0		1.4
- Darwin (Australia)		0.4		0.4		0.4
		11.7		12.0		12.9

 

Power Generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in Bolgiano, where a new plant was recently acquired.

In 2009, power generation was 24.09 TWh, up 0.76 TWh, or 3.3% from 2008, mainly due to higher production at the Ferrara plant (Eni’s interest 51%), in connection with two new 390 megawatt combined cycle units coming on line.

As of December 31, 2009, installed operational capacity was 5.3 GW (4.9 GW in 2008).

Power availability in 2009 was supported by the growth in electricity trading activity (up 3.27 TWh from 2008, or 49.5%) due to higher volumes traded on the Italian power exchange as a result of lower purchase prices.

By 2013 Eni intends to complete its plan for expanding its power generation capacity, targeting an installed operational capacity of 5.4 GW⁸.

At full capacity in 2013, production is expected to amount to approximately 26 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 the third power producer in Italy.

Supplies of natural gas are expected to amount to approximately 5.3 BCM/y from Eni’s diversified supply portfolio.

Residual expected capital expenditure amounts to euro 0.7 billion in addition to the euro 2.4 billion already invested until 2009. Development plans are underway at Taranto (Eni 100%) and Ferrara (Eni 51%), as well as at the recently acquired Bolgiano plant (Eni 100%).

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, using the CCGT technology instead of conventional power generation technology, the emission of carbon dioxide reduces by approximately 5 mmtonnes, on an energy production of 26.5 TWh. The 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

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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, has defined a 0.75% increase of this ratio for the periods from 2007 to 2009.

Eni’s main operated power plants are described below.

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

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

Brindisi. This power plant has been upgraded by installing three new combined cycle units, each with a capacity of 390 MW, which has increased the overall capacity to approximately 1,500 MW.

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

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

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

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

Bolgiano. The existing power plant has an installed capacity of approximately 39 MW divided between four gas turbines associated with four super-heated water generators.

 

Power Generation		2007		2008		2009

Purchases
Natural gas		(mmCM)		4,860		4,530		4,790
Other fuels		(ktoe)		720		560		569
- of which steam cracking				137		131		82
Production
Electricity		(TWh)		25.49		23.33		24.09
Steam		(ktonnes)		10,849		10,584		10,048
Installed generation capacity		(GW)		4.9		4.9		5.3

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Infrastructures

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

In Italy, Eni operates almost all the lines which form the national transport network, gas underground storage deposits and related facilities, a re-gasification plant in Panigaglia and can count on an extended system of local distribution networks. Eni is implementing plans for expanding and upgrading its national transport and distribution networks and storage capacity.

 

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		103.6		75		7
Tarvisio-Sergnano-Minerbio		3		433		42/36, 34 e 48/56		119.7		58/75		3
Passo Gries-Mortara		1/2		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)		Transport capacity refers to the capacity at the entry point connected to the import pipelines.
(2)		Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(3)		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

Eni owns capacity entitlements in an extensive network of international high pressure pipelines for a total length of approximately 4,400 kilometers enabling the Company to import natural gas produced in Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya to Italy. The Company participates in certain entities which own and operate those international pipelines, the pipeline owners, as well as in the entities which manage transportation rights, the carries companies. For financial reporting purposes, such entities are fully-consolidated or equity-accounted depending on the Company’s interest or agreements with other shareholders.

Management believes that the structure of the Company’s interests in those entities may undergo significant changes in the near future depending on the possible evolution of an antitrust proceeding before the European Commission relating to allegedly anti-competitive practices in the European market of natural gas, consisting in limiting third parties access to Eni’s participated gas pipelines thus restricting gas availability in Italy. The proceeding is fully disclosed in Note 28 to the Consolidated Financial Statements – Legal Proceedings. As part of that matter, on February 4, 2010, Eni formally filed a set of structural remedies relating certain international gas pipelines with the European Commission. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test, Eni will be in the position to settle the above mentioned antitrust proceeding without imposition of any fine or other measures. In light of the strategic importance of the Austrian TAG pipeline to the supply of the Italian system, which transports gas from Russia to Italy, Eni negotiated a solution with the Commission which called for the transfer of its stake to an entity controlled by the Italian State. If they are implemented, the remedies negotiated with the Commission will not affect Eni’s contractual gas transport rights.

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A description of the main international pipelines participated or operated by Eni 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 five 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. In 2009, the upgrading of this facility was finalized by completing construction of two new compression stations that increased transport capacity by 6.5 BCM/y. The entire new capacity has been entirely awarded to third parties.
•		The TTPC pipeline, 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. The pipeline was recently upgraded by increasing compression capacity in order to enable transportation of an additional 6.5 BCM/y. The upgrade was finalized in 2008 and became fully operational during 2009.
•		The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 BCM/y. It crosses the underwater Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system. In 2009, the operation of TMPC gas pipeline was fully restored. One of the five lines of the import pipeline from Algeria was damaged by an oil tanker anchor crossing the Sicily channel on December 19, 2008.
•		The TENP pipeline is 1,000-kilometer long (two 500-kilometer long lines) and has transport capacity of 15.5 BCM/y and four compression stations. It transports natural gas through Germany, from the German-Dutch border of Bocholtz to Wallbach at the German-Swiss border.
•		The Transitgas pipeline is 291-kilometer long and has one compression station, that transports natural gas across 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 Oltingue/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 started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 BCM/y and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system. In 2009, the pipeline was upgraded by 3 BCM/y, which are expected to come fully on stream in 2010, bringing total capacity to 11 BCM/y. This additional capacity will support Eni’s plans to increase gas production at its Libyan field to be implemented over the next four years.

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

 

The South Stream project

Eni and Gazprom are jointly assessing the technical and economic aspects of a project to build a new import route to Europe to market gas produced in Russia.

Based on the agreements signed between Italy and Russia on May 15, 2009, the original scope of work of the project to build the South Stream pipeline has been enlarged, providing for an increase in transport capacity from the originally planned 31 BCM/y to 63 BCM/y.

The South Stream pipeline is expected to be composed by two sections: (i) an offshore 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; and (ii) an onshore section crossing Bulgaria for which two options are currently being evaluated: one pointing North West and another one pointing South West. The second option envisages crossing Greece and the Adriatic Sea before linking to the Italian network.

In December 2009, Eni and Gazprom signed an agreement for the entrance of the French company Edf in the project. The conditions of the agreement will be defined in the coming months.

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Regulated businesses in Italy

Eni, through Snam Rete Gas, a company listed on the Italian Stock Exchange, in which Eni holds a 52.54% interest, operates most of the Italian natural gas transport network, a re-gasification terminal located in Panigaglia, an extensive local distribution network and gas underground storage deposits and related facilities.

In 2009, management completed the reorganization of Eni’s regulated businesses in Italy by combining into a single entity all gas-related infrastructures whose remuneration is established by the Italian Authority for Electricity and Gas. The reorganization was implemented by divesting the parent company’s interests in Italgas SpA (100%) and Stoccaggi Gas Italia SpA (100%) to Snam Rete Gas, a subsidiary. The transaction is expected to deliver significant synergies for regulated businesses allowing Eni to maximize the value of both gas distribution and storage activities. For more details on this deal see "Significant Business and Portfolio Developments" above.

Management plans to invest approximately euro 6.4 billion in the next four years in the regulated businesses mainly directed to upgrading and developing the transport and distribution networks and storage capacity, aiming at strengthening security, flexibility and service quality of the gas infrastructures.

Specifically, in the next four-year period Eni plans to expand and upgrade transport networks (approximately euro 4.3 billion), the storage regulated capacity (approximately euro 1 billion), both through the development of new fields and the expansion of existing capacity, and upgrade and develop local distribution networks as well as to provide the substitution of old metering (approximately euro 1.1 billion).

 

Italian Transport Activity

Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, transport and re-gasification 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 more than 31,500 kilometers and comprises: (i) a national transport network extending over 8,871 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 22,660 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):
		-		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 583-kilometer long (of these 505 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 104 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 33 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 connecting 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 a diameter from 48 to 56 inches. The pipeline transport capacity at the Tarvisio entry point amounts to approximately 120 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 and 177-kilometer long that 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:

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		-		one line, with a 30-inch diameter and 170-kilometer long that 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 receives gas from the LNG terminal located offshore of Porto Viro. The pipeline transport capacity at the Cavarzere entry point amounts to 26 mmCM/d.

Eni’s system is completed by: (i) eleven compressor stations with a total power of 857 MW used to increase gas pressure in pipelines to the level required for its flow; and (ii) four marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo and Messina 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 the regulation of the flow of natural gas in the network and guarantee the connection of pipes working at different pressures.

In 2009, volumes of natural gas input in the national grid (76.90 BCM) decreased by 8.74 BCM, or 10.2%, from 2008, mainly due to lower gas deliveries as a result of weaker demand. Eni transported 37.27 BCM of natural gas on behalf of third parties, up 0.09 BCM from 2008, or 10.1%.

Gas volumes transported (a)		2007		2008		2009

(BCM)

Eni		52.39		51.80		39.63
On behalf of third parties		30.89		33.84		37.27
		83.28		85.64		76.90

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(a)

Includes amounts destined to domestic storage.

 

Transport capacity in Italy

		2008-2009 Thermal year		2009-2010 Thermal year

Entry points

Available capacity

Awarded capacity

Saturation

Available capacity

Awarded capacity

Saturation

(mmCM/d)

(mmCM/d)

(%)

(mmCM/d)

(mmCM/d)

(%)

Tarvisio		106.0		97.8		92.2		119.7		102.8		85.9
Mazara del Vallo		101.8		93.2		91.6		103.6		98.7		95.3
Passo Gries		64.9		60.8		93.7		64.9		59.0		90.9
Gela		30.5		30.5		100.0		33.0		32.9		99.7
Cavarzere (LNG)								26.4		21.0		79.5
Panigaglia (LNG)		13.0		11.4		87.7		13.0		7.2		55.4
Gorizia		4.8						4.8
		321.0		293.7		91.5		365.4		321.6		88.0

In 2009, the LNG terminal in Panigaglia (La Spezia) regasified 1.32 BCM of natural gas (1.52 BCM in 2008).

 

Distribution Activity

Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. The subsidiary Italgas and other subsidiaries operate in the distribution activity in Italy serving 1,322 municipalities through a low pressure network consisting of approximately 50,000 kilometers of pipelines supplying 5.8 million customers and distributing 7.73 BCM in 2009.

Under Legislative Decree No. 164/2000, 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.

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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 have a term as long as twelve years.

Distribution activity in Italy		2007		2008		2009

Volumes distributed:		(BCM)		7.44		7.63		7.73
- on behalf to Eni				5.66		6.33		6.26
- on behalf to third parties				1.78		1.30		1.47
Installed network		(km)		48,746		49,410		49,973
Active meters		(No. of users)		5,598,677		5,676,105		5,770,672
Municipalities served		(No.)		1,318		1,320		1,322

For the next four years, Eni has defined a capital expenditures plan of approximately euro 1.1 billion for the development/upgrade of its distribution networks and their technological upgrade, and the substitution of gas metering.

In particular, in the medium-term Eni intends to consolidate its presence in Italy, by increasing the profitability of its asset base, security across the network, and improve the service quality as well as efficiency of services rendered.

 

Storage

Following the divestment of Stogit to Snam Rete Gas (for details on this deal see "Significant Business and Portfolio Developments" above), the results of the storage business conducted in Italy are reported within the Gas & Power segment under the "Regulated Business" starting in 2009. 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, based on ten storage concessions vested by the Ministry of Productive Activities, with a total modulation capacity of 8.9 BCM.

From the beginning of its operations, Stogit progressively increased the number of customers served and the share of revenues from third parties.

Storage		2007		2008		2009

Total storage capacity:		(BCM)		13.6		13.7		13.9
- of which strategic storage				5.1		5.1		5.0
- of which available storage				8.5		8.6		8.9
Available capacity:		(%)
- share utilized by Eni				44		39		30
- share utilized by third parties				56		61		70
Total offtake from (input to) storage:		(BCM)		9.27		11.57		16.52
- input to storage				4.00		6.30		7.81
- offtake from storage				5.27		5.27		8.71
Total customers		(No.)		44		48		56

In 2009, 8.71 BCM of gas were supplied (up 3.44 BCM from 2008) while 7.81 BCM were inputted to Company’s storage deposits, an increase of 1.51 BCM compared to 2008.

In 2009, storage capacity amounted to 13.9 BCM, of which 5 were destined to strategic storage.

The share of storage capacity used by third parties was 70% (61% in 2008).

The Company plans to increase storage capacity in the medium-term.

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Capital Expenditures

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

 

 

Refining & Marketing

Eni’s Refining & Marketing segment engages in refining of crude oil and marketing of refined products primarily in Italy and in Central-Eastern Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share.

The Company’s operations are fully integrated through refining, supply, trading, logistics and marketing so as to maximize cost efficiencies and effectiveness of operations.

In 2009, the trading environment was particularly unfavorable. Refining margins plunged to historical lows due to a rapid recovery in oil prices which the Company was unable to transfer to final prices of refined products due to weak demand, high worldwide and regional inventory levels and excess refining capacity.

In addition, profitability of complex throughputs was severely impacted by significantly compressed light-heavy crude differentials (from 5.1 $/BBL to 1.9 $/BBL in 2008 and 2009, respectively) due to reduced availability of heavy crude oil in the Mediterranean area. Those trends resulted in Eni’s refining margins falling below break-even. Management expects that those trends are likely to persist for the next two to three years as demand for refined products will continue being affected by increasing energy efficiency and use of bio-fuels. The refining capacity is expected to rise particularly in Middle and Far East Asia and the U.S. market will prove less keen to import gasoline. On the positive side, the eventual margin level will be influenced by the pace of the global economic recovery and the extent of refinery rationalization in the face of weak margins.

To cope with this challenging outlook, management plans to:

•		keep tight control on capital expenditures, particularly in refining through strong financial discipline in selecting capital projects;
•		strongly focus on cost reductions and efficiency improvements; and
•		improve profitability of marketing activities by increasing the quality and range of its retail offer including non-oil activities and loyalty programs as well as by upgrading and restyling service stations.

As a result of all these actions, management believes that the Refining & Marketing segment will have a positive cash flow in 2012.

In the 2010-2013 period, capital expenditure is projected at euro 2.7 billion, confirming the same level of the previous plan. However, the share of expenditures dedicated to marketing is planned to increase from 25% to 40% as the Company intends to upgrade its networks in Italy and selected European markets, also finalizing the process of restyling and re-branding to the "eni" brand all service stations. Management plans to upgrade the Company’s best refineries by investing euro 1.6 billion to increase plant conversion and flexibility as well as to comply with all applicable HSE regulations.

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 2009, a total of 67.40 mmtonnes of crude were purchased by the Refining & Marketing division (57.91 mmtonnes in 2008), of which 32.75 mmtonnes was from Eni’s Exploration & Production division. Volumes amounting to 19.71 mmtonnes were purchased under long-term supply contracts with producing countries, while 14.94 mmtonnes were purchased on the spot market. Approximately 25% of crude purchased in 2009 came from West Africa, 19% from European and Asian Russia, 15% from the Middle East, 13% from North Africa, 11% from the North Sea, 4% from Italy and 13% from other areas.

Approximately 36.11 mmtonnes of crude purchased in 2009 were resold, an increase of 38.9% from 2008. In addition, 2.92 mmtonnes of intermediate products were purchased (3.39 mmtonnes in 2008) to be used as feedstock in conversion plants and 13.98 mmtonnes of refined products (17.42 mmtonnes in 2008) were purchased to be sold

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on markets outside Italy (10.10 mmtonnes) and on the domestic market (3.88 mmtonnes) as a complement to available production.

 

Refining

Against the backdrop of a challenging refining environment, in the medium-term management plans to improve the cost position of the Company’s refining operations, while continuing to keep tight control over capital employed and selectively upgrading conversion capacity and flexibility of the best refineries. Cost efficiencies are expected to mainly target labor costs and refinery processes, including energy conservation.

As of December 31, 2009, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 37.3 mmtonnes (equal to 747 KBBL/d) and a conversion index of 59.8%. The conversion index is a measure of a refinery complexity. The higher the index, the wider the spectrum of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies which the Company generally expects to achieve as certain qualities of crude (particularly the heavy ones) may trade at discount with reference to the light crude Brent benchmark. Eni’s five 100-percent owned refineries have balanced capacity of 27.7 mmtonnes (equal to 554 KBBL/d), with a 63.1% conversion rate.

In 2009, refinery throughputs in Italy and outside Italy were 34.55 mmtonnes.

In the next four years, Eni plans to selectively upgrade its refining system by increasing complexity and flexibility at its best refineries. Middle distillate yields are expected to come in at 43% from 41% in 2009 (approximately double of gasoline yields) as the new hydro-cracking units recently started up in Sannazzaro, Taranto and Bayernoil are planned to improve yields. Additionally, management plans to build a new conversion unit at the Sannazzaro refinery which will be based on the EST proprietary technology for converting the heavy barrel by almost eliminating residue from conversion processes. The start-up of this unit is scheduled in 2012. Higher conversion capacity is expected enable the Company to extract value from equity crude as well as capture opportunities of monetizing heavy crudes and non conventional resources.

Management also targets flexibility enhancement at the Company refineries whereby the Company intends to achieve a 15 percentage point increase in the share of spot crude supplies which are destined to processes. Logistics and process optimization will help in selecting the most profitable slate to satisfy market needs for final products. Equity crude volumes processed are also expected to increase from 19.0% to 19.6%.

As result of investment upgrading and efficiency actions and taking into account the expected recovery in market fundamentals and throughputs, improvement in operations are expected to enable refining operations to increase our internally tracked PUI (Process Utilization Index) by 10 percentage points from the current 77% to 87% by 2013.

 

 

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The table below sets forth certain statistics regarding Eni’s refineries as of December 31, 2009.

Refining system in 2009

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		554		63		69		33		37		29		89		46		70		87
Italy
Sannazzaro		100		223		223		180		61		34		11				29		29				78		96
Gela		100		129		129		100		142		35				37						46		60		78
Taranto		100		120		120		110		65				22						38				72		78
Livorno		100		106		106		84		11														66		83
Porto Marghera		100		107		107		80		20										22				69		92
Partially owned refineries (3)				874		245		193		50		163		25				99		27				83		94
Italy
Milazzo		50		248		124		80		73		41		25				32						73		98
Germany
Vohburg/Neustadt      (Bayernoil)		20		215		43		41		36		49						43						95		95
Schwedt		8.33		231		19		19		42		49								27				105		105
Czech Republic
Kralupy e Litvinov		32.4		180		59		53		30		24						24						84		84
Total refineries				1,559		930		747		60		232		58		37		128		116		46		73		89

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(1)		Stated in fluid catalytic cracking equivalent/topping (% by weight), based on 100% of balanced primary distillation capacity.
(2)		Conversion plant where vacuum feedstock undergoes cracking at high pressure and moderate temperature thus producing mostly high quality gasoline. This kind of plant guarantees high operating flexibility to the refinery.
(3)		Capacity of conversion plant is 100%.

 

Italy

Eni’s refining system in Italy is composed of five 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 180 KBBL/d and a conversion index of 61.2%. It is one of the most efficient refineries in Europe. Located in the Po Valley, it mainly supplies markets in North-Western Italy and Switzerland. The high 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 Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulfurization 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. In 2009, the upgrading of the refinery capacity increased by a new HdCK 28 KBBL/d that came on stream in June 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 sulfur 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 late 2012.

The Taranto refinery has balanced refining capacity of 110 KBBL/d and a conversion index of 64.8%. 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 sulfur 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 2009 a total of 1.5 mmtonnes of this oil were processed). The new hydrocracking unit with a capacity of 17 KBBL/d started production in 2010. Eni’s plan to upgrade the conversion capacity of this refinery will enable to extract value from fuel oil and other semi-finished products currently exported.

Gela has a balanced refining capacity of 100 KBBL/d and a conversion index of 142.4%. This refinery is located on the Southern coast of Sicily and is highly integrated with upstream operations as it processes heavy crude produced from Eni’s nearby offshore and onshore fields in 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

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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 Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 60 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 and a new hydrocraking unit come on stream in 2009 determining an increase of middle distillate yields and a corresponding reduction of the production of gasoline giving more profitability to the activities conducted at the integrated refining pole.

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 refinery in Sines integrated with petrochemicals.

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

 

Availability of refined products		2007		2008		2009

(mmtonnes)

ITALY
Refinery throughputs
At wholly-owned refineries		27.79			25.59			24.02
Less input on account of third parties		(1.76	)		(1.37	)		(0.49	)
At affiliates refineries		6.42			6.17			5.87
Refinery throughputs on own account		32.45			30.39			29.40
Consumption and losses		(1.63	)		(1.61	)		(1.60	)
Products available for sale		30.82			28.78			27.80
Purchases of refined products and change in inventories		2.16			2.56			3.73
Products transferred to operations outside Italy		(3.80	)		(1.42	)		(3.89	)
Consumption for power generation		(1.13	)		(1.00	)		(0.96	)
Sales of products		28.05			28.92			26.68
OUTSIDE ITALY
Refinery throughputs on own account		4.70			5.45			5.15
Consumption and losses		(0.31	)		(0.25	)		(0.25	)
Products available for sale		4.39			5.20			4.90
Purchases of finished products and change in inventories		13.91			15.14			10.12
Products transferred from Italian operations		3.80			1.42			3.89
Sales of products		22.10			21.76			18.91
Refinery throughputs on own account		37.15			35.84			34.55
of which: refinery throughputs of equity crude on own account		9.29			6.98			5.11
Total sales of refined products		50.15			50.68			45.59
Crude oil sales		25.82			26.00			36.11
TOTAL SALES		75.97			76.68			81.70

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In 2009, refining throughputs on own account in Italy and outside Italy were 34.55 mmtonnes, down 1.29 mmtonnes from 2008, or 3.6%. Volumes processed in Italy decreased by approximately 990 ktonnes, or 3.3%, mainly at the Gela plant due to the extension of planned refinery downtime, and at the Livorno and Taranto plants as refinery operations were rescheduled to take account of a weak demand for products. Volumes processed outside Italy declined by approximately 330 ktonnes in particular in the Czech Republic and in Germany due to lower utilization of plant capacity in response to weak market conditions and the restructuring of the Ingolstadt facility in Germany.

Total throughputs in wholly-owned refineries (24.02 mmtonnes) decreased by 1.57 mmtonnes, or 6.1%, from 2008, due to lower refining throughputs for third parties in the Venice and Sannazzaro plants for the termination of the agreement with Tamoil at the end of 2008.

Approximately 16.3% of volumes of processed crude was supplied by Eni’s Exploration & Production segment (21.5% in 2008) representing a 5.2 percentage point decrease from 2008, corresponding to a lower volume of 1.87 mmtonnes.

 

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’s logistic model is organized on hub structure including five main areas. These hubs monitor and centralize the handling of products flows aiming to drive forward more efficiency particularly in cost control of collection and delivery of orders.

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 (of which 1,447 kilometers in operation and 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.

 

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.

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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		2007		2008		2009

(mmtonnes)

Italy
Retail		8.62		8.81		9.03
Wholesale		11.09		11.15		9.56
		19.71		19.96		18.59
Petrochemicals		1.93		1.70		1.33
Other sales		6.41		7.26		6.76
Total		28.05		28.92		26.68
Outside Italy
Retail		3.18		3.22		2.99
Wholesale		3.77		4.50		4.07
		6.95		7.72		7.06
Other sales		13.11		12.52		11.85
Total		20.06		20.24		18.91
Iberian Peninsula (a)		2.04		1.52
of which:
Retail		0.85		0.64
Wholesale		1.19		0.88
TOTAL SALES		50.15		50.68		45.59

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(a)

Downstream activities in the Iberian Peninsula were divested to Galp in October 2008.

In 2009, excluding the impact of the divestment of marketing activities in the Iberian Peninsula in 2008 (down 1.52 mmtonnes), sales volumes of refined products (45.59 mmtonnes) were down 3.57 mmtonnes from 2008, or 7.3%, mainly due to lower wholesale sales on the domestic and foreign market.

 

Retail Sales in Italy

In 2010, the re-branding to “eni” brand of all the Company’s downstream activities was launched. Following this project and the restyling of service stations the Company will market refined products in Italy through its renewed eni-branded network.

In marketing operations, Eni plans to strengthen its competitive positioning in Italy and targets to expand its share in the domestic retail market for fuels to 34% by 2013, through improving quality and range of service offer including non-oil activities, leveraging on marketing initiatives and innovative non oil formats as well as strengthening customers’ loyalty through the launch of new loyalty programs. Planned actions are also designed to attain European standards in terms of both quality of offered services and environment regulation compliance. A strong focus will be devoted to pursue high levels of operating efficiency.

By 2013, Eni expects to achieve volumes of approximately 12.2 billion liters sold (approximately 11.4 billion liters in 2009) with a retail network composed of 4,451 service stations, of which 75% is owned.

In 2009, while domestic consumption was barely unchanged, retail sales on the Italian network (9.03 mmtonnes) were up approximately 220 ktonnes from 2008, or 2.5%, mainly due to loyalty programs, marketing and pricing initiatives, in particular “Iperself” sales (for further details see below), and the opening of new services stations that sustained a 0.9 percentage point growth in market share from 30.6% in December 2008 to 31.5% in December 2009. Higher sales mainly related to gasoil and LPG sales, while gasoline sales declined slightly.

As of December 31, 2009, Eni’s retail network in Italy consisted of 4,474 service stations, an increase of 65 from December 31, 2008 (4,409 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (90 units), the opening of new service stations (7 units), which were partially offset by the closing of service stations with low throughput (24 units) and the release of 9 service stations under highway concession.

Average throughput related to gasoline and gasoil (2,482 kliters) registered an increase of 13 kliters from 2008.

In 2009, fuel sales of the Blu line (BluSuper and BluDieselTech) – high performance and low environmental impact fuel – recorded lower prices from 2008 with the stability of sales due to marketing initiatives and fidelity

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programs during the year. Sales of BluDiesel and BluDieselTech amounted to approximately 600 ktonnes (720 mmliters), and represented 10.5% of gasoil sales on Eni’s retail network. As of December 31, 2009, service stations marketing BluDiesel totaled 4,104 units (4,095 as of December 31, 2008) covering approximately 92% of Eni’s network.

Retail sales of BluSuper amounted to 82 ktonnes (110 mmliters), barely unchanged from 2008, and covered 2.6% of gasoline sales on Eni’s retail network. As of December 31, 2009, service stations marketing BluSuper totaled 2,679 units (2,631 as of December 31, 2008), covering approximately 60% of Eni’s network.

In 2009, the promotional campaign “You&Agip” was completed. The promotion was originally launched in March 2007 and lasted 3 years.

This three-year long initiative offered prizes to customers in proportion to their purchases of fuels and convenience items through the accumulation of points on a loyalty card at service stations’ stores as well as at the ones of certain partners to the program.

As of December 31, 2009, the number of customers that actively used the card in the year amounted to approximately 5.4 million. The average number of cards active each month was over 3.1 million for the year ended December 31, 2009. Volumes of fuel marketed under this initiative represented over 45% of total volumes marketed on Eni’s service stations joining the program, and 44% of overall volumes marketed on Eni’s network. In February 2010, Eni launched the new promotional campaign “you&eni” which will last for 3 years until January 31, 2013, designed to boost customer loyalty to the unique “eni” brand for all the Company’s downstream activities.

In 2009, the success of Eni’s “Iperself” promotional campaign continued. This promotion provides a discount to customers purchasing fuel in self service stations during closing hours. Jointly with other marketing activities this initiative supported market share gains in retail marketing even in an environment characterized by a steep decline in domestic demand.

 

Retail Sales in the Rest of Europe

Eni’s strategy in the rest of Europe is focused on selectively growing market share, particularly Eastern and Central Europe leveraging on synergies ensured by the proximity of these markets to Eni’s production and logistic facilities, brand awareness and economies of scale.

Excluding the impact of the divestment of marketing activities in the Iberian Peninsula to Galp (down 0.64 mmtonnes), in 2009, retail sales of refined products marketed in the rest of Europe (2.99 mmtonnes) were down approximately 230 ktonnes from 2008, or 7.1%, mainly in Germany and Eastern Europe due to a decrease in fuel demand.

As of December 31, 2009, Eni’s retail network in the rest of Europe consisted of 1,512 units, a decrease of 35 units from December 31, 2008 (1,547 service stations). The network evolution was as follows: (i) 32 low throughput service stations were closed; (ii) negative balance of acquisitions/releases of lease concessions (32 units) with negative changes in Germany and positive changes in Hungary; (iii) purchased 21 service station, in particular in Romania; and (iv) the opening of 8 new outlets. Average throughput (2,461 kliters) decreased by 116 kliters from 2008.

The key markets of Eni’s presence are: Austria with a 7.3% market share, Hungary with 11.6%, Czech Republic with 11.3%, Slovakia with 9.2%, Switzerland with 6.4% and Germany with a 3.4% on national base. These market shares were calculated by Eni based on public data on national consumption and Eni’s sales volumes.

Non oil activities in the rest of Europe are carried out under the CiaoAgip^® brand name in 1,152 service stations, of which 398 are in Germany and 159 in France with a 76% coverage of the network and a virtually complete coverage of owned stations.

 

Other businesses

Wholesale

Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.).

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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 2009, sales volumes on wholesale markets in Italy (9.56 mmtonnes) were down 1.59 mmtonnes from 2008, or 14.3%, mainly reflecting a decrease in demand for jet fuel, the bunkering market and fuel oil for power generation, as well as in gasoil sales due to lower industrial consumption reflecting the economic downturn. Sales on wholesale markets in the rest of Europe (3.66 mmtonnes) decreased by approximately 280 ktonnes, or 7.1% (excluding the impact of asset divestments in the Iberian Peninsula), mainly in Germany, in the Czech Republic and Switzerland due to declining consumption in particular of gasoil for heating.

Supplies of feedstock to the petrochemical industry (1.33 mmtonnes) declined by approximately 370 ktonnes due to declining demand. Other sales (18.61 mmtonnes) decreased by approximately 1.17 mmtonnes, or 5.9%, mainly due to lower sales volumes to trader and oil companies, as well as the reduction of volumes sold to the cargo market, also due to lower refining throughputs.

Eni also markets jet fuel directly at 46 airports, of which 27 are in Italy. In 2009, these sales amounted to 1.8 mmtonnes (of which 1.4 mmtonnes are in Italy).

Eni is also active in the international market of bunkering, marketing marine fuel mainly in 40 ports, of which 23 are in Italy. In 2009 marine fuel sales were 2.1 mmtonnes (2.0 mmtonnes in Italy). Other sales were 19.85 mmtonnes of which 18.51 mmtonnes referred to sales to oil companies and traders, and 1.33 mmtonnes of supplies to the petrochemical sector.

 

LPG

In Italy, Eni is leader in LPG production, marketing and sale with 575 ktonnes sold for heating and automotive use equal to a 18% market share. An additional 227 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.

In order to expand its presence on the marketplace, in the medium term Eni plans to increase the number of service stations providing dispensers for LPG for automotive use, targeting an increase market share to 26% by 2013.

 

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’s refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero.

In 2009, retail and wholesale sales in Italy amounted to 93 ktonnes with a 23.3% market share. Eni also sold approximately 4 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 102 ktonnes, of these about 70% 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 7% of world demand) and methanol (approximately 1.5% of world demand). About

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77% 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) and the remaining 23% is bought and resold.

Eni also distributes 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.

 

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 as a result of a challenging internal (investments on offshore fleet) and external (acquisition of Bouygues Offshore and Snamprogetti) growth process. Management expects to further strengthen Saipem’s competitive position in the medium term, leveraging on its business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. In particular Saipem plans to implement the following strategic guidelines: (i) to maximize the efficiency in all business areas with the aim in particular to maintain top execution and security standards, preserve competitive supply costs, optimize the utilization rate of the fleet, increase structure flexibility in order to mitigate the effects of negative business cycles as well as develop and promote a company culture that will permit the identification and management of risks and business opportunities; (ii) to continue to focus on the more complex and difficult projects in the strategic segments of deepwater, FPSO, heavy crude and LNG (offshore and onshore, for the gas monetization) upgrading; (iii) to promote local content in terms of employment of local contractors and assets in strategic countries where large projects are carried out supporting the development of delocalized logistic hubs and construction yards when requested by clients in order to achieve a long-term consolidation of its market position in those countries; (iv) to leverage on the capacity to execute internally more phases of large projects on an EPC and EPIC basis, pursuing better control of costs and terms of execution adapting with flexibility to clients’ needs, thus expanding the Company’s value proposition; and (v) to complete the expansion and revamping program of its construction and drilling fleet in consideration of the future needs of the Oil & Gas Industry, in order to confirm the Company’s leading position in the segment of complex projects with high profitability.

Saipem expects to invest approximately euro 3 billion over the next four years to further expand the operational features, the dimension and the geographical reach and of its fleet as well as to support the activities related to the execution of projects in portfolio and the acquisition of new orders.

 

 

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Orders acquired in 2009 amounted to euro 9,917 million, of these projects 79% are to be carried out outside Italy, while orders from Eni companies represented 32% of the total. Order backlog was euro 18,730 million as of December 31, 2009 (euro 19,105 million as of December 31, 2008). Projects to be carried out outside Italy represented 93% of the total order backlog, while orders from Eni companies amounted to 22% of the total.

		2007		2008		2009

Orders acquired		(euro million)		11,845		13,860		9,917
Offshore construction				3,496		4,381		5,089
Onshore construction				6,070		7,522		3,665
Offshore drilling				1,644		760		585
Onshore drilling				635		1,197		578
Originated by Eni companies		(%)		16		4		32
To be carried out outside Italy		(%)		95		94		79
Order backlog and breakdown by business		(euro million)		15,390		19,105		18,730
Offshore construction				4,215		4,682		5,430
Onshore construction				7,003		9,201		8,035
Offshore drilling				3,471		3,759		3,778
Onshore drilling				701		1,463		1,487
Originated by Eni companies		(%)		22		13		22
To be carried out outside Italy		(%)		95		98		93

 

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 business model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies ("NOCs"). Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage, integrating in its own business model the direct management of construction process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, by building a pipelayer, a field development ship for deepwater, an FPSO and other supporting assets for offshore activity.

Saipem’s offshore construction fleet is made up of 33 vessels and a large number of robotized vehicles able to perform advanced sub-sea operations. Its major vessels are: (i) the Saipem 7000 semi-submersible dynamic positioned vessel, with 14 ktonnes of lift capacity, capable to lay pipelines using the J-lay technique to the maximum depth of 3,000 meters; (ii) the Field Development Ship for the development of underwater fields in dynamic positioning, provided with cranes lifting up to 600 tonnes and a system for J-lay pipe laying to a depth of 2,000 meters; (iii) the Castoro 6 semi-submersible vessel, capable of laying pipes in waters up to 1,000 meters deep; (iv) the Saipem 3000 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 2009 in Offshore construction were: (i) an EPC contract on behalf of Agip KCO as part of the development program of the Kashagan field related to the hook-up and commissioning of offshore facilities, as well as activities to be executed in the Kuryk construction yard in Kazakhstan; (ii) a contract on behalf of Eni for the conversion of a tanker into an FPSO (Floating Production Storage and Offloading) vessel that will have a storage and production capacity of 700 KBBL/d and 12 KBBL/d, respectively; and (iii) an EPC contract on behalf of Esso Exploration Angola for the development of Kizomba Satellites Project offshore Angola. The project is related to the connection of the Mavacola and Clochas fields to the existing FPSO units.

 

Onshore construction

In the onshore construction business, Saipem is one of the largest Engineering & Construction operators on turnkey contract base at a worldwide level in the Oil & Gas segment, especially through the acquisition of Snamprogetti. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation,

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stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulfur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness through its technology excellence granted by its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the medium term, underpinning upward trends in the oil service market, Saipem will be focused on taking advantage of the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of Middle-East, Caspian Sea, Northern and Western Africa and Russia.

The most significant orders awarded in 2009 in Onshore construction were: (i) an EPC contract on behalf of the joint venture between Eni and Sonatrach for the construction of facilities for the treatment of natural gas extracted from the Menzel Ledjmet East field and from the future developments of the CAFC (Central Area Field Complex) in Algeria; (ii) an EPC contract on behalf of Sonatrach for the construction of the GK3-lot 3 gas pipeline that will connect various cities situated in the north-eastern region of Algeria for a total length of approximately 350 kilometers; and (iii) an EPC contract on behalf of Qafco for the construction of a new urea plant in the city of Mesaieed, in Qatar.

 

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, in the next years Saipem intends to complete the building of: (i) the Scarabeo 8 and 9, new generation semi-submersible platforms, that have been already rented to Eni through multi-year contracts; and (ii) the new S12000 drilling ship to perform operations in West Africa on behalf of Total. In parallel, investments are ongoing to renew and to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients needs and purchase of support equipment).

Saipem’s offshore drilling fleet consists of 13 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 1,500 meters of water, respectively. Average utilization of drilling vessels in 2009 stood at 90.0% (100% in 2008).

The most significant contracts awarded in Offshore drilling in 2009 included: (i) a 3-year extension of the contract for the use of the Scarabeo 5 semi-submersible platform in Norway on behalf of Statoil; (ii) an extension of the contract for the use of semi-submersible platform Scarabeo 6 in Egypt on behalf of Burullus Gas Co; and (iii) a 12-month contract (plus an additional 12 months option) for the use of the Perro Negro 6 newly built jack up in Angola on behalf of Sonangol.

 

Onshore drilling

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

Average utilization of rigs in 2009 stood at 91% (99% in 2008). The 83 rigs owned by Saipem at year end were located as follows: 30 in Venezuela, 19 in Peru, 8 in Saudi Arabia, 7 in Algeria, 3 in Kazakhstan, 3 in Brazil, 3 in Italy, 3 in Colombia, 2 in Ukraine, 2 in Congo, 1 in Ecuador, 1 Bolivia and 1 in Egypt.

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The most significant orders awarded in 2009 in Onshore drilling were: (i) a contract on behalf of Agip KCO for the lease of 2 rigs in Kazakhstan with a contract duration of five and half years; (ii) a contract on behalf of the joint venture between First Calgary Petroleum and Sonatrach in Algeria for the lease of 2 rigs with a contract duration of three years; and (iii) a contract on behalf of Eni in Congo for the lease of two rigs with a contract duration of two years.

 

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, a weak demand outlook, intense competitive pressures taking into account the commoditized nature of many of Eni’s products. In fact, Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices, also considering the cyclical nature of demand. See “Item 3 – Risk Factors”. The outlook for 2010 is challenging as management does not expect any significant improvement in industry fundamentals. As a result, weak demand growth, competition and high costs for oil feedstock are forecast to drive down operating results and liquidity in this business. However, management believes there are signs that demand has bottomed-up. Also, the Company will improve results by implementing cost efficiencies. The Company does not expect to incur significant amount of expenditures to develop this business. In the next four years, management forecasts a level of expenditures of approximately euro 220 million per annum mainly targeted to upgrading plant efficiency, selectively expanding capacity in order to improve the product-mix, as well as complying with all applicable regulations on environment, health and safety issues.

In 2009, sales of petrochemical products (4,265 ktonnes) decreased by 419 ktonnes from 2008, or 8.9% due to the economic downturn, especially in the automotive sector, that negatively influenced demand for petrochemical products.

Petrochemical production (6,521 ktonnes) decreased by 851 ktonnes from 2008, or 11.5% due to a steep decline in demand for petrochemical products in all business. The general demand decrease in the chemical industry, in particular for commodities, required unexpected outages in a number of plants in order to avoid excess stocks. Relevant production decreases were registered at the Porto Torres plant (down 51%), as result of the shutdown of the phenol plant at the beginning of the year and of reduced production for commercial reasons.

In the 2009, the nominal production capacity decreased by 3.3% from 2008 due to the shutdown of the Gela cracker and the Porto Torres phenol plant. The average plant utilization rate, calculated on nominal capacity decreased from 68.6% to 65.4% due to reduced production.

The average unit sale prices in 2009 decreased by 26% from 2008. The steeper decreases affected the prices of the main petrochemical products (olefins were down 35%) due to the negative impact of the oil price scenario (virgin naphtha was down 32.3% from 2008). Average unit prices of polymers, in particular elastomers (down 17%) decreased less, due to a slower adjustment to the oil scenario and to expected price increases in 2010.

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

	Year ended December 31,

		2007		2008		2009

(ktonnes)

Basic petrochemicals		6,274			5,110			4,350
Polymers		2,521			2,262			2,171
Total production		8,795			7,372			6,521
Consumption of monomers		(4,099	)		(3,539	)		(2,701	)
Purchases and change in inventories		816			851			445
		5,513			4,684			4,265

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

	Year ended December 31,

		2007		2008		2009

(euro million)

Basic petrochemicals		3,582		3,060		1,832
Polymers		3,109		2,961		2,185
Other revenues		243		282		186
Total revenues		6,934		6,303		4,203

Basic petrochemicals

Basic petrochemical revenues (euro 1,832 million) decreased by euro 1,228 million from 2008 (or 40.1%) in all the main business segments due to the steep reduction in average unit prices (ranging from 25% to 35%) related to the prices of main petrochemical products, and to a lower extent to the decrease in sales volumes.

In particular olefins and aromatics sales volumes decreased by 8% and 10.5%, respectively, with a slight increase in the last quarter of 2009. Intermediates sales volumes continued to report a negative performance (down 34%) as a result of lower product availability because of the shutdown of the Porto Torres plant as a result of the unfavorable scenario.

Basic petrochemicals production (4,350 ktonnes) decreased by 760 ktonnes from 2008 (or 14,9%), in line with lower demand of monomers.

 

Polymers

Polymer revenues (euro 2,185 million) decreased by euro 776 million, or 26.2%, from 2008, mainly due to price reduction.

Sales volumes of polyethylene decreased by 1.3% in spite of a slight demand increase registered in the last months of the year. Styrene sales achieved a stable performance and compact polystyrene sales increased by 2.5% from 2008. Sales decreases mainly in elastomers (down 7%) due to a greater impact of industrial sectors affected by the economic downturn (mainly automotive).

Polymers production (2,171 ktonnes) decreased by 91 ktonnes from 2008 (or 4%), which is consistent with sales trends.

In 2009, the production volumes of styrene and polyethylene decreased by 3% compared to 2008 mainly due to the shutdown of the Porto Torres plant. Elastomers production decreased by 8.8% as a result of plants outages, mainly in the first months of 2009 due to lower demand from industries, in particular the automotive sector.

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Capital Expenditures

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

 

 

Corporate and Other activities

These activities include the following businesses:

•		the "Other activities" segment comprises results of operations of Eni’s subsidiary Syndial which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and
•		the "Corporate and financial companies" segment comprises results of operations of Eni’s headquarter and certain Eni’s subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarter is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. Through Eni’s subsidiaries Eni Adfin SpA, Eni 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 inter-company basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group’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 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 issues, 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 1.4 billion to fund ongoing projects in Eni’s businesses as well as research in the field of renewable and alternatives sources of energy.

In 2009, Eni’s expenditures on R&D amounted to euro 207 million which were almost entirely expensed as incurred (euro 217 million and euro 208 million in 2008 and 2007, respectively).

As of December 31, 2009, a total of 1,019 people were employed in research and development activities.

In 2009, a total of 106 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

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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.

 

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:

•		procedures for Strategic Environment Assessment (SEA), Environmental Impact Assessment (EIA) and Integrated Pollution Prevention and Pollution Control (IPPC);
•		procedures to preserve soil, prevent desertification, effectively manage water resources and protect water from pollution;
•		procedures to effectively manage waste and remediate contaminated sites;
•		air protection and reduction of atmospheric pollution; and
•		environmental liability.

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 June 19, 2009, the Law 69/2009 starts to a consultation process of the association’s parties in order to simplify and amend the Legislative Decree No. 152/2006. The process should be completed by June 2010.

A new regulation is expected in the waste sector by 2010, when the competent authority will adopt an innovative informatics system, named SISTRI, which will be able to control and track waste transfer at the national level.

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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 August 2009 the Legislative Decree No. 81/2008 was amended and corrected with the Legislative Decree No. 106/2009. By 2008 Eni worked on the implementation of the general framework regulations on health and safety contained in this Legislative Decree No. 81/2008 and No. 106/2009, 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 the 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:

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

 

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. On June 5, 2009, the following regulations were published in order to define the criteria for cutting emissions cost-effectively by 2020 compared with levels in 2005:

•		Directive 2009/28/CE: fix target of 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 should meet to ensure they deliver real environmental benefits.
•		Directive 2009/29/CE: defines criteria and targets for cutting GHG emissions from the sectors covered by the system (energy and manufacturing industries) by 21% by 2020 compared with levels in 2005.
•		Directive 2009/30/CE: defines the fuel quality and places an obligation on suppliers to reduce greenhouse gases from the entire fuel life cycle of 6% by 2020, mostly by an increased use of biofuels.
•		Directive 2009/31/CE: defines a scenario in order to promote the development and safe use of Carbon Capture & Storage (CCS), a suite of technologies that allows the carbon dioxide emitted by industrial processes to be captured and stored underground.
•		Regulation 443/2009/CE: sets emissions standards for new passenger cars, which is an important tool to support Member States in meeting their emissions targets in the non-ETS sectors. The regulation defines binding emissions targets to ensure that emissions from the new car fleet will be reduced to an average of 120 g CO2/km by 2015, including the effect of the Fuel Quality Directive, then decreasing to a stringent long-term target of 95 g CO2/km by 2020.
•		Decision 406/2009/CE: defines, for sectors not included in the EU ETS, such as transport, housing, agriculture and waste, emissions reduction target of 10% from 2005 levels by 2020 (the Italian reduction target is fixed at 13%).

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.

Sites specific Environment Integrated Authorizations are released by the Competent Authority to the single operator. The IPPC installations of Eni have obtained most of their authorizations during 2009 and the release process it’s expected to be completed by 2010.

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

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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.

By March 2010, Eni will complete the implementation of 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. The proposal reaches the 1° reading phase on December 2009 and the consultation process is planning to end by June 2010.

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.

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 2009

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

In 2009, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 345 (330 in 2008), of which 125 certifications according to the ISO 14001 standard, 10 certifications according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union) and 61 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

Environment. In 2009, Eni incurred total expenditures amounting to euro 1,324 million for the protection of environment, up 23% from 2008. Current environmental expenses increased by approximately 1.4% from 2008, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure increased by 51% and mainly related to soil and subsoil protection and air emissions. Eni expects to continue incurring amount of environmental expenditures and expenses in line with or above 2009 levels in future years.

Safety. Safety of our employees and contractors as well of all people living in the area where activities and assets are located is important to our company. In year 2009, the Legislative Decree No. 106/2009 amended and updated Legislative Decree No. 81/2008 regarding health and safety in workplaces and substantially better clarified

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the responsibilities of companies who violate said applicable laws and terms of monitoring by managers and supervisors.

During 2009, the improvement and dissemination of safety awareness through all levels of its organization, which is one of the foundations of Eni’s safety strategy, has been greatly boosted by a large communication campaign with the target of improving the conduct of workers in the specific field of safety at work. The campaign will last two years and will involve 35,000 workers and 25,000 contractors.

Results of efforts to achieve a better safety in all activities has brought an improvement of Eni injury frequency rate to 0.99 and of the injury severity rate to 0.041, both decreasing from 2008 and representing the best results ever.

Costs incurred in 2009 to support the safety levels of operations and to comply with applicable rules and regulations were euro 538 million, up 22% from 2008. Eni expects to continue incurring amounts of expenses for safety which will be in line with or above 2009 levels in future years.

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

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

To protect the health and safety of its employees, Eni relies on a network of 334 health care centers located in its main operating areas. A set of international agreements with the best local and international health centers ensures efficient services and timely responses to emergencies.

In 2009 Eni incurred a total expense of euro 80.7 million, up 17.7% from 2008 to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health which will be in line with or above 2009 levels in future years.

 

Managing GHG emissions and 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 is a party to 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 makes use 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 operators who produce GHG emissions in excess of the amounts entitled on the base of national allocation plan, will provide allowances to cover excess emissions and also to pay a penalty. The excess emissions penalty amounts to euro 100 (euro 40 for the first period 2005-2007) for each tonne of carbon dioxide equivalent emitted in excess of entitled amounts. All companies are expected to identify and carry out projects for emission reductions.

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Management believes that the best solutions for complying with the Kyoto Protocol are use of low emission energy sources and 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. Eni participates in the ETS scheme with 55 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 period 2005- 2007 Eni was entitled to allowances equal to 77.2 mmtonnes of carbon dioxide for existing and new installations. In the period 2008-2012 Eni was entitled to allowances equal to 126.4 mmtonnes of carbon dioxide for existing installations and to further 8.6 mmtonnes in relation to new installations for the 2008-2012 period. Based on the implementation of projects designed to reduce emissions, particularly the start-up of high efficiency combined cycles for the cogeneration of electricity and steam, the amount of carbon dioxide emitted by Eni’s plants has complied with mandatory limits in each of the reported periods up to 2009.

Management plans to target reduction of GHG emissions by implementing certain gas projects designed to exploit associated gas in foreign countries where such gas is flared or released in the atmosphere absent local market outlets for that gas. 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 Italian reduction targets, as set by the Kyoto Protocol. Eni has already carried out Zero Gas Flaring projects in Nigeria and Congo.

More projects are being assessed or implemented in Libya, Congo, Nigeria, Angola and Algeria. Management plans to invest approximately euro 1.1 billion in those projects over the next four years. 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. In the period from 2010-2013, a reduction in the trend of Eni total GHG emissions is foreseen due to the planned implementation of the above mentioned projects designed to reduce gas flaring or venting, measures targeting energy efficiency at various Eni’s installations and facilities including refineries, petrochemicals plants and electricity plants, and actions to better manage gas emissions in transport and distribution activities. However, due to new facilities and installations, management believes that Eni’s GHG emissions under the ETs scheme will exceed the entitled allowances in the next four-year period resulting in the incurrence of higher operating expenses in the range of euro 250-320 million.

To ensure comprehensive, transparent and accurate reporting for GHG emissions, Eni introduced in 2005 its own Protocol for accounting and reporting of greenhouse gas emissions (GHG Accounting and Reporting Protocol), which is an essential requirement for emission certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the assessment of progress. The Eni GHG Protocol has been updated during 2009 to be in compliance with the European and Italian regulation (as the new Monitoring and Reporting Guide Line) and with the best practices reference document (American Petroleum Industry Compendium - August 2009). For safer and more accurate management of GHG emissions and with a view to supporting effective reporting, Eni provided all its business units with a dedicated database, in order to gather and report GHG emissions according to the Protocol and to ensure completeness, accuracy, transparency and consistency of GHG accounting as required by certification needs.

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. Between 2008 and 2009 the feasibility and environmental impact evaluation studies were carried out and completed. Now the project will go under authorization process (VIA). In particular Eni is involved in bio-energy and bio-fuels.

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

 

Regulation of Eni’s Businesses

Overview

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

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Regulation of Exploration and Production Activities

Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil and gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See "Regulation of the Italian Hydrocarbons Industry" and "Environmental Matters" for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities.

Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations.

In principle, the license holder is entitled to all production minus any royalties that are payable in kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area.

In 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 recovery of costs incurred for the exploration, development and operating activities (cost oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (profit oil).

A similar scheme to 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.

 

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.

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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 has been reviewed by the Italian Parliament which provides for an increase of royalties on hydrocarbon production from the current rate of 7 to 10%.

 

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:

(i)		from January 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 put into the national transmission network imported or domestically produced gas volumes to be sold in Italy higher than a preset share of Italian final consumption. This share was 75% of total final consumption in 2002 and has decreased by 2 percentage points per year to reach 61% 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;
(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 unbundling is envisaged. Also distribution, i.e. the transmission of natural gas by means of local gas pipeline networks, has to be carried out by a separate company which cannot perform other gas related activities. Sale activity is compatible only with import, export and production activities; sale activity to final customers is subject to authorization from the Ministry of Economic Development. 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 code containing rules and regulations for the operation of and access to infrastructures was prepared by operators on the basis of criteria set by the Authority for Electricity and Gas.

2009 ended the sixth three-year regulated period for natural gas volumes input in the domestic transmission network, for which the allowed average percentage was 61% of domestic consumption of natural gas, and the fifth three-year regulated period for sales volumes to final customers. Eni’s presence on the Italian market complied with said limits. Those antitrust thresholds are due to expire in 2010. Management expects that they will be revised and terms will be extended.

 

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

This law provides for:

•		a derogation to third party access granted to companies that make direct or indirect investments for the construction of new infrastructure or the upgrading of existing ones such as: (i) interconnections between EU Member States and national networks; (ii) interconnections between non-EU States and national networks for importing natural gas to Italy; (iii) LNG terminals in Italy; and (iv) underground storage facilities in Italy. Investing companies can obtain priority on the assignment of new capacity for a portion of not less than 80% of the new capacity installed and for a period of at least 20 years; and
•		paragraph 69 provides the authentic interpretation of the rule introduced by Legislative Decree No. 164/2000 concerning the transitional regime of concessions for natural gas distribution activities in urban centers existing at June 21, 2000, which allows for an anticipated repayment of the distribution service, despite being provided through a bid procedure rather than direct entitlements. This law changes the provisions defined by Legislative Decree No. 164/2000 by: (i) extending to December 31, 2007, the transitional period for the continuation of existing concessions, with a possible extension of one further year when public interest is considered important by local authorities; and (ii) canceling the adding up of possible extensions, as provided for by Legislative Decree No. 164/2000, in case of certain conditions

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(business restructuring, size parameters, shareholding composition). The end of concessions awarded on the basis of a bid procedure remains set as of December 31, 2012. Currently, the Ministry for Economic Development is drafting a revision of the distribution gas market with the aim of reducing the number of distribution companies by providing for an extension of the territory reach of each concession.

 

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 as of December 31, 2008, has been re-scheduled in a 24-month period deadline following enactment of a specific decree from the Italian Prime Minister which is to establish terms and conditions of the divestments. 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 provided for by the regulations on the divestment of interests held by the Italian Government (“golden share”) in the By-laws of this company. Eni’s interest in Snam Rete Gas will also be affected by European Directive No. 73/2009 and how the directive’s guidelines will be implemented in Italian gas regulation.

 

Regulations aimed at increasing competition in the Italian wholesale segment of natural gas and Law No. 99 of July 23, 2009

In order to implement a 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 market. The Authority for Electricity and Gas will define a certain amount of quantities of gas to be sold at a fixed price. The largest 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 largest operator is obliged to offer about 100 mmCM/d and 20 mmCM/d from April 1 to September 30. This rule should limit the discretionarily of the largest operator in defining higher prices of natural gas and on the other side to increase liquidity of the natural gas market in Italy.

On June 26, 2009, the Italian Council of Ministers approved the so called “Anti-crisis Decree” whose Article 3 concerns measures for reducing the cost of energy for industries and households and introduces an obligation for Eni to sale 5 BCM of gas to be delivered in the period October 2009-September 2010 (so called gas release). In particular the decree provides for this offer to be made under non discriminatory competitive procedures (bids) at terms and conditions fixed by the Ministry of Economic Development, taking into account a proposal of the Authority for Electricity and Gas. The compensation due to Eni has been determined by the Ministry for Economic Development, as recommended by the Authority with reference to the average prices of the relevant European markets and coherently with Eni supply costs. This mandatory compensation is lower than Eni’s average supply prices. The difference between the sale price resulting from the bid and the compensation due to Eni is awarded to industrial customers with flat gas withdrawals in the past three years according to criteria determined by the Ministry. The decree provides also that the Authority: (i) introduces digressive elements in transport tariffs for the 2010-2013 regulatory period; (ii) reforms the balancing system by adopting flexibility mechanisms providing advantages to all final customers, including industrial customers; and (iii) promotes the supply of peak services and storage for industrial and power generation customers.

In compliance with the provisions of Law No. 99 of July 23, 2009, entrusting GME (the company managing the Italian electricity market) with the managing and organization of an internal liquid market for natural gas, on March 18, 2010 the Ministry for Economic Development required GME to implement a trading platform (so called “gas exchange”) by May 10, 2010. On that platform, certain volumes of gas are expected to be traded corresponding to legal obligations on part of Italian importers and producers as per Law Decree No. 7/2007. According to such decree: (i) since January 2007 Italian importers are granted authorization to import gas from extra-EU countries upon condition that they offer preset quantities of imported natural gas at the PSV (the Italian virtual trading point); and (ii) Italian producers shall dispose of annual royalties on production due to the Italian State at the same PSV. In May 2010, Eni is required to offer at that new exchange about 40 mmCM, completing the offer obligation related to the volumes imported in thermal year October 1, 2008-September 30, 2009.

Management believes that measures as those described may increase competition on the Italian market resulting in further margin pressures. See also the next paragraph for a description of measures that the Italian

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Authority for Electricity and Gas is planning to implement about natural gas pricing or suggest at the appropriate governmental level.

 

Natural gas prices

Following the liberalization of the natural gas sector introduced by Decree No. 164, prices of natural gas sold to industrial and thermoelectric customers as well as to wholesalers are freely negotiated. However 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 by the Presidential Decree dated October 31, 2002 with the power of regulating natural gas prices to residential and commercial customers which were not eligible until December 31, 2002, also after the full opening up of the gas market from January 1, 2003, additionally targeting the public goal of containing inflationary pressure deriving from increasing energy costs. Consistently with this decree, at present on the basis of different Resolutions of the Authority for Electricity and Gas companies selling natural gas through local networks have to offer to residential customers and customers who live in buildings consuming on the whole less than 200,000 CM/y the regulated tariffs beside their own price proposals.

 

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; 79/2007 and 64/2009

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 $/BBL or a rise within the 35-60 $/BBL range, raising the cap at 95% if Brent crude prices are higher than 60 $/BBL; (ii) it has changed the relative weight of the three products making up the reference index of energy prices whose variations 2.5% as compared to the same index in the preceding period – determine the adjustment of raw – when higher or lower than 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.

The indexation mechanism for the raw material cost component in natural gas supplies to residential customers consuming less than 200,000 CM/y has been recently updated with Resolution No. 64/2009 of the Authority. This Resolution provides that updatings of said raw material component take place every three months on the basis of changes in a preset basket of hydrocarbons (including Brent crude, gasoil and light fuel oil). Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. The Company does not expect any material impact following enactment of Resolution No. 64/2009.

However, management cannot exclude the possibility that in the future the Authority could implement measures in this matter which may negatively affect Eni results of operations and liquidity. On March 26, 2010 the Authority for Electricity and Gas published a consultation document regarding certain proposed amendments to the current mechanism that is used to update the raw material cost component in supplies to residential users. The document addresses Italian gas importers, including Eni. The Authority reaffirmed its belief that such cost component should continue being linked to supply prices as provided by the long-term contracts held by Eni as the incumbent operator in the Italian gas market, as evidence suggests that there have not been sufficiently liquid spot markets in Italy. However, the Authority considers that Eni still holds as large market power as to influence wholesale gas prices. Based on that belief, the Authority suggests that the incumbent operator disposes of predetermined amounts of gas at preset economic conditions that take into account the supply costs of an efficient portfolio of long-term supply contracts which could be lower than current wholesale prices realized by Eni. Alternatively, those gas disposals might be in favor of an independent buyer for amounts that might possibly cover the entire capacity of the wholesale market in Italy. Those proposals require establishment of adequate rules by relevant administrative authorities. In case such rules are not implemented, the Authority plans to continue updating the raw material component in supplies to residential customers on the base of the current updating mechanism as it schedules to do in the fourth quarter of 2010. The eventual update will take into account of any effects associated with ongoing renegotiations of long-term supply contracts and may lead to lower wholesale gas prices.

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Third Energy Package: European Directive No. 73/2009

As a part of the so-called "Third Energy Package" sanctioned in 2009, European Directive No. 73 regulates the internal market for natural gas. Essentially, the directive requires member states to choose between two options for ensuring carriers’ independence in case transport systems belong to vertically-integrated companies.

The two options provided are:

(i)		Separation of ownership under two alternative modes:
		-		Ownership Unbundling (OU): the company that owns the networks and manages transport activities is unbundled from its integrated parent company that will retain supply/production and sale activities;
		-		Independent System Operator (ISO): the vertically integrated company retains ownership of the networks but confers their management to an independent party.
(ii)		Strengthened functional separation:
		-		Independent Transmission Operator (ITO): the vertically integrated company can retain control of the company that manages transport activities and owns transport networks, provided the vertically integrated company refrains from interfering in the decision-making process of the controlled carrier company.

Italian Parliament is scheduled to implement European Directive No. 73/2009 in Italian gas regulation by March 2011. Management cannot predict any possible outcome of that matter.

 

Fully-Regulated Businesses in the Italian Gas Market Transport

Transport

Transport tariffs. The Regulatory Authority for Electricity and Gas set transport criteria companies have to apply in determining natural gas transport and dispatching tariffs on national and regional transportation networks, for each regulatory period made up of four years, as provided for by Decree No. 164/2000. Tariffs are subject to approval by the Authority, which ensures their compliance with preset criteria.

Criteria established by the Authority for Electricity and Gas set allowed revenues that 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.

With Resolution ARG/gas 184/2009, published on December 2, 2009, the Authority set the criteria regulating the tariffs for natural gas transportation on the national and regional gas pipeline network for the third regulatory period (January 1, 2010-December 31, 2013).

The Regulated Asset Base (RAB) is calculated with the re-valuated historical cost methodology.

The allowed rate of return (WACC) on Regulatory Asset Base (RAB) has been set equal to 6.4% in real terms pre tax.

The new tariff structure confirms the recognition in tariff of expenditures incurred for network upgrading, providing for a higher remuneration than WACC, changing in a 1-3% range in relation to the nature of expenditures and for a period of 5 to 15 years.

Depreciation costs of gas transport infrastructures (gas pipelines) are determined on a 50-years useful technical life and are excluded from the price cap mechanism. Operating costs are defined with reference to operating costs incurred during 2008 and increased by a 50% rate to recognize productivity gains achieved in the second regulatory period. Fuel gas is excluded from the price cap mechanism.

The revenue component related to volumes transported is determined referring to operating costs recognized in tariff and amounts to a 15% of revenue cap.

The Authority also recognized Snam Rete Gas a total amount of euro 33.6 million as settlement of additional costs incurred during the 2007-2008 thermal year and referring to the purchase of fuel gas for compression stations.

Gas not recorded in accounts on the natural gas transport networks in the 2004-2006 period. With Resolution VIS 8/2009, the Regulatory Authority for Electricity and Gas has completed the preliminary investigation on the gas not recorded in accounts started with Resolution VIS 41/2008 “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

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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.

Network Code. From 2003 Snam Rete Gas Network Code is in force, defining rules and regulations for the operation and management of the transmission network. The Network Code, approved by the Regulatory Authority for Electricity and Gas with Resolution No. 75 of July 1, 2003, is based on the criteria set by the same Regulator with Resolution No. 137/2002, aimed at guaranteeing equal access to all customers, maximum impartiality and neutrality in transport and dispatching activities, in accordance with Legislative Decree No. 164/2000.

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. Capacity products with duration shorter than one year are also available.

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 year are higher than available capacity, a pro-rata mechanism is applied in compliance with the aforementioned priority.

Parties can also apply for shorter than one year capacity products (monthly basis at least).

Eni filed a claim against this decision with the Regional Administrative Court of Lombardy, which was partially accepted with a decision of December 2004. An administrative appeals court also confirmed the Company’s position. Specifically, the Court stated that the purchase of the contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in the access to the network, also in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure such to impairing Eni’s marketing plans. Management cannot predict a final outcome of this proceeding.

 

Regasification

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

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 Resolution ARG/gas 92/2008 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).

Regasification Code. From 2007 GNL Italia Regasification Code is in force, defining rules and regulations for the operation and management of the regasification plant of Panigaglia, north-west Italy. The Code, approved by the Regulatory Authority for Electricity and Gas with the Resolution VIS 8/2009, has completed the preliminary investigation on No. 115/07 (published May 22, 2007), is based on the criteria for access to LNG regasification services set by the same Regulator with Resolution No. 167/05 (August 1, 2005) in accordance with Legislative

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Decree No. 164/2000. 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.

 

Distribution

Distribution is the activity of delivering natural gas to residential and commercial customers in 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 Regulatory 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 a 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.

 

Storage of natural gas

Storage activities in Italy are regulated by Decree No. 164. 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 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 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.

Storage tariffs. On March 3, 2006, the Regulatory Authority for Electricity and Gas with Resolution No. 50/2006 published the criteria for determining storage tariffs for the second regulated period (from April 1, 2006 to 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)		According to this resolution, the storage company calculates revenues for the determination of unit tariffs for storage services by adding the following cost elements:a
(ii)		depreciation and amortization charges; and

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(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 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 Regulatory 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 (see Resolution VIS 51/2009 below).

Storage Code. From November 1, 2006 Stoccaggi Gas Italia (Stogit) Storage Code is in force. The Storage Code approved by the Regulatory Authority for Electricity and Gas with Resolution No. 220/2006, is based on the framework and criteria established by the Regulator with Resolution No. 119/2005 concerning guarantees for access to natural gas storage services, duties of subjects operating storage activities.

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 storage company offers services according to the access priority established by the Regulatory 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 Regulatory 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.

From November 2009, according to the Resolution No. 165/2009 set by the Regulator, monthly based storage services are available for gas-network users (Shippers). Storage capacities are sold on auction basis.

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

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such reserves. As of December 31, 2008 Eni held approximately 179 BCF of strategic reserves of natural gas (179 BCF at year end 2007).

 

Joint investigation by the Regulatory Authority for Electricity and Gas and the Antitrust Authority on storage activity in the natural gas sector - Resolution VIS 51/2009

By June 2009, the Regulatory Authority for Electricity and Gas concluded the investigation into storage activity in the natural gas sector commenced with Resolution No. 287/2007 (November 22, 2007) and performed jointly with the Antitrust Authority. The Authorities stated in their conclusions that capital expenditure plans implemented by Eni through Stogit (now controlled by Snam Rete Gas) in the storage activity were inconsistent with plans to upgrade storage capacity, as proposed by Stogit and approved by the Authority for Electricity and Gas.

The outcome of the investigation underscored that the national gas system lacks sufficient degrees of security and flexibility so as to enable third operators to compete effectively in a liberalized market. Both authorities suggested certain potential regulatory measures: the divestiture by Eni of some storage assets in order to both promote competition in the sector through the entry of new independent operators, and create premises to develop new storage capacity; and the modification of the sector-specific regulation through the introduction of new criteria for allocating modulation storage capacity through public bids and mineral storage capacity by, among others, providing incentives for the development of marginal fields.

 

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. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also requires that contracts between license holders and service station operators have a duration of not less than six years and are 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 same goal of renewing the Italian distribution network, Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non oil activities.

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

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

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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 Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis.

As of December 31, 2009 Eni owned 6.3 mmtonnes of oil products inventories, of which 4.5 mmtonnes as "compulsory stocks", 1.4 mmtonnes related to operating inventories in refineries and depots (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.4 mmtonnes related to specialty products.

Eni’s compulsory stocks (as of December 31, 2009) were held in term of crude oil (34%), light and medium distillates (46%), fuel oil (16%) and other products (4%) and they were located throughout the Italian territory both in refineries (70%) and in storage sites (30%).

 

Italian tax developments

The "Treaty of Friendship" between the Republic of Italy and Libya was enacted on February 3, 2009. The law 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. Eni fell within the scope of this supplemental tax. This supplemental tax rate is due for 2009 and following years up to 2028. In 2009, Eni incurred taxes current payable amounting to euro 239 million. According to management’s estimates the new supplemental tax rate will cause the Company to incur additional tax payable for amounts roughly in line with 2009 in future years. 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 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:

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

National courts shall have the power to apply Articles 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,

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

 

Organizational Structure

Eni SpA is the parent company of the Eni Group. As of December 31, 2009, there were 276 fully consolidated subsidiaries and 83 associates that were accounted for under the equity or cost method. For a list of subsidiaries of the Company, see "Exhibit 8. List of Eni’s fully consolidated subsidiaries for year 2009".

 

 

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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.

 

Executive Summary

Eni reported net profit of euro 4,367 million for the year ended December 31, 2009, representing a decrease of 50.5% from 2008.

The Group operating profit for the year ended December 31, 2009 amounted to euro 12,055 million, down 34.9% from 2008 mainly reflecting a down operating profit reported by the Exploration & Production and Gas & Power segments due to lower oil and gas prices and a weaker gas demand. In the Gas & Power segment, the impact of lower gas prices was mitigated by a time-lag in the indexation mechanism on residential sales. Management believes that this mechanism will have an opposite effect on the Group’s results in coming quarters. The Group results were also affected by higher amortization charges taken in connection with new investments. These negatives were partly offset by recognition of lower inventory write-downs and lower impairments of property, plant and equipment particularly in the Refining & Marketing and Petrochemical segments. Operating profit also benefited from a strengthening of the dollar against the euro.

Group results for the year were also reduced by lower profits reported by non consolidated entities that are accounted for under the equity or the cost method (down euro 804 million) and a higher consolidated tax-rate, increasing from 50.3% to 56% (up 5.7 percentage points).

Net cash provided by operating activities amounted to euro 11,136 million for the year ended December 31, 2009. Other sources of cash were the divestment of a 20% interest in OAO Gazprom Neft for euro 3,070 million, plus proceeds from the sale of a 51% interest in OOO SeverEnergia (Eni’s share 60%) for euro 155 million or $230 million, where the value of the transaction amounted to $940 million. Both transactions were carried out under call option agreements signed with Gazprom in 2007. Subscription by Snam Rete Gas minorities of a share capital increase amounted to euro 1,542 million and further cash proceeds of euro 370 million were mainly associated with the divestment of certain non strategic assets in the Exploration & Production division, following agreements signed with Suez in 2008. Those cash inflows were used to partially fund capital expenditures of euro 13,695 million, completion of the Distrigas acquisition through a buy-out of minorities for cash consideration of euro 2,045 million, payment of dividends to Eni shareholders (euro 4,166 million of which euro 1,811 million related to the interim dividend during 2009) as well as dividend payments to minorities (euro 350 million) in particular relating to Snam Rete Gas and Saipem (euro 335 million).

As of December 31, 2009 net borrowings amounted to euro 23,055 million, an increase of euro 4,679 million from December 31, 2008.

Eni’s oil and gas production for the year (on an available for sale basis) decreased by 1.8% to 1.72 mmBOE/d. This performance was mainly due to:

(i)		OPEC cuts;
(ii)		weak European gas demand;
(iii)		mature field declines;
(iv)		unplanned facility downtime; and
(v)		continuing security issues in Nigeria.

These negative factors were offset in part by:

(i)

continuing production ramp-up/start-ups in Angola, Congo, Egypt, Kazakhstan, Venezuela and the Gulf of Mexico; and

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(ii)

higher entitlements in certain Production Sharing Agreements (PSAs) and similar contractual schemes (up 35 KBOE/d compared to 2008) due to lower oil prices. Under such contracts, Eni is entitled to fixed monetary amounts settled in quantities of oil to recover the expenses incurred for the development of the relevant properties and as a consequence of lower oil prices, the volumes entitlements necessary to cover the same amount of expenses are higher.

Worldwide gas sales in 2009 amounted to 103.7 BCM, down 0.5% from 2008 due to lower volumes supplied to the Italian market against the backdrop of the economic downturn and stronger competitive pressures (down 12.83 BCM, or 24.3%). The decline in sales in Italy were partly offset by higher volumes associated with the full contribution of the Distrigas acquisition (up 12.02 BCM for the full year) and organic growth achieved in a number of European markets.

Capital expenditures in 2009 amounted to euro 13,695 million (euro 14,562 million in 2008), of which 86% related to the Exploration & Production (up 2.2%), Gas & Power (down 18.1%) and Refining & Marketing (down 34.2%) divisions. Main expenditures were the following:

•		oil & gas development activities were euro 7,478 million and were deployed mainly in Kazakhstan, the United States, Egypt, Congo, Italy and Angola;
•		exploration projects were euro 1,228 million of which 97% were carried out outside Italy, primarily in the United States, Libya, Egypt, Norway and Angola;
•		acquisition of proved and unproved properties amounting to euro 697 million mainly related to the acquisition of a 27.5% interest in assets with gas shale reserves from Quicksilver Resources Inc and extension of the duration of oil and gas properties in Egypt following the agreement signed in May 2009;
•		development and upgrading of Eni’s natural gas transport network in Italy amounted to euro 919 million. Distribution network upgrades were euro 278 million, and further euro 282 million were invested to develop and increase storage capacity;
•		projects aimed at improving the conversion capacity and flexibility of refineries amounted to euro 436 million. Building and upgrading service stations in Italy and outside Italy absorbed euro 172 million; and
•		upgrading of the fleet used in the Engineering & Construction division amounted to euro 1,630 million.

In 2009, Eni completed the acquisition of Distrigas corresponding to a total investment of euro 2,045 million.

During 2010-2013 four-year period, Eni expects to invest approximately euro 52.8 billion in capital expenditures and exploration projects to implement its growth strategy, based on the assumptions discussed below under “Management’s Expectation of Operations”.

 

Trading Environment

		2007		2008		2009

Average price of Brent dated crude oil in U.S. dollars (1)		72.52		96.99		61.51
Average price of Brent dated crude oil in euro (2)		52.90		65.93		44.16
Average EUR/USD exchange rate (3)		1.371		1.471		1.393
Average European refining margin in U.S. dollars (4)		4.52		6.49		3.13
Euribor - three month euro rate % (3)		4.3		4.6		1.2

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

When the term margin is used in the following discussion, it refers to the difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemicals products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.

Eni’s results of operations and the year to year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. See "Item 3 – Risk Factors".

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In 2009, Eni’s results were achieved in a trading environment characterized by an average 31.2% decrease in hydrocarbon realizations driven by declining Brent prices which were down 36.6% from 2008. Eni’s realized refining margins in dollar terms were sharply lower in the full year 2009, mirroring trends in Brent margins (down $3.4 per barrel, or 51.8%). A number of negative factors explained the reduction. Firstly, significantly compressed light-heavy crude differentials due to a reduction in heavy crude availability on the marketplace negatively affected the profitability of Eni’s complex refineries. Secondly, the industry continued to be plagued by weak fundamentals due to excess capacity, high inventory levels and stagnant demand affecting end-prices, while feedstock costs have been on an upward trend since the beginning of the second half. Finally, middle-distillates margins plunged to historical lows. Results of operations for the year were helped by the depreciation of the euro vs. the U.S. dollar, down by 5.3%.

 

Key Consolidated Financial Data

		2007		2008		2009

(euro million)

Net sales from operations				87,204		108,082		83,227
Operating profit (1)				18,739		18,517		12,055
Net profit attributable to Eni				10,011		8,825		4,367
Net cash provided by operating activities				15,517		21,801		11,136
Capital expenditures				10,593		14,562		13,695
Acquisitions of investments and businesses (2)				9,909		4,305		2,323
Shareholders’ equity including minority interest at year end				42,867		48,510		50,051
Net borrowings at year end (2)				16,327		18,376		23,055
Net profit attributable to Eni basic and diluted		(euro per share)		2.73		2.43		1.21
Dividend per share		(euro per share)		1.30		1.30		1.00
Net borrowings to total shareholders’ equity ratio including minority interest (leverage) (3)				0.38		0.38		0.46

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(1)		From year 2009, the Company accounts gains and losses on non-hedging commodity derivative instruments, including both fair value remeasurement and settled transactions, as items of operating profit. Prior period results have been restated accordingly.
(2)		This item includes acquired net borrowings.
(3)		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. 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 and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the oilfield services construction and engineering businesses. Although the company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates follows.

 

Oil and gas activities

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering 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

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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 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. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred cost – see also item "Current assets") related to natural gas volumes not collected under long term purchase contracts with take-or-pay clauses.

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

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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, it is possible that the Company may incur environmental costs and liabilities in addition to amounts already accrued in the financial statements, which could possibly have 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:

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(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 obligation and employee benefits, Eni accrues for all contingencies that are both probable and reasonably 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.

 

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2007-2009 Group Results of Operations

Overview of the Profit and Loss Account for Three Years Ended December 31, 2007, 2008 and 2009

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,

		2007		2008		2009

(euro million)

Net sales from operations		87,204			108,082			83,227
Other income and revenues (1)		833			728			1,118
Total revenues		88,037			108,810			84,345
Operating expenses		(61,933	)		(80,354	)		(62,532	)
Other operating income (expense) (2)		(129	)		(124	)		55
Depreciation, depletion, amortization and impairments		(7,236	)		(9,815	)		(9,813	)
OPERATING PROFIT		18,739			18,517			12,055
Finance income (expense)		46			(640	)		(551	)
Income (expense) from investments		1,243			1,373			569
PROFIT BEFORE INCOME TAXES		20,028			19,250			12,073
Income taxes		(9,219	)		(9,692	)		(6,756	)
NET PROFIT		10,809			9,558			5,317
Attributable to:
- Eni		10,011			8,825			4,367
- minority interest		798			733			950

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(1)		Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income.
(2)		From year 2009, the Company accounts gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and settled transactions, as items of operating profit. Prior period results have been restated accordingly.

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,

		2007		2008		2009

(%)

Operating expenses		71.0		74.3		75.1
Depreciation, depletion, amortization and impairments		8.3		9.1		11.8
OPERATING PROFIT		21.5		17.1		14.5

2009 compared to 2008. Net profit pertaining to Eni in 2009 was euro 4,367 million, a decrease of euro 4,458 million from 2008, or 50.5%. This decrease was affected by the following factors:

(i)		a decreased operating profit reported by the Exploration & Production and Gas & Power segments due to lower oil and gas prices and a weaker gas demand. The Group results were also affected by higher amortization charges taken in connection with new investments. Those negatives were partly offset by recognition of lower inventory write-downs and impairments of property, plant and equipment particularly in the Refining & Marketing and Petrochemical segments. As a result, the Group consolidated operating profit was down euro 6,462 million, or 34.9%, from a year ago;
(ii)		lower profit (down euro 804 million) from non consolidated entities that are accounted for under the equity or the cost method; and
(iii)		a higher consolidated tax rate up from 50.3% to 56% (up 5.7 percentage points), mainly due to new tax rules both in Italy and outside Italy which impacted taxes currently payable, charges accounted in the year which were excluded from tax calculations, and the circumstance that in 2008 the tax rate benefited from certain tax gains associated with an adjustment to deferred taxation amounting to euro 733 million as new tax provisions came into effect pertaining to both Italian and foreign subsidiaries.

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

(i)		higher finance expenses (up euro 686 million) were recorded mainly reflecting losses incurred on fair value valuation of certain derivative financial instruments that do not meet the formal criteria to be qualified as hedges under IFRS (down euro 582 million). Additionally, higher finance charges on finance debt were incurred as 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)		increase in income taxes were recorded (up 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); and
(iii)		a decrease in operating profit, down euro 222 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.

 

Discontinued Operations

Discontinued operations in 2009, 2008 and 2007 were immaterial.

 

Analysis of the Line Items of the Profit and Loss Account

a) Total Revenues

Eni’s total revenues were euro 84,345 million, euro 108,810 million and euro 88,037 million for the year ended December 31, 2009, 2008 and 2007, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations amounted to euro 83,227 million, euro 108,082 million and euro 87,204 million for the year ended December 31, 2009, 2008 and 2007, respectively, and its other income and revenues totaled euro 1,118 million, euro 728 million and euro 833 million, respectively, in these periods.

 

 

 

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Net sales from operations

The table below sets forth, for the periods indicated, the 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,

		2007		2008		2009

(euro million)

Exploration & Production (1)		26,920			33,042			23,801
Gas & Power (1)		27,793			37,062			30,447
Refining & Marketing (2)		36,349			45,017			31,769
Petrochemicals		6,934			6,303			4,203
Engineering & Construction		8,678			9,176			9,664
Other activities		205			185			88
Corporate and financial companies		1,313			1,331			1,280
Impact of unrealized intragroup profit elimination					75			(66	)
Consolidation adjustment (3)		(20,988	)		(24,109	)		(17,959	)
NET SALES FROM OPERATIONS		87,204			108,082			83,227

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2009 compared to 2008. Eni’s net sales from operations (revenues) for 2009 (euro 83,227 million) were down euro 24,855 million, or 23% from 2008, primarily reflecting lower realizations on oil, products and natural gas in dollar terms and lower sales volumes. These negatives were partly offset by the positive impact of the depreciation of the euro versus the dollar (down 5.3%).

Revenues generated by the Exploration & Production division (euro 23,801 million) decreased by euro 9,241 million, or 28% from 2008, mainly due to lower realizations in dollars (oil down 32.2%; natural gas down 29.8%) reflecting a trading environment that was particularly adverse in the first nine months and the impact of energy parameters on gas prices and a fall in gas spot prices. This decrease reflected also lower sales volumes (down 9.2 million BOE, or 1.5%). These negatives were partly offset by the depreciation of the euro vs. the U.S. dollar.

Revenues generated by the Gas & Power division (euro 30,447 million) decreased by euro 6,615 million, or 17.8% from 2008, mainly due to lower gas prices reflecting trends in energy parameters, as well as lower volumes sold in Italy (down 12.8 BCM, or 24.2%) due to the impact of the economic downturn. These negatives were partly offset by increased sales outside Italy due to contribution of the Distrigas acquisition (up 12.02 BCM).

Revenues generated by the Refining & Marketing division (euro 31,769 million) decreased by euro 13,248 million, or 29.4% from 2008, reflecting lower product prices and lower sales volumes (down 10%), that were partially offset by the impact of the depreciation of the euro vs. the dollar.

Revenues generated by the Petrochemical division (euro 4,203 million) decreased by euro 2,100 million, or 33.3% from 2008, mainly reflecting lower sales prices (down 26%) due to lower international prices for crude oil and refined products and a decline in volumes sold due to lower end-markets demand that was driven down by the economic downturn.

Revenues generated by the Engineering & Construction business (euro 9,664 million) increased by euro 488 million, or 5.3% from 2008, as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle.

2008 compared to 2007. Eni’s net sales from operations (revenues) for 2008 (euro 108,082 million) were up euro 20,878 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 the appreciation of the euro versus the dollar (up 7.3%).

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Revenues generated by the Exploration & Production division (euro 33,042 million) increased by euro 6,122 million, or 22.7% from 2007, mainly due to higher realizations in dollars (oil up 24.2%, natural gas up 47.8%). Eni’s liquid realizations (84.05 $/BBL) 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 per barrel (for a more detailed explanation about this issue see the discussion on results of the Exploration & Production division below). Revenue increases in 2008 were also driven by production growth (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 37,062 million) increased by euro 9,269 million, or 33.4% from 2007, 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 45,017 million) increased by euro 8,668 million, or 23.8% from 2007, 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, or 9.1% from 2007, 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, or 5.7% from 2007, due to increased activity levels.

 

b) Operating Expenses

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

	Year ended December 31,

		2007		2008		2009

(euro million)

Purchases, services and other		58,133		76,350		58,351
Payroll and related costs		3,800		4,004		4,181
Operating expenses		61,933		80,354		62,532

2009 compared to 2008. Operating expenses for 2009 (euro 62,532 million) were down euro 17,822 million from 2008, or 22.2%, reflecting primarily lower supply costs of purchased oil, gas and petrochemical feedstocks, partially offset by the depreciation of the euro against the dollar. Purchases, services and other included environmental and other risk provisions, impairments of certain current and non-current assets, other than tangible and intangible assets, amounting to euro 537 million. They also included a charge amounting to euro 250 million which was estimated on the basis of the possible resolution of an investigation related to the TSKJ consortium based on the current status of the ongoing discussions with U.S. Authorities.

Payroll and related costs (euro 4,181 million) increased by euro 177 million from 2008 (up 4.4%) mainly due to higher unit labor cost in Italy and outside Italy, partly due to exchange rate translation differences, the increase in the average number of employees outside Italy, following the consolidation of Distrigas in the Gas & Power division, increased personnel in the Engineering & Construction and Exploration & Production businesses due to higher activity levels, as well as increased provisions for redundancy incentives. These increases were partially offset by a decrease in the average number of employees in Italy.

2008 compared to 2007. Operating expenses for 2008 (euro 80,354 million) increased by euro 18,412 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. 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, following the consolidation of acquired assets, as well as increased personnel in the

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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.

 

c) Depreciation, Depletion, Amortization and Impairments

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

	Year ended December 31,

		2007		2008		2009

(euro million)

Exploration & Production (1)		5,431			6,678			6,789
Gas & Power		739			797			981
Refining & Marketing		433			430			408
Petrochemicals		116			117			83
Engineering & Construction		248			335			433
Other activities		4			3			2
Corporate and financial companies		68			76			83
Impact of unrealized intragroup profit elimination (2)		(10	)		(14	)		(17	)
Total depreciation, depletion and amortization		7,029			8,422			8,762
Impairments		207			1,393			1,051
		7,236			9,815			9,813

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(1)		Exploratory expenditures of euro 1,551 million, euro 2,057 million and euro 1,778 million are included in these amounts relative to the years 2009, 2008 and 2007, respectively.
(2)		This item concerned mainly intra-group sales of goods, services and capital assets recorded at period end in the equity of the purchasing business segment.

2009 compared to 2008. In 2009 depreciation, depletion and amortization charges (euro 8,762 million) increased by euro 340 million, or 4% from 2008, mainly in: (i) the Gas & Power division (up euro 184 million) reflecting consolidation of assets acquired and entry into service of new investments; and (ii) the Exploration & Production segment (up euro 111 million) where higher charges were associated with the depreciation of the euro against the dollar, rising development activities reflecting consolidation of acquired oil & gas properties and increased expenditures to develop new complex fields and projects. These negatives were partly offset by lower exploration expenses. The Engineering & Construction segment also increased amortization charges in connection with the entry into service of new assets.

In 2009, impairments (euro 1,051 million) which were down euro 342 million, mainly related to: (i) impairment charges recorded on proved and unproved properties in the Exploration & Production division due to downward reserve revisions and cost increases mainly recorded in the Gulf of Mexico, Australia, Congo and Egypt; (ii) refinery plants due to expectations of poor refining margins reflecting the industry weak fundamentals and plants’ specific factors such as low complexity. Also impairments of goodwill were recognized on marketing assets acquired in Central-Eastern Europe and certain other marketing assets in the Refining & Marketing division, in the light of a downsizing of growth expectations on certain markets; and (iii) a number of plants in the Petrochemical division due to a weak outlook for pricing/margins as a result of lower petrochemical products demand, excess capacity and higher competitive pressures.

2008 compared to 2007. In 2008 depreciation, depletion and amortization charges (euro 8,422 million) increased by euro 1,393 million, or 19.8% from 2007, mainly in the Exploration & Production segment (up euro 1,247 million), The higher charges incurred in the Exploration & Production segment were associated with: (i) rising 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 negatives 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. A number of plants and equipments in the

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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.

 

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,

		2007		2008		2009

(euro million)

Exploration & Production (1)		13,433			16,239			9,120
Gas & Power (1)		4,465			4,030			3,687
Refining & Marketing		686			(988	)		(102	)
Petrochemicals		100			(845	)		(675	)
Engineering & Construction		837			1,045			881
Other activities		(444	)		(346	)		(382	)
Corporate and financial companies		(312	)		(743	)		(474	)
Impact of intragroup profits elimination		(26	)		125
Operating profit (2)		18,739			18,517			12,055

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(1)		From January 1, 2009, results of the gas storage business, which were previously reported within the Exploration & Production segment, are reported within the Gas & Power segment reporting unit, following restructuring of Eni regulated gas businesses in Italy. As of that date, the results of the regulated businesses in Italy therefore include results of the Transport, Distribution, Re-gasification and Storage activities in Italy. Prior period results have been restated accordingly.
(2)		From year 2009, the Company accounts gains and losses on non-hedging commodity derivatives instruments, including both fair value re-measurement and settled transactions, as items of operating profit. Prior period results have been restated accordingly.

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,

		2007		2008		2009

(%)

Exploration & Production		49.9			49.1			38.3
Gas & Power		16.1			10.9			12.1
Refining & Marketing		1.9			(2.2	)		(0.3	)
Petrochemicals		1.4			(13.4	)		(16.1	)
Engineering & Construction		9.6			11.4			9.1
Other activities		(216.6	)		(187.0	)		(434.1	)
Corporate and financial companies		(23.8	)		(55.8	)		(37.0	)
Group		21.5			17.1			14.5

Exploration & Production. Operating profit in 2009 amounted to euro 9,120 million, down euro 7,119 million from 2008, or 43.8%, reflecting lower realizations in dollars (oil down 32.2%; natural gas down 29.8%), and reduced production sales volumes (down 9.2 mmBOE, or 1.5%). These negatives were partly offset by: (i) positive currency translation differences which were reported by subsidiaries which adopted the U.S. dollar as functional currency, as the euro depreciated on average by 5.3%. This had an estimated positive impact of euro 500 million; (ii) recognition of lower asset impairments (down euro 234 million); and (iii) gains recorded on the divestment of certain exploration and production assets as part of the agreements signed with Suez.

Liquids and gas realizations for the year decreased on average by 31.2% in dollar terms driven by lower oil prices for market benchmarks (Brent crude price decreased by 36.6%), partly offset by an improved product mix of Eni’s crudes (down 32.2%). Average oil realizations were barely unchanged, due to the settlement of certain non-strategic commodity derivatives relating to the sale of 42.2 mmBBL.

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In 2009, the impact of those cash flow hedges was immaterial as the increase in liquids realizations by $0.45 per barrel as a result of the sale of 31.6 mmBBL at the hedged price recorded in the first nine months was absorbed by a reduction on average by $1.46 per barrel from the sale of 10.6 mmBBL in the fourth quarter, reflecting the inversion in oil prices trends. The derivatives were entered into to hedge exposure to fluctuations in future cash flows expected from the sale of a portion of the Company’s proved reserves, in connection with the acquisition of oil and gas assets in Congo and in the Gulf of Mexico. When entered into, those hedging transactions originally covered an amount of approximately 125.7 mmBBL in the 2008-2011 period, which by the end of 2009 has decreased to approximately 37.5 mmBBL.

In 2009 average gas realizations were down 29.8%, driven by time-lags between movements in oil prices and their effect on gas prices pursuant to pricing formulae and by weak spot prices.

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

		Full Year

		2008		2009

Sales volumes		(mmBBL)		364.30			373.50
Sales volumes hedged by derivatives (cash flow hedge)				46.00			42.20
Total price per barrel, excluding derivatives		($/BBL)		88.17			56.98
Realized gains (losses) on derivatives				(4.13	)		(0.03	)
Total average price per barrel				84.05			56.95

Operating profit in 2008 amounted to euro 16,239 million, up euro 2,806 million from 2007, or 20.9%, reflecting higher realizations in dollars (oil up 24.2%; natural gas up 47.8%) and increased production sales volumes (up 20.1 mmBOE). These positives were partly offset by: (i) the recognition of significantly higher asset impairments (down euro 667 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 which 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 increased expenditures to develop new fields and to sustain production performance at mature fields; and (iv) increased exploration expenses (euro 420 million on a constant basis exchange rate basis) in connection with higher geological and geophysical expenses and increased exploratory drilling expenditures that are amortized in full as incurred.

Gas & Power. Operating profit in 2009 amounted to euro 3,687 million, a decrease of euro 343 million compared with 2008, down by 8.5%. This decrease was principally due to the following factors: (i) lower results from marketing operations in Italy as sales volumes of gas declined by 12.83 BCM, or 24.3%, due to the impact of lower gas demand and competitive pressures, also impacting selling margins. The negative margin/volume performance in marketing operations was incurred notwithstanding a positive impact associated with the renegotiation of certain long-term supply contracts; (ii) a negative impact on gas inventory valuation associated with falling gas prices which resulted in a decreased carrying amount of gas inventories recorded at the weighted average cost or net realizable value, whichever is lower; and (iii) a provision accounted in the LNG business associated with poor market perspectives in the United States. These negatives were partly offset by: (i) the circumstance that sales to residential customers in Italy and other customers consuming less than 200,000 CM/y benefited from the regulatory indexation mechanism whereby the selling price was updated with a certain delay to changed market conditions, resulting in higher margins on those sales. Management believes that this mechanism will have an opposite effect on the Company’s results in coming quarters; and (ii) positive mark-to-market evaluation of certain commodity derivatives which are recorded against profit as they lack formal requirements to be designated as hedges under applicable accounting standards. The International Transport business recorded a drop in operating profit; while regulated businesses in Italy increased their result.

Operating profit in 2008 amounted to euro 4,030 million, a decrease of euro 435 million, or 9.7% compared to 2008. 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. In fact, the Company 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 reflect a longer time span in the indexation to the U.S. dollar. 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 recycled

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through 2007 profit and loss 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 negatives were partly offset by an increase in operating results from regulated businesses in Italy.

Refining & Marketing. In 2009, the Refining & Marketing segment reported an operating loss of euro 102 million, which represented a significant improvement (up euro 886 million) compared to 2008 when a loss of euro 988 million was recorded. The improvement reflected the circumstance that an inventory write-down amounting to euro 1,199 million was recorded in 2008 as year-end inventories of oil and products were aligned to net realizable values prevailing on the marketplace at the time of the assessment which coincided with the low of the oil cycle. In 2009, an inventory holding gain amounting to euro 792 million was recognized reflecting the impact of a recovery in prices of crude oil and products on year-end valuation of inventories according to the average-cost method of inventory accounting. When excluding the inventory impacts, the Refining & Marketing segment reported underlying losses mainly due to sharply lower refining margins. Those were affected by an unfavorable trading environment due to weak end-prices of products depressed by poor demand, excess inventory of finished products on the marketplace, in particular diesel oil, whose spread on raw material reached historical lows in the fourth quarter, and excess capacity. As a result, product price did not absorbed the purchase price of oil-based feedstock. Also narrowing price differentials between heavy and light crude qualities negatively affected Eni’s complex throughputs by reducing cost-advantages associated to conversion: (i) lower operating performance delivered by the Marketing activities affected by weak demand in wholesale markets in Italy and retail European markets; and (ii) higher asset impairment charges recorded in the light of the negative outlook for the refining industry and a downsizing of growth expectations on certain markets.

The Refining & Marketing segment in 2008 reported an operating loss of euro 988 million, a euro 1,674 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 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 perspectives on the back 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 costs 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.

On the positive side, the refining business delivered a better operating performance on the back of a favorable trading environment for Eni’s complex refineries, reflecting increasing discounts on sour crudes, increasing margins from certain of the company’s secondary products (such as base lubricants and bitumen). Marketing activities in Italy also reported higher operating results due to a recovery in retail margins and increased sales volumes as a result of an increased market share. The increase in wholesale business was due to higher margins.

Petrochemicals. In 2009 the Petrochemical segment reported an operating loss in the amount of euro 675 million, which represented an improvement of euro 170 million compared to 2008 mainly due to lower impairment losses (down euro 157 million from 2008). The segment’s results continued to be affected by weak industry fundamentals due to poor demand, excess capacity and competitive pressures. As a result, the segment reported unprofitable margins on products and lower sales volumes (down 8.9%).

In 2008 the Petrochemical segment reported an operating loss in the amount of euro 845 million, a euro 945 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 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 perspectives on the back of lowered expectations for the future unfavorable trading environment.

Engineering & Construction. Operating profit in 2009 amounted to euro 881 million, a decrease of euro 164 million, or 15.7% compared to 2008. This decrease related to a non-recurring item represented by a charge amounting to euro 250 million that was the estimated cost of a possible resolution of the investigation related to the TSKJ consortium based on the current status of ongoing discussions with U.S. Authorities (See “Item 18 – Note 28 of the Financial Statements”). Although the charge was recognized in the segment results of the Engineering & Construction business as it related to a project to build gas liquefaction plants, it will be fully incurred by Eni and Saipem’s minorities will be left unaffected due to Eni’s contractual obligations to indemnify Saipem undertaken in connection with the divestiture of Snamprogetti SpA, whose subsidiary Snamprogetti Netherlands BV participates to the TSKJ venture. See “Item 8 Financial Information – Legal Proceedings” for further details. When excluding the

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impact of the charge, the segment reported an improved operating performance recorded in all business areas reflecting steady revenue growth and stable profitability as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle.

Operating profit in 2008 amounted to euro 1,045 million, a euro 208 million increase compared to 2007, or 24.9%. 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.

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 382 million for 2009, representing a reduction of euro 36 million, or 10.4%, compared to the loss recorded in 2008 (euro 346 million) mainly due to higher environmental charges (euro 153 million).

Other activities reported an operating loss of euro 346 million for 2008, representing an improvement of euro 98 million, or 22.1%, compared to the loss recorded in 2007 (euro 444 million) mainly due to impairment losses, as well as lower environmental charges (euro 101 million).

Corporate and financial companies. These activities include expenses incurred in connection with corporate activities including the central treasury department and financial subsidiaries that provide a range of 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 474 million for 2009, representing a reduction of euro 269 million, compared to the loss recorded in 2008 (euro 743 million), mainly reflecting the circumstance that in 2008 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 were accounted for.

The aggregate Corporate and financial companies reported an operating loss of euro 743 million for 2008, representing a decline of euro 431 million, compared to the loss recorded in 2007 (euro 312 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.

 

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,

		2007		2008		2009

(euro million)

Gain (loss) on derivative financial instruments		155			(427	)		(4	)
Exchange differences, net		(51	)		206			(106	)
Interest income		236			87			33
Finance expense on short and long-term debt		(703	)		(993	)		(753	)
Finance expense due to passage of time		(186	)		(249	)		(218	)
Income from equity instruments		188			241			163
Other finance income and expense, net		227			259			111
		(134	)		(876	)		(774	)
Finance expense capitalized		180			236			223
		46			(640	)		(551	)

2009 compared to 2008. In 2009 net finance expenses were euro 551 million, a decrease of euro 89 million from 2008. This was mainly due to increased losses on exchange differences (up euro 312 million) offset by gains recognized in connection with fair value evaluation through profit and loss of certain derivative instruments on

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exchange rates (up euro 423 million) which were recorded against profit as they did not qualify for hedge accounting. In addition, lower finance charges were incurred as interest rates on euro-denominated finance debt (Euribor down 3.4 percentage points) and on dollar loans (Libor down 2.2 percentage points) were down. A gain from an interest amounting to euro 163 million was recorded (euro 241 million in 2008) related to the contractual remuneration of 9.4% on the 20% interest in OAO Gazprom Neft, calculated up to April 24, 2009, when Gazprom paid for the call option exercised on April 7, 2009.

2008 compared to 2007. In 2008 net finance expenses were euro 640 million an increase of euro 686 million from 2007. This was mainly due to a net loss of euro 427 million (as compared to a net gain of euro 155 million in 2007) recognized in connection with fair value valuation through profit and loss of certain derivatives instruments on exchange rates. 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.

 

f) Net Income from Investments

2009 compared to 2008. Net income from investments in 2009 was a net gain of euro 569 million and mainly related to: (i) the share of profit of entities accounted for with the equity method (euro 393 million), mainly in the Gas & Power and Exploration & Production divisions. Gains also comprised a gain on Eni’s 60% interest in Artic Russia (euro 100 million) due to the divestment of a 51% stake in OOO Severenergia to Gazprom based on the call option exercised by the Russian company; and (ii) dividends received by entities accounted for at cost (euro 164 million), mainly related to Nigeria LNG Ltd.

2008 compared to 2007. Net income from investments in 2008 was a net gain of euro 1,373 million and 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.

 

g) Taxes

2009 compared to 2008. In 2009, income taxes amounted to euro 6,756 million, down euro 2,936 million from a year ago, or 30.3%, mainly reflecting reduced income taxes currently payable recorded by subsidiaries in the Exploration & Production division operating outside Italy due to lower taxable profit.

The Group reported consolidated tax rate was higher compared to 2008, from 50.3% to 56% (up 5.7 percentage points). A number of factors explained the increase:

(i)		The impact of recently enacted tax regulations that provided a one-percentage point increase in the tax rate applicable to Italian companies in the energy sector and enactment of a supplemental tax rate to be added to the Italian statutory tax rate resulting in higher taxes currently payable, amounting to euro 239 million for the full year;
(ii)		The recognition of a non-recurring item which was a non-deductible tax item, represented by a charge amounting to euro 250 million that was the estimated cost of the possible resolution of the investigation related to the TSKJ consortium based on the current status of ongoing discussions with U.S. Authorities. The matter is fully disclosed in the section “Legal Proceedings” in Note 28 to the Consolidated Financial Statements;
(iii)		The payment of a balance for prior-year income taxes amounting to $310 million (or euro 230 million) in Libya as new rules came into effect which reassessed revenues for tax purposes;
(iv)		A write-down of certain deferred tax assets associated with upstream properties to factor in expected lower profitability (down euro 72 million);
(v)		A lower capacity for Italian companies to deduct the cost of goods sold associated with lower gas inventories at year end (down euro 64 million); and
(vi)		The circumstance that in 2008 certain tax gains associated with an adjustment to deferred taxation amounting to euro 733 million were recorded as new tax provisions came into effect pertaining to both Italian and foreign subsidiaries.

These higher tax expenses were partly offset by recognition of a positive adjustment to deferred taxation following alignment of the tax base of certain oil and gas properties to their higher carrying amounts by paying a one-off tax, as part of the reorganization of upstream activities in Italy, and lower income taxes currently payable as

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new rules came into effect providing for the partial deduction of an Italian local tax from taxable income, also applying to previous fiscal years (for a total positive impact of euro 222 million).

In 2010 management expects the Group effective tax-rate to be flat to slightly lower compared to 2009 (see "Item 3 – Risk Factors").

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 division operating outside Italy due to higher taxable profit.

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

•		a net gain amounting to euro 176 million was recorded in connection with new tax rules in Italy that changed the tax treatment of inventories. Law Decree No. 112 of June 25, 2008 (Converted in to Law No. 133/2008) requires that from 2008 Italian energy companies state inventories of hydrocarbons at the weighted-average cost for tax purposes as opposed to the previous LIFO valuation and to recognize a one-off tax calculated by applying a special rate of 16% on the difference between the two amounts. This provision triggered utilization of deferred tax liabilities recognized until 2008 that were accrued by applying the statutory tax rate to the 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 (euro 528 million) partly offset by the recognition of a one-off tax amounting to euro 229 million. This one-off tax will be paid in three annual installments of same amount, due from 2009 onwards. Deferred taxation was accrued on hydrocarbons inventories based on the applicable statutory tax rate of 33% as enacted in June 2008 compared with 27.5% of the previous tax regime representing an expense of euro 123 million;
•		application of the statutory tax rate of 33% pursuant to Law Decree No. 112/2008 replacing the previously applicable tax rate of 27.5% on certain deferred tax assets of Italian subsidiaries resulting in a gain of euro 94 million;
•		application of the Italian Budget Law for 2008 that provided 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 applying a special rate of 6% resulting in a net positive impact on profit and loss of euro 290 million;
•		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 deferred tax liabilities (euro 173 million).

These positives were partly offset by the circumstance 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 recycling trough profit and loss excess deferred taxation resulting in a net positive impact of euro 773 million.

 

h) Minority Interest

2009 compared to 2008. Minority interest was euro 950 million, up euro 217 million from 2008, or 29.6%, and concerned primarily Saipem SpA (euro 567 million) and Snam Rete Gas SpA (euro 369 million).

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).

 

 

Liquidity and Capital Resources

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

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

	Year ended December 31,

		2007		2008		2009

(euro million)

Net profit		10,809			9,558			5,316
Adjustments to reconcile to cash generated from operating profit before changes in working capital:
- depreciation, depletion and amortization and other non monetary items		6,346			11,388			9,847
- net gains on disposal of assets		(309	)		(219	)		(226	)
- dividends, interest, income taxes and other changes		8,850			9,080			6,687
Net cash generated from operating profit before changes in working capital		25,696			29,807			21,625
Changes in working capital related to operations		(1,667	)		2,212			(1,769	)
Dividends received, taxes paid, interest (paid) received during the year		(8,512	)		(10,218	)		(8,720	)
Net cash provided by operating activities		15,517			21,801			11,136
Capital expenditures		(10,593	)		(14,562	)		(13,695	)
Acquisitions of investments and businesses		(9,665	)		(4,019	)		(2,323	)
Disposals		659			979			3,595
Other cash flow related to investing activities		(514	)		644			101
Changes in short and long-term finance debt		8,761			980			3,841
Dividends paid and changes in minority interest and reserves		(5,836	)		(6,005	)		(2,956	)
Effect of changes in consolidation and exchange differences		(200	)		7			(30	)
Change in cash and cash equivalents for the year		(1,871	)		(175	)		(331	)
Cash and cash equivalents at the beginning of the year		3,985			2,114			1,939
Cash and cash equivalents at year end		2,114			1,939			1,608

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

	Year ended December 31,

		2007		2008		2009

(euro million)

Net cash provided from operating activities		15,517			21,801			11,136
Capital expenditures		(10,593	)		(14,562	)		(13,695	)
Acquisitions of investments and businesses		(9,665	)		(4,019	)		(2,323	)
Disposals		659			979			3,595
Other cash flow related to capital expenditures, investments and divestments		(35	)		(267	)		(295	)
Net borrowings (1) of acquired companies		(244	)		(286	)
Net borrowings (1) of divested companies					181
Exchange differences on net borrowings and other changes		637			129			(141	)
Dividends paid and changes in minority interest and reserves		(5,836	)		(6,005	)		(2,956	)
Change in net borrowings (1)		(9,560	)		(2,049	)		(4,679	)
Net borrowings (1) at the beginning of the year		6,767			16,327			18,376
Net borrowings (1) at year end		16,327			18,376			23,055

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(1)

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

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

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

Net cash generated from operating profit before changes in working capital totaled euro 21,625 million in 2009 (euro 29,807 million in 2008), down euro 8,182 million from 2008.

Net profit for 2009 was adjusted to take into account non-monetary charges and gains amounting to euro 9,847 million, which primarily regarded depreciation, depletion and amortization of tangible and intangible assets (euro 8,762 million), non-monetary charges relating to environmental and risk provisions, impairments of property, plant and equipment and investments (euro 1,085 million). Adjustments to net profit also included income taxes (euro 6,756 million) and interest expenses (euro 603 million).

Net profit for 2008 was adjusted to take into account amortization, depletion and depreciation 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 expenses (euro 809 million).

 

b) Changes in Working Capital related to Operations

In 2009, changes in working capital absorbed flows amounting to a negative euro 1,769 million as a result of a decreased balance between trade payables and receivables.

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. These positives were partly offset by cash outflows associated with increased trade receivables.

 

c) Investing Activities

	Year ended December 31,

		2007		2008		2009

(euro million)

Exploration & Production		6,480			9,281			9,486
Gas & Power		1,511			2,058			1,686
Refining & Marketing		979			965			635
Petrochemicals		145			212			145
Engineering & Construction		1,410			2,027			1,630
Other activities		59			52			44
Corporate and financial companies		108			95			57
Impact of unrealized profit in inventory		(99	)		(128	)		12
Capital expenditures		10,593			14,562			13,695
Acquisitions of investments and businesses		9,665			4,019			2,323
		20,258			18,581			16,018
Disposals		(659	)		(979	)		(3,595	)
NET INVESTMENT		19,599			17,602			12,423

Capital expenditures totaled euro 13,695 million and euro 14,562 million respectively in 2009 and in 2008.

In 2009, 86% of capital expenditures related to the Exploration & Production (euro 9,486 million), Gas & Power (euro 1,686 million) and Refining & Marketing (euro 635 million) segments.

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

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Acquisitions of investments and businesses totaled euro 2,323 million in 2009 and euro 4,019 million in 2008. Main acquisitions executed in the year are outlined in "Item 4 – Significant business and portfolio developments for the year".

Disposals amounted to euro 3,595 million in 2009 and euro 979 million in 2008.

In 2009, disposals primarily related to: (i) the divestment of a 20% interest in Gazprom Neft following exercise of a call option by Gazprom on April 7, 2009 (amounting to euro 3,070 million). The exercise price of the call option was equal to the bid price ($3.7 billion) as adjusted by subtracting dividends distributed and adding the contractual annual remuneration of 9.4% on capital employed and certain financial collateral expenses; (ii) the divestment to Gazprom of a 51% stake in the joint venture OOO SeverEnergia (Eni 60%). Eni’s share of the transaction is worth $940 million of which $230 million were collected as of year end, which corresponded to euro 155 million at the exchange rate on the transaction date. The remaining part of the divestment was collected by March 31, 2010; and (iii) other disposals relating to non strategic oil & gas properties following agreements signed with Suez.

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) and the sale of Agip España by the Refining & Marketing segment.

 

d) Dividends paid and Changes in Minority Interests and Reserves

In 2009, dividends paid and changes in minority interests and reserves (euro 2,956 million) related mainly to the dividend distribution to Eni shareholders for euro 4,166 million (of which euro 2,355 million related to the balance for the fiscal year 2008 and euro 1,811 million as an interim dividend for fiscal year 2009) and the distribution of dividend to minority interest by Snam Rete Gas SpA and Saipem SpA (euro 335 million) and other consolidated subsidiaries (euro 15 million). These outflows were partly offset by the subscription by Snam Rete Gas SpA minorities of their respective share of a capital increase amounting to euro 1,542 million as part of Eni’s reorganization of its regulated businesses in Italy. This transaction is outlined in “Item 4 – Significant business and portfolio developments for the year”.

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).

 

Financial Condition

In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measures. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including 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 continuously 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 measure, derived from IFRS reported amounts, to leverage 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,

		2007		2008		2009

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)		8,500			11,330			19,830			6,908			13,929			20,837			6,736			18,064			24,800
Cash and cash equivalents		(2,114	)					(2,114	)		(1,939	)					(1,939	)		(1,608	)					(1,608	)
Securities not related to operations		(174	)					(174	)		(185	)					(185	)		(64	)					(64	)
Non-operating financing receivables		(990	)		(225	)		(1,215	)		(337	)					(337	)		(73	)					(73	)
Net borrowings		5,222			11,105			16,327			4,447			13,929			18,376			4,991			18,064			23,055

 

	As of December 31,

		2007		2008		2009

Shareholders’ equity including minority interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS		(euro million)		42,867			48,510			50,051
Ratio of total debt to total shareholders’ equity including minority interest				0.46			0.43			0.50
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including minority interest				(0.08	)		(0.05	)		(0.04	)
Ratio of net borrowing to total shareholders’ equity including minority interest (leverage)				0.38			0.38			0.46

In 2009, net borrowings amounted to euro 23,055 million, representing a euro 4,679 million increase from 2008. This increase was mainly due to the large amount of capital expenditures made in the year, the completion of the Distrigas acquisition and dividend payment to shareholders executed in the year. These outflows were only partially funded with cash flows from operations, divestments for the year and capital transactions. Total debt of euro 23,055 million consisted of euro 6,736 million of short-term debt (including the portion of long-term debt due within twelve months equal to euro 3,191 million) and euro 18,064 million of long-term debt.

Total debt included bonds for euro 10,576 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 993 million (including accrued interest and discount). Bonds issued in 2009 amounted to euro 5,058 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (83%), U.S. dollar (13%), pound sterling (3%) and 1% in other currencies.

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).

 

Short-term Debt

As of December 31, 2009, short-term debt of euro 6,736 million (including the portion of long-term debt due within twelve months) decreased by euro 172 million over 2008. The weighted average interest rate of Eni’s short-term debt was 0.8% and 4.2% for the years ended December 31, 2009 and 2008, respectively.

As of December 31, 2009, Eni had undrawn committed and uncommitted borrowing facilities available of euro 2,241 million and euro 9,533 million, respectively (euro 3,313 and euro 7,696 million as of December 31, 2008).

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These facilities were under interest rates that reflected market conditions. Changes in unutilized facilities were not significant.

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.

 

Long-term Debt

As of December 31, 2009, long-term debt of euro 18,064 million increased by euro 4,135 million over 2008.

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 the maintenance of a minimum level of rating. According to the agreements, in case the latter condition is impaired, the Company shall provide new guarantees which the European Investment Bank finds to be satisfactory. As of December 31, 2008 and 2009, the amount of short and long-term debt subject to restrictive covenants was euro 1,323 million and euro 1,508 million, respectively. In case the Company does not comply with the above mentioned covenants management does not expect any significant effects. Furthermore, Saipem SpA entered into certain borrowing facilities in the amount of euro 75 million (the same amount as of December 31, 2008) 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 11,687 million consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 9,419 million and other bonds for a total of euro 2,268 million.

As of December 31, 2008, long-term debt of euro 13,929 million increased by euro 2,599 million over 2007.

 

Capital Expenditures by Segment

Exploration & Production. In 2009, capital expenditures of the Exploration & Production segment amounted to euro 9,486 million, representing an increase of euro 205 million, or 2.2%, from 2008 mainly due to the development of oil and gas reserves (euro 7,478 million) directed mainly outside Italy, in particular Kazakhstan, United States, Egypt, Congo and Angola. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to euro 1,228 million were directed outside Italy in particular to the United States, Libya, Egypt, Norway and Angola. In Italy, exploration activities were directed mainly to the offshore of Sicily. Acquisition of proved and unproved property concerned mainly the acquisition from Quicksilver Resources Inc of a 27.5% interest in the Alliance area, in Northern Texas and the extension of Eni’s mineral rights in Egypt, following the agreement signed in May 2009.

In 2008, capital expenditures of the Exploration & Production segment amounted to euro 9,281 million, representing an increase of euro 2,801 million, or 43.2%, from 2008 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 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.

Gas & Power. In 2009, capital expenditures in the Gas & Power segment totaled euro 1,686 million and related principally to: (i) developing and upgrading the transport network in Italy (euro 1,479 million); (ii) developing and upgrading storage capacity in Italy (euro 282 million); (iii) developing and upgrading the distribution network in Italy (euro 278 million); (iv) completion of construction of combined cycle power plants (euro 73 million), in particular at the Ferrara site; and (v) the upgrading plan of international pipelines (euro 32 million).

In 2008, capital expenditures in the Gas & Power segment totaled euro 2,058 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.

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Refining & Marketing. In 2009, capital expenditures in the Refining & Marketing segment amounted to euro 635 million and regarded mainly: (i) refining, supply and logistics in Italy (euro 436 million), with projects designed to improve the conversion rate and flexibility of refineries, including the construction of an industrial plant employing Eni’s proprietary EST technology and completion of a new hydrocracker at the Sannazzaro refinery (operating from July) and at the Taranto refinery (start-up scheduled in 2010) as well as expenditures on health, safety and environmental upgrades; (ii) upgrade of the retail network in Italy, wholesale and LPG activities (euro 118 million); and (iii) upgrade of the retail network and purchase of service stations in the rest of Europe (euro 54 million). Expenditures on health, safety and the environment amounted to euro 78 million.

In 2008, capital expenditures in the Refining & Marketing segment amounted to euro 965 million and regarded mainly: (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 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.

Petrochemicals. In 2008, capital expenditures in the Petrochemical segment amounted to euro 145 million (euro 212 million in 2008) and regarded mainly plant upgrades (euro 58 million), extraordinary maintenance (euro 28 million), environmental protection, safety and environmental regulation compliance (euro 28 million), upkeeping and rationalization (euro 20 million).

In 2008, capital expenditures in the Petrochemical segment amounted to euro 212 million (euro 145 million in 2007) and regarded mainly 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).

Engineering & Construction. In 2009, capital expenditures in the Engineering & Construction division (euro 1,630 million) mainly regarded the purchase of the lay barge Acergy Piper renamed Castoro Sette, the construction of a new pipelayer and the ultra-deep water Field Development Ship FDS 2, development of a new fabrication yard in Indonesia an the activities for the conversion of a tanker into an FPSO, as well as the construction of the two semisubmersible rigs Scarabeo 8 and 9, the new ultra deep water drill ship Saipem 12000 and the jack up Perro Negro 6.

In 2008, capital expenditures in the Engineering & Construction division (euro 2,027 million) mainly regarded 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.

 

Recent Developments

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

		Three months ended March 31,

		2009		2010

Average price of Brent dated crude oil in U.S. dollars (1)		44.40		76.24
Average price of Brent dated crude oil in euro (2)		34.10		55.09
Average EUR/USD exchange rate (3)		1.302		1.384
Average European refining margin in U.S. dollars (4)		5.34		2.40
EURIBOR - three month euro rate % (3)		2.0		0.6

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

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Eni’s Results of Operations for the First Quarter of 2010

Eni reported improved results for the first quarter of 2010 compared with the first quarter of 2009. Net profit and operating profit increased by 16.7% and 22.2%, respectively driven by higher results reported by the Exploration & Production segment. The Petrochemicals segment recorded lower operating losses. The Refining & Marketing segment reported lowered results. The effective tax rate increased by 1.6 percentage points negatively affecting the Group consolidated results.

The trading environment was characterized by higher oil realizations driven by an ongoing recovery in Brent crude prices (up 71.7% from the first quarter of 2009). Natural gas realizations decreased due to the time lags between movements in oil prices and their effects on gas prices. Refining margins were sharply lower due to prolonged weakness in industry fundamentals. Eni’s results were also negatively influenced by the appreciation of the euro versus the dollar (6.3%).

Improved results reported by the Exploration & Production segment were mainly driven by higher oil realization in dollars and higher sales volumes (up 2.1%). Lower expenditures incurred in connection with lower exploration activity offset higher amortization charges taken in connection with development activities due to production ramp-up at fields which were started in 2009. Production expressed in BOE on an available-for-sale base amounted to 1,762 KBOE/d representing an increase of approximately 2% that was driven by continuing production ramp-up in Nigeria, Congo and U.S., and additions from fields which were started-up in 2009. These positive trends were partly offset by a combined negative impact associated with lower entitlements in Company’s PSAs due to higher oil prices, and lower OPEC restrictions. Also production for the quarter was negatively affected by unplanned facility downtimes and mature field declines, particularly in the North Sea.

The Gas & Power segment reported slightly better operating results as an inventory holding loss incurred last year reversed to profit. This positive was partly offset by a negative impact associated with lower sales volumes and reduced marketing margins caused by increasing competitive pressures mainly on the Italian market. Also margins on gas were negatively affected by unfavorable trends in energy parameters. Eni’s worldwide natural gas sales were 30.5 BCM, down by 5.7% compared with the first quarter of 2009. The performance was negatively affected by sharply lower volumes supplied to the Italian market (down by 2.34 BCM, or 17.7%) due to stronger competitive pressures in the power generation business, industrial customers and wholesalers. Sales outside Italy increased by 2.7% as a result of an organic growth achieved in France, Germany and Northern Europe.

At March 31, 2010 net borrowings declined by approximately 8.7% from December 31, 2009 due to cash inflows provided by operating activities, offset in part by financing requirements for capital expenditures.

 

Significant Transactions

On February 4, 2010, Eni formally presented to the European Commission a set of structural remedies relating certain international gas pipelines. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test, Eni will be in the position to resolve an inquiry started in May 2006 for alleged infringements of the European antitrust regulations in the gas sector, which involved the main players in European gas market. Eni received a statement of objections from the European Commission which alleged that during the 2000-2005 period Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas, thus restricting gas availability in Italy. Given the strategic importance of the Austrian TAG pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake to an entity controlled by the Italian State. In case they are implemented, the remedies negotiated with the Commission will not affect Eni’s contractual gas transport rights. Management expects that a possible divestiture will occur as early as at the beginning of 2011 and as such the profit and loss for the year 2010 will report the full-year results of Eni’s share of profit in those entities. For further details on the matter see “Item 8 – Legal Proceedings”.

Management intends to divest a stake in its fully-consolidated subsidiary GreenStream where the Company currently owns a 75% stake. Following the intended divestment, the Company expects to account for the entity in accordance with the equity-method of accounting.

The Company’s Annual General Shareholders Meeting scheduled on April 29, 2010, is due to approve the full year dividend proposal. Eni expects to pay the balance of the dividend for fiscal year 2009 amounting to euro 0.50 per share in May. Total cash out is estimated at euro 1.81 billion.

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Management’s Expectations of Operations

In what remains an uncertain energy environment, management forecasts a modest improvement in global oil demand and a Brent price of 76 $/BBL in 2010. Gas demand in Europe and Italy is expected to recover gradually from the steep decline suffered in 2009, which mainly impacted the industrial and power generation sectors at a time when new import capacity was coming on line. The Company faces a challenging refining environment, and does not expect any significant recovery in industry fundamentals which will entail prolonged weakness in refinery margins. Against this backdrop, management expectations about the main trends in the Company’s businesses for 2010 and beyond are disclosed below.

 

Exploration & Production

•

Production of liquids and natural gas in 2010 is forecast to achieve a level slightly higher than in 2009, when production was 1.716 mmBOE/d, assuming the Company’s scenario for Brent price of 76 $/BBL for the full year 2010, the same level of OPEC restrictions as in the first quarter of 2010 and asset disposals underway. Growth will be driven by continuing field start-ups, mainly in Congo, Norway and marginally the Zubair project in Iraq, and production ramp-up at the Company’s recently started fields, mainly in Nigeria, Angola and the USA. These additions are expected to be partly offset by mature field declines. According to management’s plans, production growth will strengthen in the coming years as the Company is targeting a production level in excess of 2 mmBOE/d by 2013, implying an annual growth rate of more than 2.5% in the 2010-2013 period under management’s assumptions for oil prices at 65 $/BBL flat in the 2011-2013 period. Those oil price assumptions are particularly significant when it comes to assess 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 a $1 increase in oil prices compared to Eni’s assumptions for oil prices at 65 $/BBL. However, this sensitivity analysis only applies to small deviations from the 65 $/BBL scenario and the impact on Eni’s production increases more than proportionally as the deviation increases. This sensitivity analysis relates to the existing Eni portfolio and might vary in the future. Our production forecast also takes into account the rescheduling of certain projects designed to develop additional gas reserves in the light of current uncertainties about gas demand outlook in Europe. Management expects that a number of factors will drive cost increases in Exploration & Production operations over the future years. Those factors include: (i) the growing complexity of development projects, as a number of planned new developments will be executed offshore or in remote/hostile environment; (ii) the intense investing activity that is required to maintain the production plateau at existing fields and to counteract natural depletion rate; and (iii) steady trends in costs for purchasing upstream goods and services. Due to those trends, operating costs and depreciation and amortization charges might trend higher in future years. Management plans to offset those negative factors by leveraging on the Company’s exposure to long-life fields where it plans to achieve substantial cost economies due to scale of operations and the growing exposure to operated projects. Project operatorship enables the Company to exercise more tight control over project execution, expenditures and achievement of project milestones and time schedule.

 

Gas & Power

•

In 2010, natural gas sales are expected to slightly decrease compared to 2009 (approximately 104 BCM were achieved in 2009). Increasing competitive pressures, mainly in Italy, should be partly offset by an expected recovery in European gas demand. Other positive trends include a benefit associated with integrating Distrigas operations and optimization of the supply portfolio, including re-negotiation of long-term supply contracts. Management expects 2010 to be the most challenging year in the 2010-2013 plan periods, as a result of: (i) the circumstance that European gas demand is seen in its early stage of recovery; and (ii) the situation of oversupply on both the European and Italian markets which is expected to persist for some time due to import capacity expansion and large availability of LNG on the marketplace. Spot prices are expected to remain at depressed levels for the next one to two years and below the oil-linked prices provided in long-term contractual formulas which are the prices payable by the Company in its gas long-term supplies. In addition, the indexation mechanism for sale to residential customers in Italy, of which Company’s results benefited in 2009, is expected to reverse its impact in 2010. Based on these market trends and developments, management does not expect gas market to recover to 2008 levels until 2013 when demand growth is anticipated to strengthen and LNG availability on the marketplace is expected to be absorbed by growth in energy requirements on Asian markets. In spite of a challenging outlook, management plans to drive volumes growth in the years subsequent to 2010. Volumes growth is expected to be supported by the impacts associated with recent renegotiations of long-term supply contracts which are expected to add price competitiveness to the company’s portfolio. In addition the

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		Company intends to leverage its multiple presence in key European markets, particularly in France, Benelux and Germany (see “Item 4 – Gas & Power”), integration with Distrigas’ operations and development of a direct sales force. Based on those actions, Eni’s worldwide gas sales are projected to reach 118 BCM by 2013, implying an annual growth rate higher than 3% in the 2010-2013 period. Management intends to implement a number of marketing actions designed to support the Company’s selling margins on both the European and Italian markets in spite of rising competitive pressures. Specifically, management intends to preserve profitability of the Company’s gas operations in Italy by focusing on the most profitable customer segments. The Company intends to deploy tailored marketing policies to retain and develop its main customers throughout all market segments. These policies include the offer of pricing formulae and services that are designed to best suit the customers’ needs. Also the Company intends to leverage on the development of the combined offer of gas and electricity (so-called dual offer) to drive sales to both business and residential customers. In the European markets, the Company plans to achieve cost efficiencies by integrating Distrigas’ operations and optimizing logistics. Streamlining business support activities and reducing marketing and general and administrative costs will also drive margin improvements. Considering that current imbalances between demand and supply on the European market are expected to continue for some time, management factored in its planning assumptions the risk that the Company may fail to fulfill its contractual obligations associated with the Company’s long-term supply contracts to off-take minimum annual quantities for significant amounts in the next two years. However, in light of the management assumptions for long-term growth in gas demand, those volumes are planned to be off-taken in subsequent years. For more information see the specific risk paragraph in “Item 3 – Risk Factors”. For a discussion of certain risks relating to the impact of the evolution of Italian regulation of the natural gas sector on Eni’s take-or-pay contracts see “Item 3 – Risk Factors – Natural Gas Market”.
•		Regulated businesses in Italy are planned to benefit from the pre-set, regulatory return on new capital expenditures and cost savings from integrating the whole chain of transport, storage and distribution activities.

 

Refining & Marketing

•		Refining margins are expected to remain at an unprofitable level in 2010 as weak industry fundamentals are expected to persist in the near future. Specifically, high feedstock costs, weak demand, excess inventory levels and compressed differentials between heavy and light crudes will continue squeezing margins on products. Refining throughputs on Eni’s account are planned to be in line with 2009 (actual throughputs in 2009 were 34.55 mmtonnes). Volumes processed at wholly-owned refineries are expected to increase, resulting in a higher capacity utilization rate, due to a reduction in volumes on third party refineries reflecting the Company’s decision to terminate certain processing agreements. Efficiency improvement actions are expected to partly offset an unfavorable trading environment.
		Retail sales of refined products in Italy and the rest of Europe are expected to be unchanged from 2009 (12.02 mmtonnes in 2009) reflecting weak demand. New marketing initiatives are planned in order to strengthen Eni’s leadership on the Italian retail market and to develop its market share in European markets.

 

Engineering & Construction

•

The Engineering & Construction business is expected to see solid results due to a robust order backlog. The segment is expected to leverage its diversified business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. The start of operations of new advanced assets in 2010 and 2011 coupled with the size and quality of the backlog and management focus on execution, underpin expectations for a further strengthening of Saipem’s competitive position in the medium-term.

 

Petrochemicals

•

Management expects that results in the Petrochemicals segment will continue being negatively affected by sluggish demand, high costs for oil-based feedstock and competitive pressures. However, management believes that there are signs that demand for the main commodities has bottomed-up. Management plans to implement a number of initiatives designed to reduce fixed operating expenses and to realign the industrial set-up of Eni’s petrochemical operations with a view of enhancing areas of competitive advantage.

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Capital Expenditure plans

Over the next four years, the Company plans to invest euro 52.8 billion in its businesses to support continued organic growth; approximately 71%, 16%, 6% and 5% of planned capital expenditures is expected 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 oil and gas reserves mainly in Iraq, Norway, Kazakhstan, Italy, Algeria, Congo, Angola, and the U.S.; (ii) exploration projects to be executed mainly in the U.S., Libya, Angola, Nigeria, Norway, Egypt, Congo and Indonesia; (iii) upgrading of national pipelines for transporting natural gas, as well as upgrading of Italian distribution networks and gas storage capacity; (iv) development of gas marketing activities in Europe; (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 is expected to increase by approximately euro 4 billion, up 8% compared to the previous industrial plan that was approved in February 2009 when the trading environment was particularly depressed. The main drivers which explain the increase are: (i) planned expenditures for developing new upstream projects, particularly those associated with reserves development in Iraq, Venezuela and certain fields offshore Angola. Management expects that those projects will contribute to production growth beyond the plan horizon; and (ii) the circumstance that the Company is forecasting steady trends in costs for materials and sector specific services which have fallen far less than what management had anticipated due to the fast recovery in international oil prices. Costs for specialized services, equipment and other goods for the oil industry have remained substantially unaffected by the global downturn. As a result management has revised the assumptions made in 2009 that pointed to a reduction in those costs over the medium term. That trend is expected to be partly offset by the positive impact associated with the Company’s assumptions of a depreciation of the U.S. dollar over the euro compared to exchange rate assumptions made in the previous plan as upstream investment costs are mainly incurred in U.S. dollars. Also the re-scheduling of certain gas projects due to current uncertainties of the global gas market is expected to partly offset increasing trends.

For the year 2010, management plans to make capital expenditures of euro 14 billion which is broadly in line with 2009 (euro 13.69 billion were invested in 2009), of which euro 10.5 billion are planned in the Exploration & Production segment. Capital projects are mainly planned for developing oil and natural gas reserves, exploration projects, upgrading construction vessels and rigs, and upgrading natural gas transport and distribution infrastructures.

Management expects to pursue strict capital discipline when assessing individual capital projects. Management assumed a long-term reference oil price of 65 $/BBL from 2013 onwards 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 taking into account: (i) the weighted average cost of capital to the Group. In 2009 management assessed that the cost of capital to the Group increased by 0.5 percentage points on average from the previous year as a result of a higher market premium for the equity risk and the country risk. Such increases were partially reduced by decreased nominal interest rates reflected in the cost of borrowings and in rates of risk-free assets; (ii) a country risk premium which reflects the specific level of risk associated with each country of operations in terms of macroeconomic, business and socio-political current conditions and outlook; and (iii) a premium for the business risk.

 

Liquidity and leverage

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. For planning purposes, management calculated the Company’s expected cash flows assuming a scenario of Brent prices at 65 $/BBL for the years 2010-2013 to assess the financial compatibility of its capital expenditures programs and dividend policy with internal targets of ratio of total equity to net borrowing. We note that Brent price in the period January 1 to March 31, 2010 was 76.24 $/BBL and it was 84.41 $/BBL in the period April 1-April 21, 2010.

Management plans for achieving a ratio of net borrowings to total equity (“leverage”) in 2010 in line with 2009, while going forward management intends to seek to progressively reduce this ratio to below 40%.

For planning purposes, management assumed an average exchange rate of approximately 1.36 U.S. dollars per euro in the 2010-2013 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”.

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Dividend policy

In the next four-year period management intends to pursue a progressive dividend policy. Management intends to pay a euro 1.00 a share dividend for 2010, and thereafter growing the dividend in line with OECD inflation. This dividend policy is based on management’s planning assumptions for oil prices at 65 $/BBL flat in the 2010-2013 period. If management assumptions on oil prices were to change, management may rebase the dividend. For fiscal year 2009, subject to approval at the General Shareholders’ Meeting, Eni is paying a dividend per share of euro 1.00, of which euro 0.50 per share was paid in September 2009 as an interim dividend with the balance of euro 0.50 per share expected to be paid late in May 2010. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full year dividend paid in the following year.

The expectations described above are subject to risks, uncertainties and assumptions associated with the oil and gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, crude oil and natural gas prices; demand for oil and gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to “Item 3 – Risk Factors”.

 

Off-Balance Sheet Arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in Note 28 to the Consolidated Financial Statements. Eni’s principal contractual obligations, including commitments under take-or-pay or ship-or-pay contracts in the gas business, are described under "Contractual Obligations" below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses.

Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the company’s financial condition, results of operations, liquidity or capital resources.

Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in Note 28 to the Consolidated Financial Statements.

 

 

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Contractual Obligations

Amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

	Maturity year

	Total		2010		2011		2012		2013		2014		2015 and thereafter

(euro million)

Total debt		26,979		8,107		1,859		3,793		2,013		2,501		8,706
Long-term finance debt		21,255		3,191		1,342		3,660		1,967		2,487		8,608
Short-term finance debt		3,545		3,545
Fair value of derivative instruments		2,179		1,371		517		133		46		14		98
Interest on finance debt		3,864		654		570		545		510		426		1,159
Guarantees to banks		377		377
Noncancelable operating lease obligations (1)		4,255		886		889		561		470		415		1,034
Decommissioning liabilities (2)		11,327		79		55		112		161		1,640		9,280
Environmental liabilities		1,903		293		259		257		214		193		687
Purchase obligations (3)		248,092		14,845		14,151		13,923		14,634		14,651		175,888
Natural gas to be purchased in connection with take-or-pay contracts (4)		237,407		13,986		13,365		13,123		13,827		13,838		169,268
Natural gas to be transported in connection with ship-or-pay contracts (4)		6,413		546		538		545		559		567		3,658
Other take-or-pay and ship-or-pay obligations		1,787		162		154		139		133		131		1,068
Other purchase obligations (5)		2,485		151		94		116		115		115		1,894
Other obligations (6)		186		21		4		3		3		3		152
of which:
- Memorandum of intent relating to Val d’Agri		186		21		4		3		3		3		152
TOTAL		296,983		25,262		17,787		19,194		18,005		19,829		196,906

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(1)		Operating leases primarily regarded assets for drilling activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(2)		Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3)		Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(4)		Such arrangements include non-cancellable, 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)		Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S.
(6)		In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans (see Note 22 to the Consolidated Financial Statements).

The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment as of December 31, 2009. 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		2010		2011		2012		2013		2014 and thereafter

Committed on major projects		24,026		4,119		3,793		2,829		1,928		11,357
Other committed projects		29,210		9,330		5,284		3,467		3,640		7,489
TOTAL		53,236		13,449		9,077		6,296		5,568		18,846

 

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 resulting in the Group’s inability to meet short-term finance

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requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. For a description of how the Company manages the liquidity risk see Note 28 to the Consolidated Financial Statements.

As of December 31, 2009, Eni maintained short term committed and uncommitted unused borrowing facilities of euro 11,774 million, of which euro 2,241 million were committed, and long term committed unused borrowing facilities of euro 2,850 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 15 billion, of which euro 9,211 million were drawn as of December 31, 2009.

The Group has debt ratings of AA- and A-1+ assigned by Standard & Poor’s and Aa2 and P-1 assigned by Moody’s respectively for long and short-term debt. The outlook is negative in both ratings.

A security rating 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. Credit risks arise from both commercial partners and financial ones. Although the Group has not experienced in the past 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. In 2009 consolidated financial statements we made a further allowance for doubtful accounts amounting to euro 260 million, mainly relating to the Gas & Power business.

 

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 2009, see "Item 4 – Research and Development".

 

 

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Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

The following lists the Company’s Board of Directors as at April 2010:

Name		Position		Year elected or appointed		Age
Roberto Poli		Chairman		2002		72
Paolo Scaroni		CEO		2005		64
Alberto Clô		Director		1999		63
Paolo Andrea Colombo		Director		2008		50
Paolo Marchioni		Director		2008		41
Marco Reboa		Director		2005		55
Mario Resca		Director		2002		65
Pierluigi Scibetta		Director		2005		51
Francesco Taranto		Director		2008		70

In accordance with Article 17.3 of Eni’s By-Laws, the Board of Directors is made up of 3 to 9 members. The current Board of Directors was elected by the ordinary Shareholders’ Meeting held June 10, 2008, which also established the number of Directors at nine for a term of three financial years.

Roberto Poli, Paolo Scaroni, Paolo Andrea Colombo, Paolo Marchioni, Mario Resca and Pierluigi Scibetta were candidates included in the list of the Ministry of the economy and finance. Alberto Clô, Marco Reboa and Francesco Taranto were elected on the basis of the list submitted by the institutional investors.

On the basis of Italian laws regulating the special powers of the State (see "Item 10 – Stock ownership limitation and voting rights restrictions"), the Minister of 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 of economy and finance opted not to exercise that power.

Roberto Poli Born in 1938. Chairman of Eni SpA since May 2002. Holds the post of Chairman of Poli e Associati SpA, a consultancy company in the fields of corporate finance, extraordinary operations, company acquisitions and restructuring plans. He is a Director of Mondadori SpA, Fininvest SpA, Coesia SpA, Maire Tecnimont SpA and Perennius Capital Partners SGR SpA. Between 1966 and 1998, he lectured in corporate finance at Università Cattolica del Sacro Cuore, in Milan. He has worked as extraordinary operations advisor for some of Italy’s largest industrial groups. He was Chairman of Rizzoli-Corriere della Sera SpA and Publitalia SpA.

Paolo Scaroni Born in 1946. Chief Executive Officer of Eni SpA since June 2005. Graduated in Economics and Business in 1969 at Bocconi University, Milan. He had initial work experience at Chevron for three years, gained a Master’s Degree in Business Administration from Columbia University, New York, and continued his career at McKinsey. In 1973, he joined the Saint Gobain Group, where he performed numerous managerial tasks in Italy and overseas until he was appointed President of the Glass Division in Paris in 1984. Between 1985 and 1996, he was Vice President and CEO of Techint and managed the privatizations of the subsidiaries SIV, Italimpianti and Dalmine. In 1996, he moved to the UK and joined Pilkington, working as CEO until May 2002. Between May 2002 and May 2005, he was CEO and General Manager of Enel. Between 2005 and July 2006 he was Chairman of Alliance Unichem (UK). In November 2007, he was honored by France as an Officer of the Legion of Honour. Currently he is Director of Assicurazioni Generali SpA, LSEG Plc (London Stock Exchange Group), Veolia Environnement (Paris), Board of Overseers of Columbia Business School, New York, and Director of the Teatro alla Scala Foundation.

Alberto Clô Born in 1947. Director of Eni SpA since June 1999. Graduated in Political Sciences at the University of Bologna. Lecturer in Industrial Economics and Public Service Economics at the University of Bologna. In 1980, he founded the journal "Energia", of which he is editor. Author of books and over 100 essays and Articles on the problems of the industrial economy and energy. Contributor to various daily newspapers and financial journals. Between 1995 and 1996 he was Minister of Industry and ad interim Minister of Foreign Trade and President of the Council of Industry and Energy Ministers of the European Union during the six-month Italian presidency. In 1996, he received the honor of "Cavaliere di Gran Croce" of the Republic of Italy. Currently he is Director of Atlantia SpA, Italcementi SpA and De Longhi SpA.

Paolo Andrea Colombo Born in 1960. Director of Eni SpA since June 2008. Graduated in Business Administration in 1984 at the Bocconi University, Milan. Qualified as a professional accountant in 1985 and Auditor. Lecturer in the Accounting Department of the Bocconi University, Milan. Founding partner of Borghesi

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Colombo & Associati, a specialized consultancy firm on corporate finance operations – including taxation and business consultancy in the context of extraordinary operations – as well as strategic and corporate governance consultancy. Between May 2002 and May 2005, he worked as Effective Statutory Auditor of Eni SpA. Between May 2005 and May 2008, he was Chairman of the Board of Statutory Auditors. Currently he is Director of Mediaset SpA, Ceresio SIM SpA and Versace SpA, Chairman of the Board of Statutory Auditors of Aviva Vita SpA and Interbanca SpA, Statutory Auditor of Sirti SpA, A. Moratti Sapa, Humanitas Mirasole SpA, Credit Agricole Assicurazioni Italia SpA and Iniziativa Gestione Investimenti SGR SpA.

Paolo Marchioni Born in 1969. Director of Eni SpA since June 2008. Lawyer specialized in criminal and administrative law, counsel for defense in the Italian Supreme Court and superior jurisdictions. Advisor of public organizations, and commercial companies in matters of commercial, corporate, administrative and local government law. Mayor of the town of Baveno (VB) between April 1995 and June 2004. President of the Assembly of Mayors of Con.Ser.Vco between September 1995 and June 1999 and member of the Assembly of Mayors of ASL14, the management committee of the Verbano Health District, the Assembly of Mayors of the Waste Water Consortium of the Val d’Ossola and the Assembly of Mayors of the Social Services Consortium of Verbano until June 2004. Councilor of the Municipality of Stresa (VB) between April 2005 and January 2008. Between October 2001 and April 2004, he was a Director of C.i.m. SpA, Novara (Goods Interport Centre) and, between December 2002 and December 2005, Director and member of the Executive Committee of Finpiemonte SpA. Between June 2005 and June 2008 he was a Director of Consip. Since June 2009, he has been Vice-President of the Province of Verbano-Cusio-Ossola and provincial councillor responsible for budgeting, property, legal affairs and production activities.

Marco Reboa Born in 1955. Director of Eni SpA since May 2005. Graduated in Business Administration at the Bocconi University, Milan. Professional Accountant and Auditor. Professor at the Faculty of Law of the Carlo Cattaneo University – LIUC – Castellanza, and author of numerous publications regarding corporate governance, economic assessment and budgeting. Works in Milan and is editor of the Rivista dei Dottori Commercialisti, an accountancy journal. Currently he is Director of Luxottica Group SpA and Interpump Group SpA. Chairman of the Board of Statutory Auditors of Mediobanca SpA, Auditor of Gruppo Lactalis Italia SpA, Egidio Galbani SpA and Big Srl.

Mario Resca Born in 1945. Director of Eni SpA since May 2002. Graduated in Economics and Business at the Bocconi University, Milan. Hired after graduating by Chase Manhattan Bank, in 1974 he was appointed Manager of Saifi Finanziaria (Fiat Group) and between 1976 and 1991 he was a partner in Egon Zehnder. During this period he served as a Director of Lancôme Italia, companies in the RCS Corriere della Sera Group and the Versace Group. Between 1995 and 2007, he was Chairman and CEO of McDonald’s Italia. He has also been Chairman of Sambonet SpA, Kenwood Italia SpA, founding partner of Eric Salmon & Partners and President of the American Chamber of Commerce. In June 2002, he received the honor of Cavaliere del Lavoro. In 2008, he was appointed by the government as General Director for the enhancement of Italian museums within the Italian Ministry for Cultural Heritage and Activities. Currently he is Chairman of Confimprese and Finbieticola Casei Gerola SpA, and Director of Mondadori SpA.

Pierluigi Scibetta Born in 1959. Director of Eni SpA since May 2005. Graduated in Economics and Business at La Sapienza University, Rome. Professional Accountant and Auditor, he has practiced at his own studio in Rome since 1990. He was Director of Gestore del Mercato Elettrico (GME) SpA, Istituto Superiore per la Previdenza e la sicurezza del lavoro (I.S.P.E.S.L.), Nucleco SpA, FN SpA and Agenzia per l’innovazione tecnologica (AGITEC) SpA, as well as a former Deputy Extraordinary Commissioner and Director of Ente per le Nuove Tecnologie, l’Energia e l’Ambiente (ENEA) and Effective Statutory Auditor of Consorzio smantellamento impianti del ciclo del combustibile nucleare.

Francesco Taranto Born in 1940. Director of Eni SpA since June 2008. Began his career in Milan, in 1959, at the offices of an exchange broker, subsequently working for Banco di Napoli between 1965 and 1982, where he held the post of deputy manager for the stock exchange and securities department. He has held numerous management posts in the asset management field, particularly as Director of securities funds at Eurogest, between 1982 and 1984, and General Director of Interbancaria Gestioni between 1984 and 1987. After moving to the Prime Group (1987-2000) he held the post of CEO of the parent company for many years. He is also a member of the steering council of Assogestioni and of the corporate governance committee for listed companies set up by Borsa Italiana. He was a Director of Enel between October 2000 and June 2008. Currently he is Director of Cassa di Risparmio di Firenze SpA, Pioneer Global Asset Management SpA (Gruppo Unicredito) and Kedrios SpA.

 

Senior Management

The table below sets forth the composition of Eni’s Senior Management. It includes the CEO, as General Manager of Eni SpA, the Chief Operating Officers, the Chief Financial Officer, the Chief Corporate Operations Officer and the Executives who directly report to the CEO (Senior Executive Vice Presidents of the Company).

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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		5		64
Claudio Descalzi		Exploration & Production Chief Operating Officer		2008		29		55
Domenico Dispenza		Gas & Power Chief Operating Officer		2005		36		64
Angelo Caridi (*)		Refining & Marketing Chief Operating Officer		2007		40		63
Alessandro Bernini		Chief Financial Officer		2008		14		50
Salvatore Sardo		Chief Corporate Operations Officer		2005		5		58
Massimo Mantovani		General Counsel Legal Affairs Senior Executive Vice President		2006		17		47
Rita Marino		Internal Audit Senior Executive Vice President		2008		5		46
Leonardo Maugeri (*)		Strategies and Development Senior Executive Vice President		2000		15		45
Stefano Lucchini		Public Affairs and Communication Senior Executive Vice President		2005		5		48
Roberto Ulissi		Company Secretary Corporate Affairs and Governance Senior Executive Vice President		2006		4		48
Raffaella Leone		Executive Assistant to the CEO		2005		5		48

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(*)

Until March 2010.

The Chief Operating Officers, the Chief Financial Officer, the Chief Corporate Operations Officer and the Senior Executive Vice Presidents are permanent members of the Management Committee, which advises and supports the CEO. 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, except for the Senior Executive Vice President of Internal Audit Department and the company Secretary, who are appointed by the Board of Directors.

 

Senior Managers

Claudio Descalzi Born in 1955. Chief Operating Officer of the Exploration & Production Division since July 2008. Graduated in Physics in 1979 at the University of Milan, attended specialist courses in Petroleum Engineering in France and USA. He joined Eni Group in 1981 as oil/gas field petroleum Engineering and Project Manager, following the development of North Sea, Libya, Nigeria, and Congo fields. In 1990 he was appointed head of operational activities for Italy. In 1994 he was named Director of Agip Recherches Congo, with responsibility for all local upstream operations, and in 1998 become Vice Chairman & Managing Director of Naoc, an Eni subsidiary in Nigeria. From 2000 to 2001 he was Regional Manager for Africa, Middle East and China at the Agip Division, where in 2002 he was appointed Country Manager for Italy. From 2002 to 2005 he was Regional Manager for Italy, Africa, Middle East at the Eni Exploration & Production Division, and in 2006 he has been named Deputy Chief Operating Officer of the Eni Exploration & Production Division. Since 2006 he has been President of Assomineraria. He is Vice President of Confindustria Energy.

Domenico Dispenza Born in 1946. Chief Operating Officer of Eni’s Gas & Power Division since January 2006. Graduated in Aeronautical Engineering at the "Politecnico di Milano" University, in 1973 he completed a Master’s degree in Advanced Technology at Sogesta in Urbino. He began working in 1974 at the Study Department of Snam SpA, in 1977 he became head of Systems Analysis and from 1980 to 1991 he was Chief Negotiator for Gas Sales and Purchase Agreement. From 1991 to 1999 he was Director Gas Supplies. On June 30, 1999 he was appointed Managing Director of Snam SpA. From 2002 to 2004 he was Deputy COO of Eni’s Gas & Power Division. On April 27, 2004 he was nominated Chairman and CEO of Snam Rete Gas.

Angelo Caridi Born in 1947. Chief Operating Officer of Eni SpA - Refining & Marketing Division since August 2007⁹. Graduated in Civil Engineering at the "Politecnico di Torino" University. He joined Snamprogetti in

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1970 and he was the Manager of the Civil Engineering department in Rome from 1978 until 1984. After four years’ experience as Manager of the Civil Engineering Division, he was appointed Manager of Environmental Impact Assessment Business Unit and, in 1990, Marketing Manager of Infrastructures Division in Italy. In 1991 he became Director of the Rome engineering centre. He was then appointed Chairman and Managing Director of Aquater and Chairman of CEPAV Uno Consortium, in 1993. In 2001 he was also appointed Director of the Infrastructures Division. In 2002 was appointed Managing Director of Snamprogetti and in July 2005 Chief Executive Officer. He is non-executive Director of Saipem SpA – a company listed on Borsa Italiana SpA (the Italian Stock Exchange) – since 2006.

Alessandro Bernini Born in 1960. Chief Financial Officer of Eni since August 2008. Started his career in 1979 at Neutra Revisioni Sas, in Milan, first as Junior Accountant in the Auditing Activities Department then as Accountant in Charge. In 1981, he joined Ernst & Young thereafter becoming Senior, Supervisor and Manager. In 1995 he was appointed Partner of the Company and Chartered Accountant Manager for the Areas of Piacenza, Parma and Cremona and Technical Manager for the branch based in Brescia. In the same period he was also engaged as Lecturer for post graduate Master Degree courses in the Universities of Pavia and Parma. In 1996 he joined Eni Group as Administration Department Manager of Saipem SpA. In 2006 was appointed Group Chief Financial Officer of Saipem SpA. He has covered executive managerial roles in many important companies of the Saipem Group.

Massimo Mantovani Born in 1963. Senior Executive Vice President of Legal Affair Department of Eni SpA since 2005. Graduated in Law and achieved a Master in Law (LLM) at the University of London. He is registered to practice law in Italy and in England. For around 5 years he worked for a number of law firms in Milan and London before joining the legal department of Snam SpA in 1993. He was responsible of legal affairs of Eni’s Gas & Power Division. Since 2005 he has been a member of the Board of Directors of Snam Rete Gas SpA and is a member of the Eni Watch Structure.

Rita Marino Born in 1964. Chief Internal Auditor since July 2005 and Senior Executive Vice President of the Internal Control System since March 2007. Graduated in Economics and Business in 1987 at LUISS University in Rome, she worked in Stet and then in Telecom Italia 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 as well as Head of the 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 is currently member of Eni Watch Structure and Secretary of Eni Internal Control Committee.

Stefano Lucchini Born in 1962. Senior Executive Vice President of Public Affairs and Corporate Communication since July 2005. Graduated in Economics at LUISS University in Rome. He started in the research department at Montedison. After a period as assistant to the President of the Energy and Commerce Commission of the U.S. Congress in Washington D.C., he was Director of communications at Montedison USA in New York. Returning to Italy in 1993, he was responsible for financial communications and investor relations for the Gruppo Ferruzzi Montedison. He joined Enel in 1997, initially in financial communications and subsequently as the group’s head of external relations. He has also been the head of external relations for Confindustria. In June 2002 he was appointed head of external relations for the Banca Intesa Group. He teaches at the Advanced School of Journalism at Università Cattolica in Milan, and is a member of its evaluation committee. He has been a member of the Board of Directors of AGI since 2005. He is also Commendatore della Repubblica Italiana and a Silver Medalist of Croce Rossa Italiana. Since 2007 he has been a member of the supervisory board of Confindustria and the executive board of UPA. He is also a member of the boards of Censis, the Fondazione Eni Enrico Mattei (FEEM) and the Eni Foundation.

Leonardo Maugeri Born in 1964. Senior Executive Vice President of Strategy and Development since 2000¹⁰. He has two degrees and a research doctorate, after extensive academic experience acquired in Italy and abroad. Joined Eni Group in 1994, holding various positions mainly as counsel for strategic decisions 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 Centre 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 Born in 1952. Chief Corporate Operations Officer of Eni SpA since November 2008. Graduated in Economics at University of Torino. From 1976 to 1981 at Coopers & Lybrand as auditor, reaching the position of Supervisor. From 1981 at Stet, head of management control for manufacturing. Co-Central Director in 1991 and Central Director for Planning and Control. Nominated in 1997 Deputy General Manager for Finance and Control at Telecom Italia. From 1998 to June 2001, President of Seat Pagine Gialle SpA. From 1999 Operational

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Head of Comparto Immobiliare di Gruppo. President of EMSA, President and Managing Director of EMSA Servizi and President and Managing Director of IMMSI, as well as Executive President of TELIMM, IMSER and Telemaco. From 2001 Head of the Real Estate and General Services business unit at Telecom Italia. From 2003 head of Procurement, Services and Security of Enel Group. From 2005 Director of Human Resources and Business Services at Eni SpA, also assuring guidance and control of the Information & Communication Technology Unit and the company EniServizi.

Roberto Ulissi Born in 1962. Senior Executive Vice President Corporate Affairs and Governance since 2006. He is a lawyer. After a number years spent as lawyer at the Bank of Italy, in 1998 he was nominated General Manager at the Ministry of the Economy and Finance, head of the "Banking and Finance System and Legal Affairs Department". He was a Director of Telecom Italia, Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Supreme Council of the Bank of Italy. He was also a member of numerous Italian and European Commissions representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law and, at 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 was also special professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana 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.

Raffaella Leone Executive Assistant to the CEO of Eni since 2005. She is President of Servizi Aerei SpA, Vice President of Eni Foundation, member of the Board of Directors of the news agency AGI (Agenzia Giornalistica Italia) and of the Board of Directors of the Fondazione Eni Enrico Mattei. Previously she was the Executive Assistant to the CEOs of Enel (from May 2002 to 2005) and of Pilkington (from 1996 to May 2002).

 

 

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 2008, Eni rated fourth and in 2009 a bonus of euro 40,000 was 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 2009, based on 2008 Eni’s results, a bonus equal to 120% 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 2009, this bonus amounted to euro 360,000.

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.

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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;
(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 2008, said targets included a set level of adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) (with a 40% weight), divisional operating performances (30%), reduction of Company’s costs (20%) and maintaining of ranking within certain sustainability indexes (10%). 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 for the period from January 1 to June 10, 2008 respectively to 77% and 100% and for the period from June 11 to December 31, 2008 respectively to 110% and 155% of the fixed amount under a) above. In 2009, based on 2008 Eni’s results, a bonus equal to 120% of the target level was determined, within an interval ranging from 85% to 130% and a bonus of euro 1,699,000 was paid;
(c)		a long-term incentive under the incentive scheme as approved by the Board of Directors on March 25, 2009 as proposed by the Compensation Committee. This incentive scheme provides a deferred monetary incentive with a target level corresponding to 55% of the fixed amount under a) above. The bonus will vest over the next three years upon achievement of certain preset Company annual targets in terms of EBITDA for the reference three-year period. Vested amounts will range from 0 to 170% of the award. The 2009 bonus that was awarded to the CEO amounted to euro 786,500. Taking into account that on the same occasion, the Board of Directors decided to discontinue the stock option plan, based on the resolution of the Compensation Committee, and in force of the contractual obligation to the CEO of adopting an alternative incentive scheme with same economic effects, in order to replace and compensate for the discontinued stock option incentive the CEO was awarded a further deferred monetary bonus whose value and characteristics are comparable with those of the former plan. The bonus will vest over the next three years upon achievement of certain performance targets in terms of variation of the Adjusted Net Profit + DD&A (Depletion Depreciation & Amortization) as compared to that of the other six largest international oil companies for market capitalization for the reference three-year period. The 2009 bonus that was awarded to the CEO amounted to euro 2,716,391 and will be paid in 2012 according to a percentage ranging from 0 to 130% of the awarded amount in relation to the performance achieved in the reference three-year period.
		In 2009, the 2006 long-term incentive scheme approved in March 2006 by the Board of Directors as proposed by the Compensation Committee vested. This incentive scheme provided: (i) a deferred monetary incentive, linked to the achievement of certain Company’s financial performance annual targets in terms of EBITDA; and (ii) a stock option awards which vested upon achievement of certain performance targets of the Eni share measured in terms of Total Shareholder Return (TSR) that considers both the stock appreciation and the dividend, as compared to that achieved by the other six largest international oil companies for market capitalization over the three-year vesting period. Under this scheme, based on results achieved in the 2006-2008 three-year period, the CEO received:

	(i)		an amount equal to 143% of the deferred monetary incentive that was granted in 2006 with a target level corresponding to 55% of the fixed amount under a) above. In 2006, this award was accrued for euro 786,500; and
	(ii)		an award of stock options corresponding to 47% of options granted in 2006 (681,000 rights with a strike price of euro 23.1 per share corresponding to the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the grant);

(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-

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		retirement benefit computations applied to the CEO annual emolument and 50% of the maximum bonuses earned as a Director. A provision of euro 244,435.07 was accrued in 2009;
(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 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 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 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. No bonus is paid in case Eni scores a position lower than the fourth one. In 2008, Eni rated fourth and in 2009 a bonus of euro 10,000 was 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)		a long-term incentives in the form of a deferred monetary bonus linked to the achievement of certain Company’s financial performance annual targets in terms of EBITDA, according to the same scheme as

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		the CEO. Under this scheme the three General Managers have received in 2009 a yearly award of the deferred monetary bonus of 47% of the base salary. The Board of Directors on March 25, 2009 as proposed by the Compensation Committee resolved to discontinue the stock option plan;
(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; 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.

Remuneration earned for 2009 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.

Name

Position

Emoluments for service at Eni SpA

Non-cash benefits

Bonus and other incentives (a)

Salaries and other elements

Total

	(euro thousand)

Board of Directors
Roberto Poli		Chairman		765				400				1,165
Paolo Scaroni		CEO		430		1		2,824		1,017		4,272
Alberto Clô		Director		162				10				172
Paolo Andrea Colombo		Director		96				10				106
Paolo Marchioni		Director		107				10				117
Marco Reboa		Director		163				10				173
Mario Resca		Director		162				10				172
Pierluigi Scibetta		Director		96				10				106
Francesco Taranto		Director		153				10				163
Board of Statutory Auditors
Ugo Marinelli		Chairman		121								121
Roberto Ferranti (b)		Auditor		84								84
Luigi Mandolesi		Auditor		84								84
Tiziano Onesti (c)		Auditor		84						40		124
Giorgio Silva		Auditor		44								44
Divisional Chief Operating Officers
Claudio Descalzi		Exploration & Production				3		772		734		1,509
Domenico Dispenza		Gas & Power				1		1,002		745		1,748
Angelo Caridi		Refining & Marketing				2		648		642		1,292
Other managers with strategic responsibilities (d)						15		4,179		4,266		8,460
				2,551		22		9,895		7,444		19,912

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(a)		Based on the annual incentive plan related to performance achieved in 2008 (euro 6,283 thousand) and payment of the deferred monetary incentive granted in 2006 (euro 3,612 thousand).
(b)		Compensation for the service is paid to the Ministry for Economy and Finance.
(c)		Includes the compensation obtained as Chairman of the Board of Statutory Auditors of AGI and Servizi Aerei.
(d)		Managers who, during the year, have been members of Eni’s Management Committee with the CEO and the Divisional Chief Operating Officers, and Eni Senior Executive Vice Presidents who report directly to the CEO (8 managers).

The items provided in the table above report the following elements of compensation:

•

"Emoluments for service at Eni SpA" include emoluments paid to non-executive and executive directors for service rendered, fixed fees paid to Directors attending the Board’s Committees, and fees paid to Statutory Auditors. Emoluments earned by the Chairman and the CEO include also the portion awarded for the powers entrusted to them by the Board;

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•		"Non cash benefits" comprise amounts referring to all fringe benefits, including insurance policies;
•		"Bonuses and other incentives" include: (i) performance bonuses awarded in the year to Directors and the Chairman of the Board based on the performance of the Eni share; (ii) performance bonuses awarded in the year to both the Chairman and the CEO in connection with the power entrusted to them by the Board, based on the achievement of specific company targets; and (iii) performance bonuses awarded in the year to the CEO, in his position as General Manager of the parent company, the General Managers of Eni’s divisions and other managers with strategic responsibilities based on the achievement of specific financial, operational and strategic targets and of individual performance targets pertaining to their respective business or functional units; and
•		"Salaries and other elements" report base salaries paid to the CEO, the General Mangers of Eni’s Divisions and other managers with strategic responsibilities, and indemnities paid upon termination of the employment contract.

For the year ended December 31, 2009, 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 35 million and was accrued in Eni’s consolidated financial statements for the year ended December 31, 2009. The break-down is as follows:

	2009
	(euro million)

Fees and salaries		20
Post employment benefits		1
Other long-term benefits		10
Fair value stock grants/options		4
		35

The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay. As of December 31, 2009, the total amount accrued to the reserve for employee termination indemnities with respect to members of the Board of Directors who were also employees of Eni, the three divisional Chief Operating Officers and Eni’s senior managers was euro 1,621 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		167
Claudio Descalzi		Chief Operating Officer of the E&P Division		305
Domenico Dispenza		Chief Operating Officer of the G&P Division		426
Angelo Caridi		Chief Operating Officer of the R&M Division		150
Senior managers (a)				573
				1,621

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(a)

No. 8 managers.

 

Long-term Incentive Schemes

On March 25, 2009, the Board of Directors resolved to terminate the Eni Stock Option Plan for 2009 and to maintain the Deferred Monetary Incentive Plan for the three-year period 2009-2011. This Plan, which is aimed at all managerial resources and is focused on certain business growth and operating efficiency targets, provides for an incentive to be paid after a period of three years in an amount connected with the achievement of annual EBITDA objectives (actual results vs. budget, on a constant scenario basis) defined for the reference three-year period. See below for further details.

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In order to adopt an alternative incentive scheme to Stock Option Plan, the Compensation Committee defined a new long-term incentive plan for critical managerial resources that will be approved by the Board of Directors in 2010. In 2009 the Board of Directors approved a plan with similar characteristics for the CEO; this plan provides for an incentive to be paid after a period of three years in an amount connected with the variation of the adjusted net profit + DD&A (Depletion, Depreciation & Amortization), measured over the three-year period 2009-2011 in relative terms compared to the other six largest international oil companies for market capitalization.

In 2009, the vesting period of the long-term incentive plan assigned in 2006 expired. This plan consisted of a Deferred Monetary Incentive Plan, aimed at managerial resources, and a Stock Option Plan, aimed only at managerial resources holding positions that are more directly responsible for results and are of strategic interest. The Board of Directors, on March 25, 2009, based on the results achieved in 2006-2008, as verified by the Compensation Committee, resolved that: (i) with reference to the Deferred Monetary Incentive Plan, a multiplier of 143% should be applied to the amount awarded in 2006, calculated on the basis of the performance achieved in terms of Eni’s EBITDA; and (ii) with reference to the Stock Option Plan, a percentage of 47% of exercisable options, calculated on the basis of the performance achieved in terms of Eni’s relative TSR, should be applied to the total amount granted in 2006.

The CEO, in his quality of General Manager, participated in both Plans.

 

Deferred monetary bonus

The deferred bonus scheme approved for the 2009-2011 three-year period provides for the award of a basic monetary bonus to be paid after three years from grant 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. The following table sets out the basic bonus awarded in the year 2009 to the CEO and to the Divisional Chief Operating Officers, 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		787
Claudio Descalzi		Chief Operating Officer of the E&P Division		340
Domenico Dispenza		Chief Operating Officer of the G&P Division		350
Angelo Caridi		Chief Operating Officer of the R&M Division		307
Senior managers (a)				1,612

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(a)

No. 8 managers.

 

Stock Options

Following the decision of Eni’s Board of Directors to discontinue any stock option plans from 2009, information reported herein on Eni’s stock based compensation relates to plans adopted in previous years whereby options to purchase treasury shares were awarded for no consideration to managers of Eni and its subsidiaries as defined in the Article 2359 of the Civil Code holding positions of significant responsibility for achieving the Company’s profitability targets or are otherwise strategically important. The stock option scheme provided that grantees had the right to purchase treasury shares in a 1 to 1 ratio, with a strike price calculated as the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding award or, if greater, as the average carrying cost of treasury shares held by Eni as of the date preceding the award.

The most recent stock option scheme covered the three-year period 2006-2008 and was approved on May 25, 2006, by the Shareholders’ Meeting that authorized the Board of Directors to dispose of a maximum amount of 30 million treasury shares (equal to 0.749% of the share capital) for the stock option plan. This stock option plan also provided a performance condition upon which options can be exercised. At the end of each vesting period with a three-year duration, the Board of Directors determined the number of exercisable options, in a percentage ranging from 0% to 100% of the total amount awarded for each year of the scheme, depending on the performance of Eni shares measured in terms of Total Shareholder Return as compared to that achieved by a panel of major international oil companies in terms of market capitalization. Options may be exercised upon fulfillment of all conditions after three years from the award and within the next three years.

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As of December 31, 2009, a total of 19,482,330 options were outstanding for the purchase of an equal amount of ordinary shares nominal value euro 1.00 of Eni SpA, carrying an average strike price of euro 23.576.

The following is a summary of residual stock option activity as there were no options granted in 2009:

	2008		2009

	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		17,699,625			23.822		25.120		23,557,425		23.540		16.556
New options granted		7,415,000			22.540		22.538
Options exercised in the period		(582,100	)		17.054		24.328		2,000		13.743		16.207
Options cancelled in the period		(975,100	)		24.931		19.942		4,073,095		23.374		14.866
Options outstanding as of December 31		23,557,425			23.540		16.556		19,482,330		23.576		17.811
of which exercisable as of December 31		5,184,250			21.263		16.556		7,298,155		21.843		17.811

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(a)

Market price relating to new rights assigned, rights exercised in the period and rights cancelled in the period correspond 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; and (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 as of December 31.

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 General Manager of Eni		COO of E&P Division		COO of G&P Division		COO of R&M Division		Senior managers (a)
	Paolo Scaroni (b)		Claudio Descalzi		Domenico Dispenza		Angelo Caridi

Options outstanding at the beginning of the period:
- number of options		2,587,500		264,000		380,000	142,000	(c)		150,500	122,000	(d)		1,671,000	80,500	(e)
- average exercise price	(euro)	23.767		24.009		24.142	4.399			22.534	21.098			23.660	21.545
- average maturity in months		55		55		56	54			65	48			56	48
Options granted during the period:
- number of options
- average exercise price	(euro)
- average maturity in months
Options exercised at the end of the period:
- number of options															35,600	(e)
- average exercise price	(euro)														17.519
- average market price at date of exercise	(euro)														22.264
Options expired during the period:
- number of options		360,930		40,280		64,925					14,700	(d)		233,995	8,900	(e)
- average exercise price	(euro)	23.100		23.100		23.100					17.519			23.100	17.519
- average market price at date of exercise		14.079		14.079		14.079					12.240			14.079	12.240
Options outstanding at the end of the period:
- number of options		2,226,570		223,720		315,075	150,500	(c)		150,500	107,300	(d)		1,437,005	36,000	(e)
- average exercise price	(euro)	23.875		24.173		24.357	22.534			22.534	21.588			23.751	26.521
- average maturity in months		45		46		46	53			65	36			46	43

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(a)		No. 8 managers.
(b)		The assignment to the CEO have been integrated in 2007 by a monetary incentive to be paid after three-year in relation to the performance of Eni shares, equal to 80,500 options with a strike price of euro 27.451. Relating to the attribution of this incentive for 2006, equal to 96,000 options with a strike price of euro 23.100, the conditions for its payment were not fulfilled, since the price of Eni share resulted lower to the exercise-price at the end of the three-year vesting period.
(c)		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.
(d)		Options on Saipem shares: assigned by the company to Angelo Caridi who held the position of CEO of Snamprogetti until August 2, 2007.
(e)		Options on Saipem shares.

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Board Practices

Corporate Governance

The corporate governance structure of Eni SpA follows the Italian traditional model, which assigns corporate management to the Board of Directors, the linchpin of the organizational system, supervisory functions to the Board of Statutory Auditors and auditing of the accounts to the audit firm appointed by the Shareholders’ Meeting.

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

The Board of Directors will expire at the date of the Shareholders’ Meeting approving Eni’s 2010 financial statements.

 

Board of Directors’ duties and responsibilities

The Board of Directors has the widest powers for the ordinary and extraordinary administration of the Company in relation to its purpose. The Board has entrusted CEO and Chief Operating Officer, Paolo Scaroni, with the widest powers for the ordinary and extraordinary administration of the Company and has retained the most important strategic, operational and organizational powers as well as the powers that by law may not be delegated.

In performing the powers as specified in the Eni Code, and in consultation with the relevant committees, the CEO, and/or the Chairman where applicable, the Board, among other tasks: defines the system of corporate governance of the Company and the Group; establishes the internal committees of the Board; assigns and revokes proxies to the CEO and to the Chairman and defines the limits and modalities for exercising such proxies; defines the fundamental guidelines pertaining to the organizational, administrative and accounting structure of the Company and the internal control system; examines and approves the Company and Group’s strategic, industrial and financial plans and agreements, annual budgets and the semi-annual financial report and the interim reports, as well as the Sustainability Report; receives information from Directors with proxies relative to activities implemented during the exercising of proxies and receives periodical half-year information from the internal committees of the Board; assesses the general management trends of the Company and of the Group paying particular attention to conflicts of interest; examines and approves the operations of the Company and its subsidiaries which are significant from a strategic, economic and financial perspective, particularly with regards to situations in which one or more Directors retain personal or third party interests as well as related parties transactions; appoints and dismisses the Chief Operating Officer, the Officer in charge of preparing financial reports, the Officer in charge of internal control and a Senior Executive Vice President of Internal Audit; defines remuneration criteria for top management of the Company and the Group; resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the primary subsidiaries; formulates the proposals to present to the Shareholders’ Meeting; and examines and resolves on other issues which Directors with proxies believe it is appropriate to present to the Board due to their particular relevance or sensitivity.

 

Directors’ independence

The Board of Directors has confirmed that the non-executive Directors Clô, Colombo, Marchioni, Reboa, Resca, Scibetta and Taranto are independent. This determination was made by the Board at its meeting on February 11, 2010 on the basis of statements made and information available to the Company, and taking into account the criteria of independence set forth in Italian regulation and the Corporate Governance Code of Borsa Italiana. Director Clô was confirmed as being independent under the terms of the Eni Code as well, even though he has held the position for over nine years, because he was appointed by the minority shareholders (specifically the institutional investors) and because of his recognized professional skills and independence of judgment.

The Board of Statutory Auditors has consistently verified, most recently at its meeting on February 11, 2010, the correct application of the criteria and procedures adopted by the Board for assessing the independence of its members. The above-referenced independence criteria may not be equivalent to the independence criteria set forth by the NYSE listing standards applicable to a U.S. domestic company.

 

Board Committees

The Board of Directors has established three internal committees with consulting and advisory functions: a) the Internal Control Committee; b) the Compensation Committee; and c) the Oil-Gas Energy Committee. The Internal Control Committee and the Compensation Committee are required by the Corporate Governance Code of Borsa

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Italiana. The composition, tasks and operation of the committees are governed by the Board in accord with specific regulations and in compliance with the criteria outlined in the Eni Code.

The committees required by the Code consist of at least three members, although the number of members must not exceed the majority of members of the Board. All the committees must consist of non-executive Directors, the majority of whom must be independent.

In performing their functions, the committees retain the right to access any information and Company departments that are necessary to carry out their tasks. They are also provided with adequate financial resources and retain the right to avail themselves of external consultants according to terms established by the Board of Directors. Meetings of the committees may also be attended by non-members expressly invited to attend with reference to individual items on the meeting agenda. Meetings of the Internal Control Committee are attended by the Chairman of the Board of Statutory Auditors or an Effective Auditor appointed by him. Committee meetings are summarized by the respective Secretaries. The current members of the committees are all non-executive and independent directors; they were appointed at a meeting of the Board of Directors held on June 11, 2008.

 

Compensation Committee

Members: Mario Resca (Chairman), Francesco Taranto, Alberto Clô and Paolo Andrea Colombo.

Established by the Board of Directors in 1996, this committee advises the Board regarding the remuneration payable to Directors with proxies and to the members of the committees of Directors set up by the Board and, on instructions from the CEO, regarding: (i) Annual and long-term incentive plans; (ii) general criteria for the remuneration of executives with strategic responsibilities; and (iii) objectives and results of the Performance and Incentive Plans.

During 2009, the Compensation Committee met 13 times, with a 96% attendance rate, and made proposals regarding: (i) Eni’s 2008 results and 2009 objectives for the purposes of the Annual and Long-Term Incentive Plans; (ii) the variable remuneration of the Chairman, CEO and Directors based on the results achieved in 2008; (iii) the criteria of the remuneration policy for executives with strategic responsibilities; (iv) establishment of the 2009 Long-Term Monetary Incentive Plan for the CEO, to replace and compensate for the Eni Stock Option Plan; (v) establishment of the 2010 Long-Term Incentive Plan, to replace the Stock Option Plan, for critical managerial resources; (vi) establishment of the 2009-2011 Deferred Monetary Incentive Plan for managerial resources; and (vii) 2009 implementation of the Deferred Monetary Incentive Plan and its assignment to the CEO.

The composition, appointment and operating methods, tasks, powers and resources of the Committee are governed by an appropriate regulation approved by the Board of Directors.

 

Internal Control Committee

Members: Marco Reboa (Chairman), Francesco Taranto, Pierluigi Scibetta and Paolo Marchioni.

The Internal Control Committee, established within Eni in 1994, provides consulting and advisory services to the Board of Directors regarding the internal control system. It is exclusively comprised of non-executive, independent Directors with the professional qualifications required to carry out the responsibilities entrusted to it¹¹. The Committee reports to the Board of Directors both on its activities and on the adequacy of the internal control system, at least once every six months, at the time of approval of the annual and half-year financial statements. The periodical reports, to be submitted to the Board of Directors, are prepared by the Committee and must take into consideration the content of the periodical reports prepared by the Officer in charge of preparing financial reports, the Officer in charge of Internal Control and the Eni 231 Watch Structure and, in general, must be based on the evidence acquired while performing its activities. The Committee’s activities:

•		in cooperation with the Officer in charge of preparing financial reports and the Audit firm, assesses and examines the correct utilization of accounting principles and their consistent application for the drafting of the annual and half-year financial statements before approval by the Board of Directors;
•		assists the Board in defining the guidelines for the internal control system;
•		upon request by the CEO, provides an evaluation on specific aspects concerning the process used to identify the main risks related to the Company as well as on the planning, implementation and management of the internal control system;
•		oversees the activities of Internal Audit and of the Officer in charge of Internal Control; as part of this responsibility the Committee also examines: the proposal of the Audit Plan and its potential amendments

 

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		during the financial year; the annual budget of the Internal Audit Department; the periodical reports and performance indicators on the activities of the Internal Audit Department;
•		examines and assesses: (i) the outcomes of internal audit reports as well as any evidence on related monitoring activities on improvement actions on control system, planned after the audits are performed; (ii) evidence resulting from the periodical reports on the outcomes of the monitoring activities conducted on the internal control system over financial reporting, on its adequacy and actual application, as well as the adequacy of the powers and means assigned to the Officer in charge of preparing financial reports; (iii) communications and information received from the Board of Statutory Auditors and its members regarding the internal control system, also in reference to the outcomes of preliminary inquiries conducted by the Internal Audit department following reports received also in anonymous form (whistle blowing); (iv) evidence emerging from the reports and management letters submitted by the Audit Firm12; (v) periodical reports issued by Eni 231 Watch Structure, also in its capacity as Guarantor of the Code of Ethics; (vi) evidence emerging from the periodical reports submitted by the Officer in charge of preparing financial reports and by the Officer in Charge of internal control; and (vii) information on the internal control system as it relates to the Company’s structure, also through periodical meetings with management, as well as enquiries and reviews carried out by third; and
•		performs other specific activities aimed at formulating analyses and opinions on topics falling under its competence and based on the Board’s request for details, and in particular, providing an opinion on the rules concerning the transparency and substantial and procedural correctness of operations carried out with related third parties, as well as transactions where a Director of the Board retains a personal interest or an interest on behalf of third parties, and carries out any additional task assigned within this scope, including the review and evaluation of specific types of transactions.

 

Board of Statutory Auditors

In accordance 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 members of the Board of Statutory Auditors were elected by the Ordinary Shareholders’ Meeting held on June 10, 2008 for a three year term, until the Shareholders’ Meeting approval of the consolidated financial statements for the year ended December 31, 2010.

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.

Pursuant to the Consolidated Law on Finance, the Board of Statutory Auditors oversees: (i) the compliance with the law and the By-Laws; (ii) the observance of the principles for correct administration, the suitability of the Company’s organizational structure, within each area of competence, the suitability of the internal control system and of the administrative-accounting system, as well as the accurate recording by the latter of the Company’s operations; (iii) the methods for complying with corporate governance regulations set forth in the Code of Borsa Italiana to which the Company adheres; and (iv) the adequacy of the provisions imposed on the subsidiaries by the Company, in order to guarantee full compliance with legal reporting requirements.

Pursuant to the Consolidated Law on Finance, the Board of Statutory Auditors submits a documented proposal to the Shareholders’ Meeting concerning the granting of auditing responsibilities as well as compensation for the audit firm. In accordance with Eni’s Code, the Board also monitors the independence of the audit firm, its compliance with all applicable regulatory provisions as well as the nature and size of non-auditing services provided

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to the Eni Group either directly or through companies within its network. The outcomes of this monitoring activity are included in the Report which shall be prepared pursuant to Article 153 of the Consolidated Law on Finance, and attached to the documentation accompanying the financial statements.

In 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, identified the Board of Statutory Auditors as the body that, since June 1, 2005, has been fulfilling, within the limits set forth by Italian laws, the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and by SEC regulations. On June 15, 2005, the Board of Statutory Auditors approved the regulations concerning the fulfillment of the responsibilities assigned pursuant to the aforementioned U.S. regulations, the text of which is available on Eni’s website.

The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by SEC rules are as follows:

•		evaluating the proposals presented by the external auditors for their appointment and making its prompt recommendation to the Shareholders’ Meeting about the proposal for the appointment or the retention of the external auditor;
•		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.

 

Eni Watch Structure and Model 231

According to the Italian regulations pertaining to the "administrative liability of legal entities deriving from offences", pursuant to Legislative Decree No. 231 of June 8, 2001 (hereinafter, "Legislative Decree No. 231 of 2001"), associations, including corporations, may be held liable – and therefore charged with the payment of a penalty or placed under injunction, with regard to certain offences that are attempted or committed in Italy or abroad in the interest or for the benefit of the Company. The companies may, in any case, adopt organizational, management and control models suitable to the prevention of possible offences. With regards to this issue, Eni SpA’s Board of Directors – in its meetings of December 15, 2003 and January 28, 2004 – has approved an organizational, managerial and control model pursuant to Legislative Decree No. 231 of 2001 ("Model 231") and has appointed the Eni Watch Structure¹³. The composition of the Eni Watch Structure, initially consisting of only three members, was amended in 2007 with the addition of two external members, one of them appointed by the Chairman of the Eni Watch Structure and selected from among university professors and professionals of proven experience and expertise in economics and business management. The internal members are represented by the Legal Affairs Senior Executive Vice President, the Internal Audit Senior Executive Vice President and the Human Resources Executive Vice President (or managers directly reporting to them).

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Court of Auditors ("Corte dei conti")

The financial management of Eni is subject to control by the Court of Auditors in order to protect public finances. This activity was carried out by the Judge of the Court of Auditors, Lucio Todaro Marescotti, succeeded by Raffaele Squitieri, appointed by resolutions issued on October 28, 2009 by the Council of the Presidency of the Court of Auditors. The Judge of the Court assists at the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Internal Control Committee.

 

Employees

As of December 31, 2009, Eni’s had a total of 78,417 employees, a decrease of 463 employees or 0.6% from December 31, 2008, which reflects an increase of 718 employees hired and working outside Italy and a decrease of 718 employees hired in Italy.

Employees hired in Italy were 38,299 (48.9% of all Group employees). Of these, 34,794 were working in Italy, 3,282 outside Italy and 223 on board vessels, with a 1,181 unit decrease from 2008. Declines were registered in all business segments due to efficiency actions and to the postponement to 2010 of some orders obtained by Saipem.

The process of improvement in the quality mix of employees continued in 2009 with the hiring of 1,163 persons, of which 491 had fixed-term contracts. A total of 672 persons were hired with open-ended and apprenticeship contracts, most of them with university qualifications (359 persons) and 282 persons with a high school diploma. During the year 2,357 persons left their job at Eni, of these 1,634 had an open-end contract and 491 a fixed-term contract.

Employees hired and working outside Italy were 40,118 (51.1% of all Group employees), an increase of 718 persons, of which approximately 650 employees were hired with fixed-term contracts in the Engineering & Construction segment mainly due to new contracts in Nigeria and Kazakhstan (Kashagan project), and 160 persons in the Exploration & Production segment, offset by downsizing in other segments, in particular in Hungary in the Gas & Power segment (Tigaz).

Employees at year end		2007		2008		2009

(units)

Exploration & Production		9,023		10,891		10,870
Gas & Power		11,893		11,692		11,404
Refining & Marketing		9,428		8,327		8,166
Petrochemicals		6,534		6,274		6,068
Engineering & Construction		33,111		35,629		35,969
Other activities		1,172		1,070		968
Corporate and financial companies		4,701		4,997		4,972
		75,862		78,880		78,417

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The table below sets forth Eni’s employees as of December 31, 2007, 2008 and 2009 in Italy and outside Italy:

		2007		2008		2009

(units)

Exploration & Production	Italy		5,224		5,468		5,287
	Outside Italy		3,799		5,423		5,583
			9,023		10,891		10,870
Gas & Power	Italy		9,425		9,113		8,911
	Outside Italy		2,468		2,579		2,493
			11,893		11,692		11,404
Refining & Marketing	Italy		7,101		6,641		6,493
	Outside Italy		2,327		1,686		1,673
			9,428		8,327		8,166
Petrochemicals	Italy		5,476		5,230		5,054
	Outside Italy		1,058		1,044		1,014
			6,534		6,274		6,068
Engineering & Construction	Italy		6,618		7,316		7,003
	Outside Italy		26,493		28,313		28,966
			33,111		35,629		35,969
Other activities	Italy		1,172		1,070		968
	Outside Italy		-		-		-
			1,172		1,070		968
Corporate and financial companies	Italy		4,411		4,642		4,583
	Outside Italy		290		355		389
			4,701		4,997		4,972
Total	Italy		39,427		39,480		38,299
Total	Outside Italy		36,435		39,400		40,118
			75,862		78,880		78,417
of which senior managers			1,585		1,658		1,649

 

Share Ownership

As of March 29, 2010, the cumulative number of shares owned by Eni’s directors, statutory auditors and senior managers, including the three Chief Operating Officers, was 231,870 equal to approximately 0.006% of Eni’s share capital outstanding as of the same data. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The break-down of share ownership for each of those persons is provided below.

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Name	Position	Number of shares owned		Option granted (*)

Board of Directors
Roberto Poli		Chairman
Paolo Scaroni		CEO and COO of Eni		56,250		1,894,230
Alberto Clô		Director
Paolo Andrea Colombo		Director		1,650
Paolo Marchioni		Director		600
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		182,830
Domenico Dispenza		Chief Operating Officer of the G&P Division		99,715		251,275
Angelo Caridi		Chief Operating Officer of the R&M Division		40,595		150,500
Board of Statutory Auditors				1,000
Senior managers				7,105		1,213,995

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(*)

The Board of Directors, in its meeting of March 11, 2010, determined the number of exercisable options for the 2006-2008 stock option plan, within the number of previously granted rights as of December 31, 2009, as the relevant vesting conditions were assessed (For further details see tables in the section “Stock Option Plans”).

 

Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

As of March 29, 2010, 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

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". As of March 29, 2010 there were 36,275,119 ADRs, each representing two Eni ordinary shares outstanding corresponding to 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.

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Item 8. FINANCIAL INFORMATION

Consolidated Statements and Other Financial Information

See "Item 18 – Financial Statements".

 

Legal Proceedings

Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will not have an adverse effect on Eni’s Consolidated Financial Statements.

For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see Note 28 to the Consolidated Financial Statements.

 

Dividends

Eni’s dividend policy in future periods, and the sustainability of the current amount of dividends over the next four-year period, will depend upon a number of factors including future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the “Risk Factors” set out in Item 3. The parent Company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. However, subject to such factors, under the Company’s scenario for Brent prices at 65 $/BBL flat over the next four years, management plans to pay a dividend per share for the year 2010 which will be in line with 2009 at euro 1.00 per share. In the subsequent years of the industrial plan 2010-2013 as approved by the Board, the dividend per share is anticipated to grow in line with OECD inflation. If management assumptions on oil prices were to change, management may rebase the dividend.

Management intend to propose to the Annual Shareholders’ Meeting scheduled on April 29, 2010, the distribution of a dividend of euro 1.00 per share for fiscal year 2009, of which euro 0.50 was already paid as interim dividend in September 2009. Total cash outlay for the 2009 dividend is expected at approximately euro 3.6 billion (including the euro 1.8 billion already paid in September 2009) in case the Annual Shareholders’ Meeting approves the annual dividend. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance to the full year dividend to be paid in each following year.

 

Significant Changes

See "Item 5 – Recent Developments" for a discussion of significant events occurred after 2009 year-end up to the latest practicable date.

 

 

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"). Telematico, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA ("Borsa Italiana"). 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.

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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)

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
2009		18.350		12.300		54.450		31.070
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
Second quarter		18.350		14.510		51.800		37.240
Third quarter		17.700		15.860		52.100		44.400
Fourth quarter		18.220		16.500		54.450		48.660
October 2009		18.220		16.730		54.450		48.660
November 2009		17.540		16.500		52.450		49.740
December 2009		17.870		16.690		51.380		48.720
2010
First quarter		18.560		16.010		53.890		43.950
January 2010		18.560		16.710		53.890		46.520
February 2010		17.110		16.010		47.910		43.950
March 2010 (through March 29, 2010)		17.870		16.840		48.710		45.680

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 hereunder.

As of March 29, 2010 there were 36,275,119 ADRs outstanding, representing 72,550,238 ordinary shares or 2% of all Eni’s shares outstanding, held by 113 holders of record (including the Depository Trust Company) in the United States of America, 111 of which are U.S. residents. Since certain of such ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere.

The Shares are included in the FTSE MIB Index (the "FTSE MIB"), the primary benchmark index for the Italian stock market. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on Telematico and seeks to replicate the broad sector weights of the Italian stock market. The constituents of the FTSE MIB are selected according to the following criteria: sector representation, market capitalization of free-float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for float. Since June 1, 2009 the FTSE MIB (previously S&P/MIB Index) is the principal indicator used to track the performance of the Italian stock market and is the basis for future and option contracts traded in the Italian Derivatives Market ("IDEM") managed by Borsa Italiana. Eni’s Shares are the second largest component of the FTSE MIB after UniCredit, with a weighting of approximately 14.9%, as established by FTSE after the quarterly rebalancing for FTSE MIB effective March 22, 2010.

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. In addition, future and option contracts on the Shares are traded on IDEM and securitized derivatives based on the

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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.

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an "official price", calculated as the weighted average price of the total volume of each security traded in the market during the session, and a "reference price", calculated as the closing-auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on Telematico, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective December 10, 2009: (i) ± 5.0% (or such other amount established by Borsa Italiana in the "Guide to the Parameters" for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall be the previous day’s reference price, in the opening auction, or the auction price, in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the "Guide to the Parameters") with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.

 

Markets

The Commissione Nazionale per le Società e la Borsa (the National Commission for Companies and the Stock Exchange or "Consob"), is the public authority responsible for regulating and supervising the Italian securities markets to ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, is a joint stock company authorized by Consob to operate regulated markets in Italy; it is responsible for the organization and management of the Italian stock exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are: to oversee transaction activities; to define the rules and procedures for admission and listing on the market for issuing companies; to define the rules and procedures for admission for intermediaries.

According to Consob Regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which are Telematico (shares, convertible bonds, pre-emptive rights, warrants, and Funds), TAH (After Hours trading market), ETFplus (Exchange Traded Funds and Exchange Traded Commodities market), IDEM (index and stock derivatives market), SeDeX (covered warrants and certificates), MOT (bond market), and MIV (Investment Vehicles Market), as well as the admission to listing on and trading on these markets.

According to EU Markets in Financial Instruments Directive (2004/39/EC) ("MiFID") and Consob Regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities ("MTF"s) or Systematic Internalisers. 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.

According to Legislative Decree No. 58 of February 24, 1998 ("Decree No. 58"), the consolidated law on financial intermediaries, the provision of investment services and activities to the public on a professional basis is reserved to banks and investment firms ("authorized persons"). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct.

The Bank of Italy, in agreement with Consob, also regulates the operation of the clearing and settlement service for transactions involving financial instruments. The regulations and measures of general application adopted by Consob and the Bank of Italy are available on the website of Consob (www.consob.it) or Bank of Italy (www.bancaditalia.it). The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it).

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Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

Register office

"Eni SpA" results from the privatization of Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953 and it is registered at the Rome Companies Register, with identification number (and Tax number) 00484960588, and Vat number 0090581106.

The full text of Eni’s By-Laws is attached as an exhibit to this annual report (last amended on March 25, 2009). See "Exhibit 1".

 

Company objects and purpose

According to Article 4 of Eni’s By-Laws, Company’s objects include: management of activities in the field of hydrocarbons and natural vapors, all in respect of concessions provided by the law; management of activities in the fields of chemicals, nuclear fuels, geothermal and renewable energy sources, industrial plant construction and engineering, mining, metallurgy, textile machinery, water derivation, purification and distribution, environmental protection and treatment and disposal of waste, as well as in any other business activity that is instrumental, supplemental or complementary with the aforementioned activities. The Company manages the technical and financial co-ordination of subsidiaries and affiliated companies. Moreover, the Company may take shareholdings and interests in other companies or business 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’ issues

The Eni 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 of Directors on the matters regarding major strategic, operational and organizational decisions.

According with Eni’s By-Laws, a majority of members having a voting right must be present for a Board meeting to be valid. Board’s resolutions are taken with the majority of votes of the members (with voting rights) present at the meeting; votes are equal, the person who chairs the meeting has a casting vote.

 

Interests in Company’s transactions

As provided by Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company’s transactions, he shall disclose it to the others (as well as to the Board of Statutory Auditors), specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the provisions of the Eni Corporate Governance Code, the Board of Directors – in its decision of February 12, 2009 and with the opinion of the Internal Control Committee – has adopted a specific policy ("Guidelines on transactions involving interests of Directors or Statutory Auditors and related parties transactions"), to detail the above mentioned disclosure obligations (extending them to the Statutory Auditors). According to these Guidelines Directors involved in matters subject to the Board resolution normally shall not participate in the correspondent discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction is under his jurisdiction, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Civil Code). Moreover, to ensure compliance with the preliminary and authorizing procedures described, Eni’s Directors and Statutory Auditors shall periodically issue a statement representing the potential interests each one of them has with respect to the Company and the Group, and in any case they shall promptly notify the Chief Executive Officer (or the Chairman, if the matter concerns the latter’s interest) – who shall inform the other Directors and the Statutory Auditors – of the individual transactions that the Company intends to perform, in which they have an interest.

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Compensation

Directors’ compensation is determined by the Shareholders Meeting, as required by Italian civil law, while compensation of Directors invested with particular powers (such as the Chairman and the CEO) is determined by the Board of the Directors, on proposal of the Compensation Committee after consultation with the Board of Statutory Auditors (for more details about compensation policy in 2009, see "Item 6 – Compensation").

 

Borrowing powers

Borrowing powers exercisable by directors are included in the Company purpose. Moreover, according to the Article 11 of the By-Laws, the Company may issue bonds, including convertibles and warrant bonds in compliance with the law.

 

Retirement and shareholdings

There are no provisions in the By-Laws relating both to the retirement based on age-limit requirements and the number of shares required for director’s qualification.

 

Company’s shares

According to Article 5 of the By-Laws, the Company’s share capital amounts to euro 4,005,358,876, fully paid, and is represented by 4,005,358,876 ordinary nominative shares with a nominal value of euro 1 (one) each. As required by Italian legislation on dematerialization of financial instruments, Eni’s shares must be held with "Monte Titoli" (the Italian Central Depository for financial instrument) and their beneficial owners may exercise their rights through special deposit accounts opened with authorized intermediaries, such as banks, brokers and securities dealers.

Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, also through proxy or mail.

Moreover, according to Article 9 of the By-Laws, the Shareholders’ Meeting might resolve to increase the Company capital by issuing shares, including shares of different classes, to be assigned for no consideration to Eni’s employees, pursuant to Article 2349 of the Italian Civil Code. This faculty has not been exercised.

In 1995, Eni established a sponsored ADR (American Depositary Receipts) program directed to U.S. investors. Each of Eni’s ADR is equal to two of Eni’s ordinary shares; Eni’s ADR are listed on the New York Stock Exchange.

 

Dividend rights

Shareholders have the right to participate in profits and any other right as provided by the law and subject to any applicable legal limitations: in particular, the ordinary Shareholders’ Meeting called for the approval of the annual financial statements may allocate the net income resulting after the allotment to the legal reserve, to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors has the faculty, as allowed by the By-Laws, to pay interim dividends to the shareholders. Dividends not collected within five years from the day in which they are payable will be prescribed in favor of the Company and allocated to reserves.

 

Voting rights

The general provisions on the shares' "voting rights" are described at the point 6 below. In relation to the appointment of the Board of Directors (Eni’s Board is not a "staggered board") and the Board of Statutory Auditors (see Item 6) the By-Laws provide a voting list system. In particular, pursuant to Article 17 of the By-Laws and according to the provisions of Law No. 474/1994, lists may be presented both by shareholders, either individually or together with others, representing at least 1% of the share capital, or by the Board of Directors. Each shareholder may present or contribute towards presenting, and vote for, a single list.

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There are no provisions in Eni’s By-Laws relating to: rights to share in the Company’s profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.

 

Liquidation rights

In case of liquidation of the Company, the Shareholders’ Meeting would appoint one or more liquidators and determine their powers and remuneration. According to the Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to the nominal value of their shares, only after payments of all Company’s liabilities and satisfaction of all other creditors.

 

Change in shareholders’ rights

To change the rights of holders of the stocks is necessary a shareholders’ resolution. In case of any modification of the By-Laws provisions relating to voting and dividend rights, resolved by the Shareholders’ Meeting, with the attendance and decision quorum established by the law for extraordinary meetings, shareholders are entitled with a withdrawal right, provided by the Italian Law.

 

Shareholders’ Meeting

The Shareholders’ Meeting resolves on the issues set forth applicable law and Eni’s By-Laws, in "ordinary" or "extraordinary" form. In particular, an ordinary meeting appoints and revokes Directors and Statutory Auditors, approves financial statements within 120 days from the end of each financial year (December 31), while an extraordinary meeting approves amendments in By-Laws¹⁴ and extraordinary transactions, such as capital increases, mergers and demergers.

The notice of a Shareholders’ Meeting may specify two meeting dates ("calls") for ordinary meetings and three or more calls for extraordinary Shareholders’ meetings. 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. 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 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 the following calls, respectively. On first, second and following calls, resolutions may be approved by a majority of 2/3 of the shares represented at the Shareholders’ Meeting.

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.

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 Gazzetta Ufficiale of the Italian Republic, and in the newspapers "Il Sole 24 Ore", "Corriere della Sera" and "Financial Times". The notice, which reports the conditions of admission requested by the By-Laws, is filed with Borsa Italiana and published on the Company website. Admission to the Shareholders’ Meeting is granted to shareholders who deliver the communication issued by financial intermediaries, according to applicable laws, at least two business days prior to the date of the meeting. The communication can be withdrawn, through the financial intermediaries: in this case shareholders lose the right to participate. Shareholders may also attend the meeting by proxy and vote by mail, as allowed by Article 13 and 14 of Eni’s By-Laws. Vote by mail can be revoked by express communication sent to the Company at least one day before the meeting. In order to attend the meeting, legal or voluntary representatives of shareholders shall 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 who 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.

Meetings are regulated by the "Eni’s Shareholders’ Meeting Regulation" approved by the ordinary Shareholders’ Meeting of Eni on December 4, 1998, in order to guarantee an efficient development of meetings and the right of each shareholder to express his opinion on the items in the agenda.

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During Shareholders’ Meetings, the Board of Directors provides wide disclosure on items examined and shareholders can require information on issues in the agenda. Information is provided taking account of applicable rules on inside information.

 

Stock ownership limitation and voting rights restrictions

There are no limitations imposed by Italian law or by Eni’s By-Laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to residents and non-residents in Italy).

In accordance with Article 6 of the By-Laws, and applying the special rules pursuant to Article 3 of Law Decree No. 332/1994, converted into Law No. 474 of 1994 (Law No. 474/1994), under no circumstances may any party own shares in the Company which constitute a direct or indirect shareholding of more than 3% of the share capital. Exceeding this limit results in a ban on exercising the voting rights and other rights, except for the right to partecipate in profits, relative to any shareholding that exceeds the limit.

Pursuant to Article 32 of the By-Laws and the same laws mentioned above, shareholdings owned by the Ministry of the Economy and Finance, public bodies or organization controlled by them are exempt from this ban.

Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.

 

Limitation on changes in control of the Company (Special Powers of the Italian State)

Pursuant to Article 6.2 of the By-Laws and to the special rules set out in Law No. 474/1994, the Ministry of Economy and Finance, in agreement with the Ministry of Economic Development, holds special powers that can be exercised in accordance with the criteria set out in the Prime Ministerial Decree of June 10, 2004.

These special powers are briefly the following:

(a)		objection to the purchase, by parties who are subject to the shareholding limit, of significant shareholdings, i.e. shareholdings that represent at least 3% of the share capital and consist of shares with the right to vote in ordinary Shareholders’ Meetings. The objection, duly justified, must be expressed if the transaction is deemed to be prejudicial to the vital interests of the State, within ten days of the date of the notification which Directors are required to send when a request is made for registration in the register of shareholders. During the period of time allowed for the right of objection to be exercised, the voting rights and other rights, except for the right to partecipate in profits, connected with the shares that represent the significant shareholding remain suspended. In the event of the right of objection being exercised, by means of a duly justified decision based on the actual prejudicial effect caused by the transaction to the vital interests of the State, the assignee will be forbidden from exercising its voting rights and any rights other than property rights connected with the shares that represent the significant shareholding, and will be required to assign these same shares within one year. In the event of a failure to comply, the Court, at the request of the Ministry of Economy and Finance, will order the sale of the shares representing the significant shareholding according to the procedures set out in Article 2359-ter of the Civil Code;
(b)		objection to the signing of agreements, as defined in Article 122 of the Consolidated Law on Finance, in the event that at least 3% of the share capital consisting of shares with the right to vote in ordinary Shareholders’ Meetings is represented in the agreements. For the purpose of allowing the right of objection to be exercised, Consob will inform the Ministry of the Economy and Finance of any significant agreements of which it has been notified under the terms of the aforementioned Article 122 of the Consolidated Law on Finance. The right of objection must be exercised within ten days of the date of Consob’s notification. During the period of time allowed for the right of objection to be exercised, the voting rights and any rights other than property rights of the shareholders signing up to the agreement are suspended. If an objection decision is issued with due justification detailing the actual prejudicial effect of the aforesaid agreements to the vital interests of the State, the agreement will be null and void. If the conduct during the Shareholders’ Meeting of the shareholders bound by the agreement reveals that the undertakings given under an agreement pursuant to the aforesaid Article 122 of the Consolidated Law on Finance have been maintained, any resolutions passed with the casting vote of these same shareholders may be challenged;
(c)		vetoing, if duly justified by an actual prejudicial effect to the vital interests of the State, of resolutions to dissolve the Company, transfer the company, merge, demerge, transfer the registered office overseas,

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		change the company purpose, amend the By-Laws in a way that withdraws or modifies the powers detailed in letters (a), (b), (c) and the subsequent letter (d); and
(d)		appointment of a Director with no right to vote in Board meetings.

Decisions to exercise the powers detailed in letters a), b) and c) may be challenged within sixty days, by the parties entitled to do so, before the Regional Administrative Court of Lazio.

These powers have been limited after some decisions of the European Court of Justice. The European Court, on March 26, 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. To obtain further information about the measures examined to comply with the ruling of the Court, the European Commission has sent the Italian authorities a formal notice under European Community infringements procedures (Article 228). Management can not foresee developments on this matter: only the Government is responsible for the amendment of the above mentioned regulation.

In order to "promote privatization and the spread of investment in shares" of companies in which the State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-Laws of privatized companies primarily controlled by the State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-Laws would lead to the shareholding limit referred to in Article 6.1 of the By-Laws being removed. At the present time, however, Eni’s By-Laws do not contain any such provision.

 

Shareholder ownership thresholds

There are no By-Laws provisions governing the disclosure of the ownership threshold because the matter is regulated by the Italian law. Under Consolidated Law on Finance¹⁵ and Consob Regulation¹⁶, any direct or indirect holding in the voting shares of a listed issuer in excess of 2%¹⁷, 5%, 10%, 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. 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.

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. The obligation to notify also applies to any direct or indirect participation owned through ADRs. Specific disclosure requirements (with partially different thresholds), are connected to the so called "potential holdings" (such as holdings of derivatives or other equity-linked securities).

Voting rights attached to listed shares which have not been notified pursuant 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.

The Consolidated Law on Finance 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

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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 Italian Civil Code. Described limitations are not applicable in case of a takeover bid or exchange tender offer for acquiring at least 60% of the ordinary shares of a listed company.

Under the same Consolidated Law on Finance, any agreement, in whatever form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed with the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights 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 Italian Civil Code.

The same provisions also apply to agreements, in whatever form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe 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.

Finally, in accordance with Law No. 287 of October 10, 1990, any merger or acquisition of sole or joint control over a company that would create or strengthen a dominant position in the domestic market in a manner that eliminates or significantly reduces competition is prohibited and mergers and acquisition of specified dimension must be subject to preventive authorization of Italian Antitrust Authority¹⁸. 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.

 

Changes in share capital

Eni’s By-Laws do not provide for more stringent conditions than is required by the law.

Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. According to 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 definite conditions, designated to prevent reduction of (actual) shareholders rights, and to preserve the Company’s interest, the pre-emptive right may be waived or limited by a shareholders’ resolution at an extraordinary Shareholders’ Meeting with the consent of more than 50% of the shares outstanding. The shareholders’ pre-emptive right is also waived by the law, in case of contributions in-kind.

 

Material Contracts

None.

 

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.

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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 2009 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 2009 profits are included in the taxable business income to the extent of 49.72% of their amount.

Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to un-distributed profit of 2007 and previous years.

Dividends received by Italian 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.

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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 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy-U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 27%. 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.

 

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:

•		the so-called "administered savings" tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (12.5%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and
•		the so-called "portfolio management" tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 12.5% substitute tax to be applied by the portfolio.

Gains realized by non-residents from non substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.

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On the contrary, gains realized by non-residents from substantial interest even in listed companies are deemed to be realized in Italy and consequently they are subject to the capital gains tax.

However double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above-mentioned conditions of non-taxability pursuant to the convention have been satisfied.

 

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), 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.

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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 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

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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.

 

Documents on Display

Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at:
http://www.eni.com/en_IT/documentation/documentation.page?type=bilrap&header=documentazione&doc_from=hpeni_header.

The Company is subject to the information requirements of the U.S. Security Exchange Act of 1934 applicable to foreign private issuers.

In accordance with these requirements, Eni files its annual report on Form 20-F and other related documents with the SEC. It’s possible to read and copy documents that have been filed with the SEC at the SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, U.S.

You may also call the SEC at +1 800-SEC-0330 or log on to www.sec.gov.

It is also possible to read and copy documents referred to in this annual report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17^th floor, New York, USA.

 

 

Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the euro/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.

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.

Please refer to Note 28 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, 14, 19 and 24 to the Consolidated Financial Statements for details of the different derivatives owned by the Company in these markets.

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Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

 

Item 12A. Debt Securities

Not applicable.

 

Item 12B. Warrants and Rights

Not applicable.

 

Item 12C. Other Securities

Not applicable.

 

Item 12D. American Depositary Shares

In the USA, the Company’s securities are traded in the form of ADSs (American Depositary Shares) which are listed on the New York Stock Exchange. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. The depositary receipts are issued, cancelled and exchanged at the office of JP Morgan Chase Bank of New York, 60 Wall Street, 36^th Floor, NY 10260, as depositary (the "Depositary") under a deposit agreement between Eni, the Depositary and the holders of ADRs.

JP Morgan Chase Bank is also the transfer agent for Eni ADRs, and its principal office is 2 Heritage Drive, North Quincy, MA 02171.

BNP Paribas is the custodian (the "Custodian") on behalf of the holders of Eni ADRs, and its principal office is located in Milan, Italy.

 

Fees and charges paid by ADR holders

The depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees.

 

 

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The table below sets forth all fees and charges that a holder of Eni’s ADRs may have to pay, either directly or indirectly, to JP Morgan, as Depositary.

Type of service		Amount of fees or charges (1)		Depositary Actions
(a) Depositing or substituting the underlying shares.		U.S. $ 5.00 for each 100 ADSs (or portion thereof)		Each person to whom ADRs are issued against deposits of shares, including deposits and issuances in respect of: • Share distributions, stock split, rights, merger. • Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities.
(b) Selling or exercising rights.		U.S. $5.00 for each 100 ADSs (or portion thereof)		Distribution or sale of securities, the fee being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities.
(c) Withdrawing an underlying security.		U.S. $5.00 for each 100 ADSs (or portion thereof)		Acceptance of ADRs surrendered for withdrawal of deposited securities.
(d) Transferring, splitting or grouping receipts.		U.S. $1.50 per ADS		Transfers, combining or grouping of depositary receipts.
(e) Expenses of the depositary.		Expenses payable at the sole discretion of the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions.		Expenses incurred on behalf of holders in connection with: • Compliance with foreign exchange control regulations or any law or regulation relating to foreign investment. • The depositary’s or its custodian’s compliance with applicable law, rule or regulation. • Stock transfer or other taxes and other governmental charges. • Cable, telex, facsimile transmission/delivery. • Expenses of the depositary in connection with the conversion of foreign currency into U.S. dollars (which are paid out of such foreign currency). • Any other charge payable by Depositary or its agents.

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(1)

All fees and charges are paid by ADR holders to JP Morgan as Depositary and Transfer agent.

 

Fees and payments made by the Depositary to the issuer

The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the New York Stock Exchange. These expenses mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.

For the year 2009, as agreed in the Deposit Agreement and subsequent amendments, the Depositary reimbursed to Eni a total amount of U.S. $900,000 in connection with above mentioned expenditures.

 

Expenses waived or paid directly to third parties by the Depositary

There are no agreements whereby the Depositary has agreed to waive the Company for any fees associated with the administration of the ADRs Program or other services thereof, nor to directly pay fees to third-parties.

 

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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, 2009.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, 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.

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Changes in Internal Control over Financial Reporting

There have not been changes in the Company’s internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

 

Item 16A. Board of Statutory Auditors Financial Expert

Eni’s Board of Statutory Auditors has determined that 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's principal independent public auditor for fiscal years 2007, 2008 and 2009 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,

		2007		2008		2009

(euro thousand)

Audit fees		26,383		27,962		30,748
Audit-related fees		169		152		276
Tax fees		81		46		51
All other fees		120		1		-
Total		26,753		28,161		31,075

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

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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.

 

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 2009, 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).

 

 

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Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In May 2000, Eni’s Ordinary Shareholders’ Meeting 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 authorization was renewed from time to time. The latest authorization for share repurchases granted by the Ordinary Shareholders’ Meeting expired on October 18, 2009. Management does not plan to request authorization for share repurchases in the foreseeable future. In the period from January 1, 2009 up to expiration of the ongoing authorization on October 18, 2009 the Company did not make any share repurchases.

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		-			-		-		-
Total purchased as of December 31, 2009		398.47			17.49		6,971		9.95
minus:
- stock options exercised and shares granted pursuant to stock option and stock grant plans		(15.53	)
Total shares held in treasury		382.93							9.56

 

Item 16F. Change in Registrant’s Certifying Accountant

Due to the audit firm rotation rules in Italy, PwC, as the Company’s independent public accounting firm, must step-down at the next meeting of the Company’s shareholders (set for April 29, 2010). PwC was hired for a period of three years and served as our independent auditor for the fiscal years ended December 31, 2009, 2008 and 2007.
PwC’s report on the Company’s financial statements for each of the past three years did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope or accounting principle.
In connection with the audit of the Company’s financial statements in the fiscal years ended December 31, 2009 and 2008, there were no disagreements with PwC on any matters of accounting principles or practices, financial statement disclosure, or auditing scope and procedures which, if not resolved to the satisfaction of PwC, would have caused PwC to make reference to the matter of such disagreements in their reports.
Eni has provided a copy of this disclosure to PwC and requested that PwC furnish us with a letter addressed to the SEC stating whether or not it agrees with the above statements. A copy of PwC’s letter is filed as an exhibit to this Form 20-F.
The Statutory Board of Auditors has selected Ernst & Young to be appointed as the Company’s new independent auditor, subject to the approval of Eni’s shareholders. If approved, Ernst & Young will become the Company's independent registered public accounting firm effective from April 30, 2010.

 

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.

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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.
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, after appointment of its member and 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. The Eni Code allows independent Directors to decide whether to meet in the absence of the other Directors for discussion of topics deemed relevant to the functioning of the Board. This express provision allowing such meetings to take place was requested by the independent Directors themselves in order to have greater flexibility to deal with actual requirements. In 2009, the independent Directors, in consideration of the frequency of the Board meetings, had numerous opportunities to meet, holding formal and informal meetings to hold discussions and exchange opinions.

 

Audit Committee

NYSE standards. Listed U.S. companies must have an audit committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the further provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

Eni standards. In 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, identified the Board of Statutory Auditors as the body that, since June 1, 2005, has been fulfilling, within the limits set forth by Italian laws, the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the SEC regulations (see “Item 6 – Board of Statutory Auditors” earlier).

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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 “Item 6 – Board of Statutory Auditors”.

 

Nominating/Corporate Governance Committee

NYSE standards. U.S. listed companies must have a nominating/corporate governance committee (or equivalent body) composed entirely of independent directors 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.

 

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 as of December 31, 2009 and 2008	F-3
Consolidated profit and loss account for the years ended December 31, 2009, 2008 and 2007	F-4
Consolidated Statements of comprehensive income for the years ended December 31, 2009, 2008 and 2007	F-5
Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2009, 2008 and 2007	F-6
Consolidated Statement of cash flows for the years ended December 31, 2009, 2008 and 2007	F-9
Supplemental cash flow information for the years ended December 31, 2009, 2008 and 2007	F-11
Notes to the Consolidated Financial Statements	F-28

 

 

Item 19. EXHIBITS

1. By-laws of Eni SpA

8. List of subsidiaries

11. Code of Ethics

Certifications:

12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act

13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)

15.a(i) Consent of DeGolyer and MacNaughton
15.a(ii) Consent of Ryder Scott Co
15.a(iii) Report of DeGolyer and MacNaughton
15.a(iv) Report of Ryder Scott Co
15.a(v) Report of DeGolyer and MacNaughton

16.f Agreement letter of PwC

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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 comprehensive income, 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, 2009 and December 31, 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, 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 2009 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.

F-1

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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.

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
April 26, 2010

 

 

 

 

 

 

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CONSOLIDATED BALANCE SHEET
(euro million)

		Dec. 31, 2008		Dec. 31, 2009

		Note		Total amount		of which with related parties		Total amount		of which with related parties

ASSETS
Current assets
Cash and cash equivalents		(1)		1,939					1,608
Other financial assets held for trading or available for sale:		(2)
- equity instruments				2,741
- other securities				495					348
				3,236					348
Trade and other receivables		(3)		22,222			1,539		20,348			1,355
Inventories		(4)		6,082					5,495
Current tax assets		(5)		170					753
Other current tax assets		(6)		1,130					1,270
Other current assets		(7)		1,870			59		1,307			9
Total current assets				36,649					31,129
Non-current assets
Property, plant and equipment		(8)		55,933					59,765
Inventory - compulsory stock		(9)		1,196					1,736
Intangible assets		(10)		11,019					11,469
Equity-accounted investments		(11)		5,471					5,828
Other investments		(11)		410					416
Other financial assets		(12)		1,134			356		1,148			438
Deferred tax assets		(13)		2,912					3,558
Other non-current receivables		(14)		1,881			21		1,938			40
Total non-current assets				79,956					85,858
Assets held for sale		(25)		68					542
TOTAL ASSETS				116,673					117,529
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt		(15)		6,359			153		3,545			147
Current portion of long-term debt		(20)		549					3,191
Trade and other payables		(16)		20,515			1,253		19,174			1,241
Income taxes payable		(17)		1,949					1,291
Other taxes payable		(18)		1,660					1,431
Other current liabilities		(19)		3,863			4		1,856			5
Total current liabilities				34,895					30,488
Non-current liabilities
Long-term debt		(20)		13,929			9		18,064
Provisions for contingencies		(21)		9,506					10,319
Provisions for employee benefits		(22)		947					944
Deferred tax liabilities		(23)		5,784					4,907
Other non-current liabilities		(24)		3,102			53		2,480			49
Total non-current liabilities				33,268					36,714
Liabilities directly associated with assets held for sale		(25)							276
TOTAL LIABILITIES				68,163					67,478
SHAREHOLDERS' EQUITY		(26)
Minority interest				4,074					3,978
Eni shareholders' equity
Share capital				4,005					4,005
Reserves				40,722					46,269
Treasury shares				(6,757	)				(6,757	)
Interim dividend				(2,359	)				(1,811	)
Net profit				8,825					4,367
Total Eni shareholders' equity				44,436					46,073
TOTAL SHAREHOLDERS' EQUITY				48,510					50,051
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY				116,673					117,529

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)

		2007		2008		2009

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		(29)		87,204			4,198			108,082			5,048			83,227			3,300
Other income and revenues				833						728			39			1,118			26
Total revenues				88,037						108,810						84,345
OPERATING EXPENSES		(30)
Purchases, services and other				58,133			3,777			76,350			6,298			58,351			4,999
- of which non-recurring charge				91						(21	)					250
Payroll and related costs				3,800						4,004						4,181
- of which non-recurring income				(83	)
OTHER OPERATING (CHARGE) INCOME				(129	)		10			(124	)		58			55			44
DEPRECIATION, DEPLETION, AMORTIZATIONAND IMPAIRMENTS				7,236						9,815						9,813
OPERATING PROFIT				18,739						18,517						12,055
FINANCE INCOME (EXPENSE)		(31)
Finance income				4,445			49			7,985			42			5,950			27
Finance expense				(4,554	)		(20	)		(8,198	)		(17	)		(6,497	)		(4	)
Derivative financial instruments				155						(427	)					(4	)
				46						(640	)					(551	)
INCOME FROM INVESTMENTS		(32)
Share of profit (loss) of equity-accounted investments				773						640						393
Other gain (loss) from investments				470						733						176
				1,243						1,373						569
PROFIT BEFORE INCOME TAXES				20,028						19,250						12,073
Income taxes		(33)		(9,219	)					(9,692	)					(6,756	)
Net profit				10,809						9,558						5,317
Attributable to:
- Eni				10,011						8,825						4,367
- Minority interest		(26)		798						733						950
				10,809						9,558						5,317
Earnings per share attributable to Eni (euro per share)		(34)
Basic				2.73						2.43						1.21
Diluted				2.73						2.43						1.21

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(euro million)

		Note		2007		2008		2009

Net profit				10,809			9,558			5,317
Other items of comprehensive income
Foreign currency translation differences				(1,980	)		1,077			(869	)
Change in the fair value of cash flow hedging derivatives		(26)		(2,237	)		1,969			(481	)
Change in the fair value of available-for-sale securities		(26)		(6	)		3			1
Share of "Other comprehensive income" on equity-accounted entities										2
Taxation		(26)		869			(767	)		202
Other comprehensive income				(3,354	)		2,282			(1,145	)
Total comprehensive income				7,455			11,840			4,172
Attributable to:
- Eni				6,708			11,148			3,245
- Minority interest				747			692			927
				7,455			11,840			4,172

 

 

 

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(million euro)

	Eni shareholders’ equity

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of the tax effect

Reserve related to the fair value of available-for-sale securities net of the tax effect

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			1			6			393			(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
Other items of comprehensive income
Change in the fair value of cash flow hedge derivatives net of the tax effect											(1,370	)																							(1,370	)					(1,370	)
Change in the fair value of available-for-sale securities net of the tax effect														(4	)																				(4	)					(4	)
Foreign currency translation differences											25									(1,835	)					(119	)								(1,929	)		(51	)		(1,980	)
											(1,345	)		(4	)					(1,835	)					(119	)								(3,303	)		(51	)		(3,354	)
Total recognized income and (expense) for the year											(1,345	)		(4	)					(1,835	)					(119	)					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	)
Net effect related to the purchase of treasury shares by Saipem SpA and Snam Rete Gas SpA																																						(201	)		(201	)
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	)		(489	)		(5,697	)
Other changes in shareholders’ equity
Cost related to stock options and stock grant																										18									18						18
Other changes																										(119	)								(119	)		11			(108	)
																										(101	)								(101	)		11			(90	)
Balance at December 31, 2007		4,005			959			7,207			(1,344	)		2			428			(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
(million euro)

	Eni shareholders’ equity

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of the tax effect

Reserve related to the fair value of available-for-sale securities net of the tax effect

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			(1,344	)		2			428			(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 cash flow hedge derivatives net of the tax effect											1,255																								1,255			(52	)		1,203
Change in the fair value of available-for-sale securities net of the tax effect														2																					2						2
Foreign currency translation differences											25									1,264						(223	)								1,066			11			1,077
											1,280			2						1,264						(223	)								2,323			(41	)		2,282
Total recognized income and (expense) for the year											1,280			2						1,264						(223	)					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
Net effect related to the purchase of treasury shares by Saipem SpA																																						(31	)		(31	)
Put option granted to Publigaz Scrl (the Distrigas NV 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
								(20	)								(1,482	)					(758	)		5,262			(160	)		(10,011	)		(7,169	)		953			(6,216	)
Other changes in shareholders’ equity
Cost related to stock options and stock grant																										18									18						18
Other changes											(26	)														37									11			(10	)		1
											(26	)														55									29			(10	)		19
Balance at December 31, 2008 (Note 26)		4,005			959			7,187			(90	)		4			(1,054	)		(969	)		(6,757	)		34,685			(2,359	)		8,825			44,436			4,074			48,510

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued
(million euro)

	Eni shareholders’ equity

Share capital

Legal reserve of Eni SpA

Reserve for treasury shares

Reserve related to the fair value of cash flow hedging derivatives net of the tax effect

Reserve related to the fair value of available-for-sale securities net of the tax effect

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, 2008 (Note 26)		4,005			959			7,187			(90	)		4			(1,054	)		(969	)		(6,757	)		34,685			(2,359	)		8,825			44,436			4,074			48,510
Net profit for the year																																4,367			4,367			950			5,317
Gains (losses) recognized directly in equity
Change in the fair value of cash flow hedge derivatives net of the tax effect (Note 26)											(279	)																							(279	)					(279	)
Change in the fair value of available-for-sale securities net of the tax effect (Note 26)														1																					1						1
Share of "Other comprehensive income" on equity-accounted entities																	2																		2						2
Foreign currency translation differences											1									(696	)					(151	)								(846	)		(23	)		(869	)
											(278	)		1			2			(696	)					(151	)								(1,122	)		(23	)		(1,145	)
Total recognized income and (expense) for the year											(278	)		1			2			(696	)					(151	)					4,367			3,245			927			4,172
Transactions with shareholders:
Dividend distribution of Eni SpA (euro 0.65 per share in settlement of 2007 interim dividend of euro 0.65 per share)																													2,359			(4,714	)		(2,355	)					(2,355	)
Interim dividend distribution of Eni SpA (euro 0.50 per share)																													(1,811	)					(1,811	)					(1,811	)
Dividend distribution of other companies																																						(350	)		(350	)
Payments by minority shareholders																																						1,560			1,560
Allocation of 2008 net profit																										4,111						(4,111	)
Put option granted to Publigaz Scrl (the Distrigas NV minority shareholder)																	1,495																		1,495						1,495
Effect related to the purchase of Italgas SpA and Stoccaggi Gas SpA by Snam Rete Gas SpA																	1,086																		1,086			(1,086	)
Minority interest acquired following the mandatory tender offer and the squeeze-out on the shares of Distrigas NV																																						(1,146	)		(1,146	)
																	2,581									4,111			548			(8,825	)		(1,585	)		(1,022	)		(2,607	)
Other changes in shareholders’ equity
Utilization of the reserve for the acquisition of treasury shares								(430	)								1									429
Cost related to stock options and stock grant																										13									13						13
Stock option expired																										(7	)								(7	)					(7	)
Other changes											(71	)					(38	)								80									(29	)		(1	)		(30	)
								(430	)		(71	)					(37	)								515									(23	)		(1	)		(24	)
Balance at December 31, 2009 (Note 26)		4,005			959			6,757			(439	)		5			1,492			(1,665	)		(6,757	)		39,160			(1,811	)		4,367			46,073			3,978			50,051

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)

		Note		2007		2008		2009

Net profit of the year				10,809			9,558			5,317
Depreciation, depletion and amortization		(30)		7,029			8,422			8,762
Impairments and other, net				(494	)		2,560			495
Net change in provisions for contingencies				(122	)		414			574
Net change in the provisions for employee benefits				(67	)		(8	)		16
Gain on disposal of assets, net				(309	)		(219	)		(226	)
Dividend income		(32)		(170	)		(510	)		(164	)
Interest income				(603	)		(592	)		(352	)
Interest expense				523			809			603
Exchange differences				(119	)		(319	)		(156	)
Income taxes		(33)		9,219			9,692			6,756
Cash generated from operating profit before changes in working capital				25,696			29,807			21,625
(Increase) decrease:
- inventories				(1,117	)		(801	)		52
- trade and other receivables				(655	)		(974	)		(19	)
- other assets				(362	)		162			(472	)
- trade and other payables				360			2,318			(1,201	)
- other liabilities				107			1,507			(129	)
Cash from operations				24,029			32,019			19,856
Dividends received				658			1,150			576
Interest received				333			266			594
Interest paid				(555	)		(852	)		(583	)
Income taxes paid, net of tax receivables received				(8,948	)		(10,782	)		(9,307	)
Net cash provided from operating activities				15,517			21,801			11,136
- of which with related parties		(36)		549			(62	)		(1,188	)
Investing activities:
- tangible assets		(8)		(8,364	)		(12,082	)		(12,032	)
- intangible assets		(10)		(2,229	)		(2,480	)		(1,663	)
- consolidated subsidiaries and businesses				(4,759	)		(3,634	)		(25	)
- investments		(11)		(4,890	)		(385	)		(230	)
- securities				(76	)		(152	)		(2	)
- financing receivables				(1,646	)		(710	)		(972	)
- change in payables and receivables in relation to investments and capitalized depreciation				185			367			(97	)
Cash flow from investments				(21,779	)		(19,076	)		(15,021	)
Disposals:
- tangible assets				165			318			111
- intangible assets				35			2			265
- consolidated subsidiaries and businesses				56			149
- investments				403			510			3,219
- securities				491			145			164
- financing receivables				545			1,293			861
- change in payables and receivables in relation to disposals				(13	)		(299	)		147
Cash flow from disposals				1,682			2,118			4,767
Net cash used in investing activities (*)				(20,097	)		(16,958	)		(10,254	)
- of which with related parties		(36)		(822	)		(1,598	)		(1,262	)

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CONSOLIDATED STATEMENT OF CASH FLOWS continued
(euro million)

		Note		2007		2008		2009

Proceeds from long-term debt				6,589			3,774			8,774
Repayments of long-term debt				(2,295	)		(2,104	)		(2,044	)
Increase (decrease) in short-term debt				4,467			(690	)		(2,889	)
				8,761			980			3,841
Net capital contributions by minority shareholders				1			20			1,551
Net acquisition of treasury shares different from Eni SpA				(340	)		(50	)		9
Acquisition of additional interests in consolidated subsidiaries				(16	)					(2,068	)
Dividends paid to Eni's shareholders				(4,583	)		(4,910	)		(4,166	)
Dividends paid to minority interest				(289	)		(297	)		(350	)
Net purchase of treasury shares				(625	)		(768	)
Net cash used in financing activities				2,909			(5,025	)		(1,183	)
- of which with related parties		(36)		20			14			(14	)
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)				(40	)		(1	)
Effect of exchange rate changes on cash and cash equivalents and other changes				(160	)		8			(30	)
Net cash flow for the period				(1,871	)		(175	)		(331	)
Cash and cash equivalents - beginning of year		(1)		3,985			2,114			1,939
Cash and cash equivalents - end of year		(1)		2,114			1,939			1,608

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SUPPLEMENTAL CASH FLOW INFORMATION
(million euro)

				2007		2008		2009

Effect of investment of companies included in consolidation and businesses
Current assets		398			1,938			7
Non-current assets		5,590			7,442			47
Net borrowings		1			1,543			4
Current and non-current liabilities		(972	)		(3,598	)		(29	)
Net effect of investments		5,017			7,325			29
Minority interests					(1,261	)
Fair value of investments held before the acquisition of control		(13	)		(601	)
Sale of unconsolidated entities controlled by Eni
Purchase price		5,004			5,463			29
less:
Cash and cash equivalents		(245	)		(1,829	)		(4	)
Cash flow on investments		4,759			3,634			25
Effect of disposal of consolidated subsidiaries and businesses
Current assets		73			277
Non-current assets		20			299
Net borrowings		26			(118	)
Current and non-current liabilities		(94	)		(270	)
Net effect of disposals		25			188
Gain on disposal		33			25
Minority interest					(1	)
Selling price		58			212
less:
Cash and cash equivalents		(2	)		(63	)
Cash flow on disposals		56			149

Transactions that did not produce cash flows
Acquisition of equity investments in exchange of businesses contribution:

(euro million)				2007		2008		2009

Current assets
Non-current assets		38
Net borrowings		(4	)
Long-term and short-term liabilities
Net effect of contribution		34
Minority interest
Gain on contribution
Acquisition of investments		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 essentially 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 2009 Consolidated Financial Statements approved by Eni’s Board of Directors on March 11, 2010 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 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 the 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 the 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 rate 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 rate 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 the 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 the 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 to the equity reserve related to other comprehensive income, respectively.

In the latter case, changes in fair value recognized in 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, inter alia, significant breaches of contracts, serious financial difficulties or the high probability of insolvency of the counterparty; asset write downs are included in the carrying amount of the financial asset.

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, if applicable, 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 shareholders’ equity (the so-called "fair value option") in order to ensure a match with the recognition in the profit and loss account for the changes in fair value of the derivative instrument².

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 in "Financial income (expense)" and "Other gain (loss) 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 generally established 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, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual sale price. The cost for inventories of hydrocarbons (crude oil, condensates and natural

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gas) and petroleum products is determined by applying the weighted-average cost method on a three-month basis, or monthly, when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost for inventories of the 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 incurred. 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.

When take-or-pay clauses are included in long term natural gas purchase contracts, uncollected gas volumes which imply the "pay" clause, measured using the price formulas contractually defined, are recognized under "Other assets" as "deferred costs" as an offset to "Trade payables" or, after the settlement, to "Cash and Cash equivalents".

The deferred costs are charged to the profit and loss account: (i) when natural gas is actually delivered – the related cost is included in the determination of the weighted-average cost of inventories and (ii) for the portion which is not recoverable, when it is not possible to collect gas that was previously uncollected within the contractually defined deadlines. Furthermore, the deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, measured adopting the same criteria described for inventories.

Hedging instruments are described in the section "Derivative Instruments".

Non-current assets

Property, plant and equipment³
Tangible assets, including investment properties, are recognized using the cost model and stated at their purchase or self-construction cost including any costs directly attributable to bringing the asset into operation. In addition, when a substantial period of time is required to make the asset ready for use, the purchase price or self-construction cost includes the borrowing costs incurred that could have otherwise been saved had the investment not been made. In the case of a present obligation for the dismantling and removal of assets and the restoration of sites, the carrying value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be incurred at the moment the asset is retired. Changes in the estimate of the carrying amounts of provisions due to the passage of time and changes in discount rates are recognized under "Provisions for contingencies"⁴.

Property, plant and equipment is not revalued for financial reporting purposes.

Assets carried under financial leases 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 to 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 or 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 the book value less the estimated net realizable value at the end of the useful life, if it is significant and can be reasonably determined. Land is not

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depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see item "Non-current assets held for sale" below).

Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession or the asset's useful life.

Replacement costs of identifiable components in complex assets are capitalized and depreciated over their useful life; the residual book value of the component that has been substituted is charged to the profit and loss account. Expenditures for ordinary maintenance and repairs are expensed as incurred.

The carrying value of property, plant and equipment is reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying value with the recoverable amount which is the higher of fair value less costs to sell or its value in use. If there is no binding sales agreement, fair value is estimated on the basis of market values, recent transactions, or the best available information that shows the proceeds that the company could reasonably expect to collect from the disposal of the asset. Value in use is the present value of the future cash flows expected to be derived from the use of the asset and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life, net of disposal costs. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving more importance to independent assumptions. Oil, natural gas and petroleum products prices (and to prices for products which derive there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. Discounting is carried out at a rate that reflects a current market valuation of the time value of money and of those specific risks of the asset that are not reflected in the estimate of the future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the activity.

The evaluation of the specific country risk considered for inclusion in the discount rate is determined on the basis of information provided by external parties. The 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 risks 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 regulated activities, the discount rate used for the measurement of the value in use is equal to the rate of return defined by the Regulator. For 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 the profit or loss account as income from asset revaluation. This reversed amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

Intangible assets
Intangible assets are 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

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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 pro-rata on the basis of the carrying amount of each asset in the unit. Impairment charges against goodwill are not reversed⁵. 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 service⁶.

Exploration and production activities⁷

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.

Expenditures 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 then capitalized within property, plant and equipment and

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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.

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 the 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 while 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 revenues, and 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 method⁸. When there is objective evidence of impairment (see also section "Current assets"), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the section "Property, plant and equipment".

Subsidiaries, 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 the equity reserve related to other comprehensive income; the changes in fair value recognized in equity are charged to the profit and loss account when it is impaired or realized. When investments are not traded in a public

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market and fair value cannot be reasonably determined, investments are accounted for at cost, adjusted for impairment losses; impairment losses may not be reversed⁹.

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, impairment and amortization of the difference between the reimbursement value and the initial carrying value. Amortization is carried out on the basis of the effective interest rate of return represented by the rate that equalizes, at the moment of the initial revaluation, the current value of expected cash flows to the initial carrying value (so-called "amortized cost method"). Receivables for finance leases are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease.

Any impairment is recognized by comparing the carrying value with the present value of the expected cash flows discounted at the effective interest rate as defined at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and financial assets to be held to maturity are recognized net of the allowance for impairment losses; when the impairment loss is definite the allowance for impairment losses is reversed for charges otherwise for excess. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as "Financial income (expense)".

Non-current assets held for sale
Non-current assets and current and non-current assets included within disposal groups, whose carrying amount will be recovered principally through a sale transaction rather than through their continuing use, are classified as held for sale.

Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized in the balance sheet separately from the entity’s other assets and liabilities.

Non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell or their carrying amount.

Any difference between the carrying amount and the fair value less costs to sell is taken to the profit or loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale.

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. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any indemnity or penalty arising from failure to fulfill these obligations. If the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the company’s average borrowing rate taking

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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 recorded with a corresponding entry to the asset to which it refers. Charges to the profit and loss account are made through the amortization process of the asset.

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 unrecognized actuarial gains and losses at the end of the previous reporting period exceed the greater or 10% of the present value of the defined benefit obligation or 10% of the fair value of the plan assets, over the expected average remaining working lives of the employees participating in the plan.

Such actuarial gains and losses derive from changes in the actuarial assumptions used or from a change in the conditions of the plan.

Obligations for long-term benefits are determined by adopting actuarial assumptions. The effect of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the 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 of petroleum products are generally recognized upon shipment;
• chemical products and other products, generally upon shipment.

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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 on the measurement of accrued income if the stage of completion can be reliably determined and there is no significant uncertainty as to the collectability of the amount and the related costs. When the outcome of the transaction cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable.

Revenues accrued during the year related to construction contracts are recognized on the basis of contractual revenues with reference to the stage of completion of a contract measured on the cost-to-cost basis^10-11.

Requests for 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.

Award credits, related to customer loyalty programs, are recognized as a separate component of the sales transaction which grant the right to customers. Therefore, the portion of revenues related to the fair value of award credits granted is recognized as an offset to the item "Other liabilities". The liability is charged to the profit and loss account in the period in which the award credits are redeemed by customers or the related right is lost.

The exchange of goods and services of a similar nature and value do not give rise to revenues and costs as they do not represent sale transactions. Costs are recorded when the related goods and services are sold, 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. 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. Revenues related to emission quotas are recognized when they are realized after the related sale. In case of sale, if applicable, the acquired emission rights should be considered as the first to be sold.

Operating lease payments are recognized in the profit and loss account over the length of the contract.

Labor costs include stock options granted to managers, consistent with their actual remunerative nature. The instruments granted are recorded at fair value on the vesting date and are not subject to subsequent adjustments; the current portion is calculated pro-rata over the vesting period¹². Fair value of stock options is determined using valuation techniques which consider conditions related to the exercise of options, current share prices, expected volatility and the risk-free interest rate. The fair value of stock options is recorded as a charge to "Other reserves".

The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized, 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.

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Monetary assets and liabilities denominated in currencies other than functional currency are converted by applying the year end exchange rate and the effect is stated in the profit and loss account. Non-monetary assets and liabilities denominated in currencies other than the functional currency valued at cost are translated at the initial exchange rate. Non-monetary 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 taxes payables". Current income 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 as of the balance sheet date and the tax rates estimated on 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 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 hedged item is formally documented and the hedge is highly effective and regularly reviewed. 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 on the fair value of fixed interest rate assets/liabilities) the derivatives are stated at fair value and the effects are 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 reported 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 statements¹³
Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature¹⁴.

The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS.

The statement of changes in shareholders’ equity includes profit and loss for the year, transactions with shareholders and other changes in shareholders’ equity.

The statement of cash flows is presented using the indirect method, whereby net profit is adjusted for the effects of non-cash transactions.

 

Changes in accounting principles

Starting from January 1, 2009, following the adoption of the provisions of IFRIC 13 "Customer Loyalty Programmes", award credits granted are recognized as a separate component of the sales transaction which granted the right to customers. As a result, part of the consideration received from the sale transaction is allocated to award credits granted, on the basis of their fair value, as an offset to the balance sheet item "Other liabilities"; such liability is recorded to the profit and loss account (as a revenue) in the year when award credits are redeemed by customers or rights are cancelled.

The application of IFRIC 13 determined the following adjustments in the 2007 and 2008 profit and loss account and in the balance sheet as of January 1, 2008 and December 31, 2008: (i) a decrease of euro 52 million and euro 66 million in "Net sales from operations" in the 2007 and 2008 profit and loss account, respectively; (ii) an increase of euro 6 million and euro 8 million in "Other income and revenues" in the 2007 and 2008 profit and loss account, respectively; (iii) a decrease of euro 46 million and euro 58 million in the line item "Purchases, services and other" in the 2007 and 2008 profit and loss account, respectively; (iv) the reclassification of euro 53 million and euro 66 million from "Provisions for contingencies" to "Other current liabilities" in the balance sheet as of January 1, 2008 and December 31, 2008, respectively.

Segment reporting is prepared according to the provisions of IFRS 8 "Operating Segments", effective from January 1, 2009. The new standard requires segment reporting to be prepared according to the requirements used for the preparation of internal reports for the entity’s chief operating decision maker. Therefore the identification of operating segments and the related reporting are prepared on the basis of internal reports that are regularly reviewed by the entity’s chief operating decision maker in order to allocate resources to the segment and to assess its performance. The adoption of the provisions of IFRS 8 "Operating Segments" has not modified the reporting segments.

Starting from 2009, the provisions of the revised IAS 23 "Borrowing Costs" are effective. The revised standard requires the capitalization of borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset that takes a substantial period of time to get ready for use or sale. As a result, the main change from the previous version is the removal of the option of immediately recognizing as an expense such borrowing costs. The change does not affect Eni’s financial statements as it already capitalizes such costs.

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

Oil and gas activities
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering criteria that must be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data engineering and geological interpretation and judgment.

Field reserves will only be categorized as proved when all the criteria for attribution of proved status have been met. At this stage, all booked reserves 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 in regards to the initial estimate and, in the case of Production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered.

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

Depreciation rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter.

Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment.

Impairment of assets
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

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matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred cost - see also item "Current assets") related to natural gas volumes not collected under long term purchase contracts with take-or-pay clauses.

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 or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate related to the activity involved.

For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. 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 product 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 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 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.

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Environmental liabilities
Together with other companies in the industries in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental costs are recognized when it becomes probable that a liability has been incurred and the amount can be reasonably estimated.

Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to:

(i)		the possibility of an unknown contamination;
(ii)		the results of the ongoing surveys and other possible effects of statements required by 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, 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 the profit or loss in their entirety.

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

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

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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
The revised IFRS 3 "Business Combinations" require, interalia, (i) the acquisition-related costs to be accounted for separately from the business combination and then recognized as expenses; (ii) the recognition to the profit and loss account of any change to contingent consideration; and (iii) the choice of the full goodwill method which means to account for the full value of the goodwill of the business combination including the share attributable to non-controlling interests. In the case of step acquisitions, the revisions also require the recognition in the profit and loss account 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 "Consolidated and Separate Financial Statements" require, interalia, that acquisitions or disposals of ownership interests in a subsidiary that do not result in the acquisition (loss) of control, shall be accounted for as equity transactions. By contrast, disposal of any interests that the parent retains in a former subsidiary, jointly controlled entity or associate may result in a loss of control, joint control and significant influence. In this case, at the date when control (joint control or significant influence) is lost, the remaining investment retained is recognized at its fair value with gains or losses arising from the difference between the fair value and carrying amount of the held investment recorded 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).

Amendment to IAS 32 "Classification of rights issues" clarifies how to classify in the issuer’s financial statements those financial instruments which grant to shareholders the right to acquire equity instruments of the issuers for a price denominated in a currency other than issuer’s functional currency. If such instruments are issued pro rata to the issuer's existing shareholders for a fixed amount of cash, they should be classified as equity even if their exercise price is denominated in a currency other than the issuer's functional currency. The amendment to IAS 32 shall be applied for annual period beginning on or after February 1, 2010 (for Eni: 2011 financial statements).

IFRIC 17 "Distributions of Non-cash Assets to Owners" (hereinafter IFRIC 17) provides clarification and guidance on the accounting treatment of distributions of non-cash assets to owners of an entity, or distributions that give owners a choice of receiving either non-cash assets or a cash alternative. In particular, the interpretation requires, interalia, that the distribution is measured at the fair value of the assets to be distributed. The liability to pay a dividend shall be recognized when the dividend is appropriately authorized; the liability and the related adjustments are recognized as an offset to equity. When an entity settles the dividend payable, it shall recognize the difference, if any, between the carrying amount of the non-cash assets distributed and the fair value of the dividend payable in the profit or loss account. This interpretation shall be applied for annual periods beginning on or after July 1, 2009 (for Eni: 2010 financial statements).

On November 4, 2009, IASB issued a new version of IAS 24 "Related Party Disclosures", which: (i) enhances the definition of a related party requiring new cases; (ii) for transactions between entities related to the same Government, allows to limit quantitative disclosures to significant transactions. The revised standard shall be applied for annual periods beginning on or after January 1, 2011.

On November 12, 2009 IASB issued IFRS 9 "Financial Instruments" which changes recognition and measurement of financial assets and their classification in the financial statements. In particular, new provisions require, inter alia, a classification and measurement model of financial assets based exclusively on the following categories: (i) financial assets measured at amortized cost; (ii) financial assets measured at fair value. New provisions also require that investments in equity instruments, other than subsidiaries, jointly controlled entities or associates, shall be measured at fair value with effects taken to the profit and loss account. If these investments are not held for trading purposes, subsequent changes in the fair value can be recognized in other comprehensive income, even if dividends are taken to the profit and loss account. Amounts taken to other comprehensive income shall not be subsequently transferred to the profit or loss account, even at disposal. IFRS 9 provisions shall be applied for annual periods beginning on or after January 1, 2013.

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On November 26, 2009 IASB issued IFRIC 19 "Extinguishing Financial Liabilities with Equity Instruments" which defines the accounting treatment to adopt when a financial liability is settled by issuing equity instruments to the creditor (debt for equity swaps). Equity instruments issued to extinguish a liability in full or in part are measured at their fair value or, if fair value cannot be reliably measured, at the fair value of the financial liability extinguished. The difference between the carrying amount of the financial liability extinguished and the fair value of equity instrument issued shall be recognized in the profit or loss account. IFRIC 19 provisions shall be applied for annual periods beginning on or after July 1, 2010 (for Eni: 2011 financial statements).

On April 16, 2009, IASB issued the document "Improvements to IFRSs" which includes only changes to the existing standards and interpretations with a technical and editorial nature. The provisions come into effect starting from 2010.

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 in the amount of euro 1,608 million (euro 1,939 million as of December 31, 2008) included financing receivables originally due within 90 days for euro 450 million (euro 616 million as of December 31, 2008). The latter were related to amounts on deposit with financial institutions accessible only with 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, 2008		Dec. 31, 2009

Investments		2,741
Securities held for operating purposes
Listed Italian treasury bonds		257		113
Listed securities issued by Italian and foreign financial institutions		45		171
Non-quoted securities		8
		310		284
Securities held for non-operating purposes
Listed Italian treasury bonds		109		49
Listed securities issued by Italian and foreign financial institutions		67		14
Non-quoted securities		9		1
		185		64
Total securities		495		348
		3,236		348

Equity instruments decreased by the carrying amount of the 20% interest in OAO Gazprom Neft (euro 2,741 million), purchased by Gazprom following the exercise of a call option on April 7, 2009 on the basis of the existing agreements with Eni. On April 24, 2009, Eni received a payment of euro 3,070 million (U.S. $4,062 million at the exchange rate on the date of the transaction). Eni acquired the investment in Gazprom Neft on April 4, 2007 through a bid on the liquidation of the second lot of ex-Yukos assets. The strike price of the call option was equal to the bid price (U.S.$3.7 billion) decreased by the dividends distributed and an increase of the contractual remuneration of 9.4% on the capital employed and financing collateral expenses.

Other securities in the amount of euro 348 million (euro 495 million as of December 31, 2008) were classified as available-for-sale securities. As of December 31, 2008 and 2009, Eni did not own financial assets held for trading.

The effects of the valuation at fair value of securities are set below:

(euro million)		Value at Dec. 31, 2008		Changes recognized in the reserves of shareholders' equity		Value at Dec. 31, 2009

Fair value		5			1			6
Deferred tax liabilities		(1	)					(1	)
Other reserves of shareholders' equity		4			1			5

Securities held for operating purposes in the amount of euro 284 million (euro 310 million as of December 31, 2008) were designed to provide coverage of technical reserves for the Group’s insurance company, Eni Insurance Ltd (euro 302 million as of December 31, 2008).

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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, 2008		Dec. 31, 2009

Trade receivables		16,444		14,916
Financing receivables:
- for operating purposes - short-term		402		339
- for operating purposes - current portion of long-term receivables		85		113
- for non-operating purposes		337		73
		824		525
Other receivables:
- from disposals		149		82
- other		4,805		4,825
		4,954		4,907
		22,222		20,348

Receivables are stated net of the allowance for impairment losses in the amount of euro 1,647 million (euro 1,251 million as of December 31, 2008):

(euro million)		Value at Dec. 31, 2008		Additions		Deductions		Other changes		Value at Dec. 31, 2009

Trade receivables		747		260		(15	)		(50	)		942
Financing receivables		19				(13	)					6
Other receivables		485		206		(24	)		32			699
		1,251		466		(52	)		(18	)		1,647

Trade receivables decreased in the amount of euro 1,528 million primarily due to the Gas & Power segment (euro 1,990 million), which was partially offset by the increase in the Refining & Marketing segment (euro 380 million).

Trade and other receivables were as follows:

		Dec. 31, 2008		Dec. 31, 2009

(euro million)

Trade receivables

Other receivables

Total

Trade receivables

Other receivables

Total

Neither impaired nor past due		12,611		3,395		16,006		11,557		3,004		14,561
Impaired (net of the valuation allowance)		1,242		88		1,330		1,037		58		1,095
Not impaired and past due in the following periods:
- within 90 days		1,812		502		2,314		1,168		772		1,940
- 3 to 6 months		231		68		299		503		56		559
- 6 to 12 months		248		294		542		294		439		733
- over 12 months		300		607		907		357		578		935
		2,591		1,471		4,062		2,322		1,845		4,167
		16,444		4,954		21,398		14,916		4,907		19,823

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 in the amount of euro 260 million (euro 251 million as of December 31, 2008) primarily referred to the Gas & Power segment (euro 165 million).

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Allowances for impairment losses of other receivables in the amount of euro 206 million (euro 137 million as of December 31, 2008) primarily referred to the Exploration & Production segment (euro 205 million) which primarily represents the 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 in the amount of euro 168 million (euro 213 million as of December 31, 2008).

Receivables for financing operating activities in the amount of euro 452 million (euro 487 million as of December 31, 2008) included euro 245 million due from unconsolidated subsidiaries, joint ventures and associates (euro 399 million as of December 31, 2008), euro 179 million cash deposit to provide coverage of Eni Insurance Ltd technical reserves (euro 47 million as of December 31, 2008) and receivables for financial leasing in the amount of euro 19 million (the same amount as of December 31, 2008). More information about receivables for financial leasing is included in Note 12 – Other Financial assets.

Receivables for financing non-operating activities amounted to euro 73 million (euro 337 million as of December 31, 2008), of which euro 67 million related to deposits for the Engineering & Construction segment. The decrease of euro 264 million is mainly due to the release of a deposit of Eni Lasmo Plc made to guarantee a debenture (euro 173 million) and the decrease of deposits of Eni Insurance Ltd (euro 88 million).

Other receivables were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Accounts receivable from:
- joint venture operators in exploration and production		2,242		2,372
- Italian government entities		378		457
- insurance companies		146		194
		2,766		3,023
Prepayments for services		857		860
Receivables relating to factoring operations		171		156
Other receivables		1,160		868
		4,954		4,907

Receivables deriving from factoring operations in the amount of euro 156 million (euro 171 million as of December 31, 2008) related to Serfactoring SpA and consisted primarily of advances for factoring operations with recourse and receivables for factoring operations without recourse.

Other receivables in the amount of euro 461 million (euro 227 million as of December 31, 2008) associated with cost recovery in the Exploration & Production segment are currently undergoing arbitration procedures.

Receivables with related parties are described in Note 36 – Transactions with related parties.

Because of the short-term maturity of trade receivables, the fair value approximates their carrying amount.

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4 Inventories
Inventories were as follows:

		Dec. 31, 2008		Dec. 31, 2009

(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		466		263				1,155		1,884		616		150				1,363		2,129
Products being processed and semi finished products		48		17				3		68		74		17				9		100
Work in progress						953				953						759				759
Finished products and goods		2,528		557				92		3,177		1,889		552				66		2,507
		3,042		837		953		1,250		6,082		2,579		719		759		1,438		5,495

Contract work in progress in the amount of euro 759 million (euro 953 million as of December 31, 2008) are net of prepayments in the amount of euro 13 million (euro 274 million as of December 31, 2008) which are within the limits of contractual considerations.

Inventories are stated net of the valuation allowance in the amount of euro 103 million (euro 697 million as of December 31, 2008):

(euro million)		Value at Dec. 31, 2008		Additions		Deductions		Other changes		Value at Dec. 31, 2009

697

36

(550

)

(80

)

103

Deductions in the amount of euro 550 million essentially represent the Refining & Marketing (euro 336 million) and the Petrochemical segments (euro 200 million).


5 Current tax assets
Current tax assets were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Italian subsidiaries		53		570
Foreign subsidiaries		117		183
		170		753

The increase in other current tax assets in the amount of euro 583 million mainly relates to receivables for interim tax payments which exceeded the full-year tax payable (euro 430 million) made by Eni SpA.

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6 Other current tax assets
Other current tax assets were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

VAT		623		889
Excise and customs duties		167		119
Other taxes and duties		340		262
		1,130		1,270

7 Other current assets
Other current assets were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Fair value of non-hedging derivatives		1,128		698
Fair value of cash flow hedge derivatives		474		236
Other curren assets		268		373
		1,870		1,307

The fair value of derivative contracts which do not meet the criteria to be classified as hedges under IFRS was as follows:

		Dec. 31, 2008		Dec. 31, 2009

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Interest Currency Swap		35				80		2		113
Currency swap		201		2,653		1,701		64		1,855		1,117
Other		285		98		1,154		142		174		537
		521		2,751		2,935		208		2,142		1,654
Non-hedging derivatives on interest rate
Interest rate swap		2				300		1		133
Other				4				9		9
		2		4		300		10		142
Non-hedging derivatives on commodities
Over the counter		547		1,063		1,850		469		1,383		1,257
Other		58		65		53		11		234		8
		605		1,128		1,903		480		1,617		1,265
		1,128		3,883		5,138		698		3,901		2,919

Fair value of the derivative contracts is determined using market quotations provided by primary information providers, or in the absence of market information, appropriate valuation methods used in the marketplace.

Fair values of non-hedging derivatives in the amount of euro 698 million (euro 1,128 million as of December 31, 2008) consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.

The decrease in the fair value of the non-hedging derivatives in the amount of euro 430 million primarily referred to the Gas & Power segment (euro 315 million) and the Corporate and financial companies segment (euro 160 million).

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Fair value of the cash flow hedge derivatives in the amount of euro 236 million referred to Distrigas NV. These derivatives were designated to hedge surpluses or deficits of gas to achieve a proper balance in the gas portfolio. The negative fair value for contracts expiring in 2010 is given in Note 19 – Other current liabilities; positive and negative fair value of contracts expiring beyond 2010 is given in Note 14 – Other non-current receivables and Note 24 – Other non-current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and Note 30 – Operating expenses.

The nominal value of cash flow hedge derivatives represented purchase and sale commitments in the amount of euro 25 million and euro 603 million, respectively.

Information on the hedged risks and the hedging policies is provided in Note 28 – Guarantees, commitments and risks.

Other assets amounted to euro 373 million (euro 268 million as of December 31, 2008) and included prepayments and accrued income for euro 104 million (euro 63 million as of December 31, 2008), rentals for euro 35 million (euro 31 million as of December 31, 2008) and insurance premiums for euro 18 million (euro 11 million as of December 31, 2008).


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, 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	)		1,301			123			4,535			36,120			86,716			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	)		2,442			414			(4,342	)		17,360			18,579			1,219
		46,919			12,082			(5,994	)		(1,343	)		3,601			550			118			55,933			112,290			56,357
Dec. 31, 2009
Land		625			10									2			(3	)		(16	)		618			646			28
Buildings		850			35			(99	)		(37	)		25			(34	)		45			785			3,057			2,272
Plant and machinery		36,120			3,530			(6,277	)		(496	)		3			(184	)		7,162			39,858			96,280			56,422
Industrial and commercial equipment		601			112			(152	)		(2	)		16			(18	)		230			787			1,948			1,161
Other assets		377			152			(130	)		(4	)					(8	)		156			543			1,920			1,377
Tangible assets in progress and advances		17,360			8,193						(451	)		2			(281	)		(7,649	)		17,174			18,715			1,541
		55,933			12,032			(6,658	)		(990	)		48			(528	)		(72	)		59,765			122,566			62,801

Capital expenditures in the amount of euro 12,032 million (euro 12,082 million for the year ended December 31, 2008) essentially related to the Exploration & Production segment (euro 8,196 million), the Gas & Power segment (euro 1,354 million), the Engineering & Construction segment (euro 1,615 million), and the Refining & Marketing segment (euro 626 million). Capital expenditures included capitalized finance expenses of euro 221 million (euro 236 million for the year ended December 31, 2008) essentially related to the Exploration & Production segment (euro 77 million), the Engineering & Construction segment (euro 76 million), the Refining & Marketing segment (euro 35 million) and the Gas & Power segment (euro 31 million). The interest rate used for the capitalization of finance expense ranged between 1.9% to 3.7% (3.5% and 5.1% for the year ended December 31, 2008).

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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

 

Impairments in the amount of euro 990 million (euro 1,343 million as of December 31, 2008) and the associated tax effect by segment is provided below:

(euro million)		2008		2009

Impairment
Exploration & Production		765		576
Refining & Marketing		292		287
Petrochemicals		279		121
Other segments		7		6
		1,343		990
Tax effect
Exploration & Production		213		197
Refining & Marketing		108		108
Petrochemicals		88		33
Other segments		2		2
		411		340
Impairment net of the relevant tax effect
Exploration & Production		552		379
Refining & Marketing		184		179
Petrochemicals		191		88
Other segments		5		4
		932		650

In assessing whether an impairment is required, the carrying value of an asset is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell or 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. Eni assesses individual assets or groups of assets (Cash Generating Units - CGUs) which represent the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. In particular, the CGUs consist of: (i) the Exploration & Production segment, which include individual oilfields or pools of oilfields whereby technical, economic or contractual features make the underlying cash flows interdependent; (ii) the Gas & Power segment, which include transport and distribution networks and related facilities, storage sites and re-gasification facilities in a consistent way with the gas segments of operations that are defined by the Italian Authority for Electricity and Gas for the purpose of tariff settings and other authorities. Other CGUs are gas carrier ships and plants for the production of electricity; (iii) the Refining & Marketing segment, which include refining plants and commercial facilities relating to each distribution channel and by country (ordinary network, high-ways network, and wholesale activity); (iv) the Petrochemicals segment, which include production plants and related facilities; and (v) the Engineering & Construction segment, which include Business Units Offshore construction, Onshore construction and Onshore drilling facilities and individual Rigs for Offshore operations.

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 which is derived from: (i) the Company’s four-year plan approved by top management that provides information on the expected oil and gas production, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main monetary variables, including inflation, nominal interest rates and exchange rates. For the subsequent years beyond the four-year plan, a nominal growth rate is used ranging from 0% to 2%; (ii) the commodity prices have been assessed based on the forward prices prevailing on 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").

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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 (adjusted post-tax WACC). For 2009, the adjusted post-tax rates used for impairment testing showed an increase of 0.5 percentage points on average from the previous year as a result of a higher market premium for the equity risk and the country risk. Such increase was partially reduced by decreased nominal interest rates reflected in the cost of borrowings and in rates of assets risk-free. For 2009, the adjusted post-tax rates ranged from 9% to 13.5%. 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 related to proved and unproved oil & gas properties mainly located in the Gulf of Mexico, Australia, Congo, Egypt and Nigeria as a result of downward reserve revisions and cost increases.

In the Refining & Marketing segment the main impairments related to refining plants. The drivers of those impairments were a weak refining environment and the Company’s expectations for a slow recovery in those trends which negatively affected the refining performance in 2009, including compressed price differentials between heavy and light crudes, and weak prices for middle distillates that were dragged down by excess inventory. Also, plant-specific factors were taken into account, particularly low complexity.

In the Petrochemicals segment the main impairments related to the olefins-aromatic-polyethylene plants of Porto Marghera and the Sicilian pole. The main drivers of those impairments were continuing trends for margin pressures and volumes reduction, particularly in the case of commoditized products, due to weak industry fundamentals in terms of sluggish demand, excess capacity and rising competitive pressures as new capacity is expected to come on line in the Middle East.

Negative foreign currency translation differences in the amount of euro 528 million were primarily related to translation of entities accounts denominated in U.S. dollar (euro 1,005 million). This effect was partially offset by translation of entities accounts denominated in Norwegian krones (euro 339 million).

Other negative changes in the net book value of tangible assets (euro 72 million) relate to the reclassification to assets classified as held for sale in the amount of euro 311 million and the disposals of assets in the amount of euro 150 million, which was offset by an increase in the initial recognition and change of estimated costs for the dismantling and restoration of sites in the amount of euro 289 million which mainly relate to the Exploration & Production segment (euro 273 million).

The following is a description of unproved mineral interests, included in tangible assets in progress and advances:

(euro million)

Value at the beginning of the year

Acquisitions

Impairments

Reclassification to Proved Mineral Interest

Other changes and currency translation differences

Net value at the end of the year

Dec. 31, 2008
Congo		641		862		(10	)		(81	)		85			1,497
USA		1,401				(144	)					74			1,331
Turkmenistan				809		(164	)					40			685
Algeria				748								(59	)		689
Other countries		255		209		(90	)		(85	)		(1	)		288
		2,297		2,628		(408	)		(166	)		139			4,490
Dec. 31, 2009
Congo		1,497		42					(333	)		(42	)		1,164
USA		1,331		43		(231	)		(229	)		(32	)		882
Turkmenistan		685							(13	)		(23	)		649
Algeria		689							(220	)		(17	)		452
Other countries		288		137		(54	)		(140	)					231
		4,490		222		(285	)		(935	)		(114	)		3,378

Unproved mineral interests are normally recognized upon allocation of the purchase price of business combinations in the Exploration & Production segment. The main amounts are associated with probable and possible reserves in Congo, Gulf of Mexico, Turkmenistan and Algeria associated with recent acquisitions. Changes during the year amounted to a decrease of euro 935 million which related to transfers to property, plant and equipment associated with recognition of proved reserves and internal approval for development. Impairments for

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the year amounted to euro 285 million due to downward revisions related to properties in the Gulf of Mexico and, to a lesser extent, Nigeria.

The accumulated provisions for impairments amounted to euro 4,692 million and euro 5,680 million as of December 31, 2008 and 2009, respectively.

As of December 31, 2009, Eni pledged property, plant and equipment for euro 28 million primarily as collateral against certain borrowings (euro 29 million as of December 31, 2008).

Government grants recorded as a reduction of property, plant and equipment amounted to euro 642 million (euro 651 million as of December 31, 2008).

Assets acquired under financial lease agreements amounted to euro 28 million (euro 163 million as of December 31, 2008), of which, euro 19 million related to FPSO ships used by the Exploration & Production segment to support oil production and treatment activities and euro 9 million related to service stations in the Refining & Marketing segment. The decrease of euro 135 million primarily related to the exercise of the option for the acquisition of a drilling platform by the Engineering & Construction segment for euro 127 million.

Contractual commitments related to the purchase of property, plant and equipment are included in Note 28 – Guarantees, commitments and risks – Liquidity risk.

Property, plant and equipment under concession arrangements are described in Note 28 – Guarantees, commitments and risks – Asset under concession arrangements.

Property, plant and equipment by segment

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Property, plant and equipment, gross
Exploration & Production		64,338			71,189
Gas & Power		20,729			22,040
Refining & Marketing		12,899			13,378
Petrochemicals		5,036			5,174
Engineering & Construction		7,702			9,163
Other activities		1,550			1,592
Corporate and financial companies		391			373
Elimination of intra-group profits		(355	)		(343	)
		112,290			112,566
Accumulated depreciation, amortization and impairment losses
Exploration & Production		31,983			36,727
Gas & Power		7,691			8,262
Refining & Marketing		8,403			8,981
Petrochemicals		4,124			4,321
Engineering & Construction		2,548			2,858
Other activities		1,467			1,513
Corporate and financial companies		179			194
Elimination of intra-group profits		(38	)		(55	)
		56,357			62,801
Property, plant and equipment, net
Exploration & Production		32,355			34,462
Gas & Power		13,038			13,778
Refining & Marketing		4,496			4,397
Petrochemicals		912			853
Engineering & Construction		5,154			6,305
Other activities		83			79
Corporate and financial companies		212			179
Elimination of intra-group profits		(317	)		(288	)
		55,933			59,765

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9 Inventory - compulsory stock
Inventory - compulsory stock was as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Crude oil and petroleum products		1,040		1,586
Natural gas		156		150
		1,196		1,736

Compulsory stock was primarily held by Italian companies (euro 1,184 million and euro 1,724 million as of December 31, 2008 and 2009, respectively) in accordance with minimum stock requirements set forth by applicable laws.


10 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, 2008
Intangible assets with finite useful lives
Exploration expenditures		749		1,907		(2,097	)		335			77			971		2,295		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 progress and advances		377		264								(61	)		580		590		10
Other intangible assets		158		18		(52	)		1,595			14			1,733		1,995		262
		5,436		2,480		(2,436	)		1,915			93			7,488		14,395		6,907
Intangible assets with indefinite useful lives
Goodwill		2,115							1,417			(1	)		3,531
		7,551		2,480		(2,436	)		3,332			92			11,019
Dec. 31, 2009
Intangible assets with finite useful lives
Exploration expenditures		971		1,273		(1,615	)					2			631		2,259		1,628
Industrial patents and intellectual property rights		149		10		(85	)					64			138		1,275		1,137
Concessions, licenses, trademarks and similar items		733		20		(153	)					71			671		2,403		1,732
Service concession arrangements		3,322		268		(121	)					(57	)		3,412		5,958		2,546
Intangible assets in progress and advances		580		83								(82	)		581		584		3
Other intangible assets		1,733		9		(136	)					20			1,626		2,035		409
		7,488		1,663		(2,110	)					18			7,059		14,514		7,455
Intangible assets with indefinite useful lives
Goodwill		3,531							15			864			4,410
		11,019		1,663		(2,110	)		15			882			11,469

Exploration expenditures in the amount of euro 631 million mainly related to license acquisition costs that are amortized on a straight-line basis over the contractual term of the exploration lease or fully written off against profit and loss in case of release or when no future activity is planned. Additions for the year included exploration drilling expenditures which were fully amortized as incurred in the amount of euro 1,271 million (euro 1,715 million as of December 31, 2008).

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Concessions, licenses, trademarks and similar items in the amount of euro 671 million primarily comprised of transmission rights for natural gas imported from Algeria (euro 452 million) and concessions for mineral exploration (euro 157 million).

Service concession arrangements in the amount of euro 3,412 primarily refer to the Italian gas distribution activity (euro 3,205 million and euro 3,340 million as of December 31, 2008 and 2009, respectively). Such activity is conducted on the basis of concessions granted by local public entities. At the expiration date of the concession, a compensation is paid, defined by using criteria of a 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. Other negative changes in the net book value of intangible assets (euro 57 million) referred to the reclassification to assets classified as held for sale in the amount of euro 110 million. Government grants recorded as a decrease in service concession arrangements amounted to euro 693 million (euro 657 million as of December 31, 2008).

Other intangible assets with finite useful lives in the amount of euro 1,626 million primarily referred to: (i) customer relationship and order backlog in the amount of euro 1,244 million (euro 1,355 million as of December 31, 2008) recognized after the acquisition of control on 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 in the amount of euro 234 million (euro 208 million as of December 31, 2008); (iii) royalties for the use of licenses by Polimeri Europa SpA in the amount of euro 68 million (euro 72 million as of December 31, 2008); (iv) estimated costs for Eni’s social responsibility projects in relation to oil development programs in Val d’Agri in the amount of euro 38 million (euro 18 million as of December 31, 2008) following commitments made with the Basilicata Region.

The depreciation rates used were as follows:

(%)
Exploration expenditures					14		-	33
Industrial patents and intellectual property rights					20		-	33
Concessions, licenses, trademarks and similar items					3		-	33
Concessions, licenses, trademarks and similar items					2		-	20
Other intangible assets					4		-	25

Other changes of intangible assets with a definite useful live in the amount of euro 18 million include negative currency translation differences of euro 22 million.

Changes in the scope of consolidation related to intangible assets with indefinite useful live (goodwill) in the amount of euro 15 million mainly refers to the acquisition of Seacom SpA (euro 13 million).

The carrying amount of goodwill as of December 31, 2009 was euro 4,410 million (euro 3,531 million as of December 31, 2008). The break-down by operating segment is as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Exploration & Production		243		249
Gas & Power		2,400		3,328
Refining & Marketing		142		84
Engineering & Construction		746		749
		3,531		4,410

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; (ii) value-in-use which is determined by discounting the estimated future cash flows based of the best information available at the moment of the assessment which is derived from: (a) the Company’s four-year plan approved by top management that provides information on the expected oil and gas production, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main monetary variables, including inflation, nominal interest rates and exchange rates. For the subsequent years beyond the four-year plan, a nominal growth rate is used ranging from 0%

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to 2%; (b) the commodity prices have been assessed based on the forward prices prevailing on 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 following rates: (i) in the Exploration & Production and Refining & Marketing and Petrochemicals segments, impairment rates correspond to the Company’s weighted average cost of capital, as adjusted to consider risks specific to each country of activity (adjusted post-tax WACC). For 2009, the adjusted post-tax rates used for impairment testing showed an increase of 0.5 percentage points on average from the previous year as a result of a higher market premium for the equity risk and the country risk. Such increases were partially reduced by decreased nominal interest rates reflected in the cost of borrowings and in rates of assets risk-free. For 2009, the adjusted post-tax rates ranged from 9% to 13.5%; (ii) for the Gas & Power and Engineering & Construction segments, specific adjusted post-tax WACC have been used. 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. Rates used for impairments in the Gas & Power segment have been adjusted to take into consideration risks specific to each country of activity, while rates used in the Engineering & Construction segment have not been adjusted as most of the company assets are not permanently located in a specific country. Rates for the Gas & Power segment have ranged from 7% to 8%, representing a reduction of 0.5 percentage points on average from the previous year, which reflects decreased nominal interest rates, while the equity risk for utilities has remained unchanged. In the Engineering & Construction segment, rates at 8.5% have increased on average by 0.5 percentage points due to higher equity risk; 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 segment

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Domestic gas market		743		766
Foreign gas market		1,342		2,247
- of which European market (Distrigas)		1,248		2,148
Domestic natural gas transportation network		305		305
Other		10		10
		2,400		3,328

Goodwill allocated to the CGU domestic gas market primarily related to goodwill recognized upon the buy-out 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 included commercial margins, forecast sales 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 that factored in revised downward prospects of gas demand growth in Italy. The terminal value was estimated based on the perpetuity method of the last-year-plan assuming a long-term nominal growth rate equal to zero. 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 28.7% on average in the projected commercial margins; (ii) a decrease of 28.7% on average in the projected sales volumes; (iii) an increase of 3.4 percentage points in the discount rate; (iv) a negative nominal growth rate of 4.4%. The recoverable amount of the CGU domestic gas market and the relevant sensitivity analysis were calculated solely on the basis of retail margins, thus excluding wholesale and business client margins (industrial, thermoelectric and others).

Goodwill allocated to the CGU represented by the European gas market was recognized upon acquisition of the Belgian company Distrigas NV that was acquired in two different steps: (i) a controlling interest of 57.24% was acquired in October 2008 and (ii) a mandatory tender offer was finalized on the minorities of Distrigas and the subsequent squeeze-out at the same price of the acquisition of the controlling interest. Such goodwill has been allocated to the CGU that is expected to benefit from the synergies of the acquisition corresponding to the European market that includes the activities of Distrigas and other European marketing activities conducted by the Gas

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& Power Division of Eni SpA. Key assumptions adopted for assessing the recoverable amount of the European market CGU which exceeds its carrying amount included commercial margins, forecast sales volumes, the discount rate and the growth rates adopted to determine the terminal value. The determination of the value-in use is based on the four-year-plan approved by Eni’s top management which assumed full integration of the Distrigas activities with other European activities. The plan also factored in the revised downward prospects for gas demand growth in Europe and consistent projection on marketing margins. The terminal value was estimated based on the perpetuity method of the last-year-plan assuming a long-term nominal growth rate equal to 1.6%. The excess of the recoverable amount of the European 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 40.9% on average in the projected marketing margins; (ii) a decrease of 40.9% on average in planned sales volumes; (iii) an increase of 3.9 percentage points in the discount rate; (iv) a negative nominal growth rate of 4.0%.

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 price 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.

Engineering & Construction segment

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Offshore constructions		416		416
Onshore constructions		314		317
Other		16		16
		746		749

The Engineering & Construction segment’s goodwill in the amount of euro 749 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA (euro 711 million).

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 nominal growth rate of 2% applied to the cash flow of the four-year period. The following changes in each of the assumptions, ceteris paribus would cause the headroom of the Offshore construction CGU to be reduced to zero: (i) decrease of 56% of the operating result of the four years of the plan; (ii) increase of 8 percentage points of the discount rate; and (iii) a negative real growth rate.

Changes in each of the assumptions, ceteris paribus 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.

The Exploration & Production and the Refining & Marketing segments tested their goodwill, yielding the following results: (i) in the Exploration & Production segment (euro 249 million of carrying amount), management believes that there are no reasonably possible changes in the pricing environment and production/cost profiles that would cause the headroom of the relevant CGUs to be reduced to zero. Goodwill mainly refers to the portion of the acquisition cost that was not allocated to proved or unproved mineral interests from the business combinations of Lasmo, Burren Energy (Congo) and First Calgary. The change in goodwill recorded by the segment in the period derived from the completion of the purchase price allocation of First Calgary in the amount of euro 65 million; (ii) in the Refining & Marketing segment (euro 84 million), the Company recorded an impairment charge in the amount of euro 58 million, of which euro 48 million related to goodwill allocated to the fuel retail business assets and aviation fuel supply business recently acquired in Central-Eastern Europe driven by lower expectations for margins/volumes due to decreased fuel demand caused by the economic downturn and loss of market share and an impairment charge in the amount of euro 10 million related to goodwill allocated to minor assets. Net of this impairment, the residual goodwill primarily referred to the retail network CGUs which relates to the acquisitions in Czech Republic, Hungary and Slovakia.

Other changes in intangible assets with indefinite useful lives in the amount of euro 864 million include the accounting of goodwill related to the acquisition of 42.757% of Distrigas NV, following the finalization of the mandatory tender offer for the minorities with a 41.617% adhesion of the share capital, including the 31.25%

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interest of Publigaz SCRL, the other major stakeholder of Distrigas, and the 1.14% interest through the squeeze-out procedure (euro 903 million) and, as a decrease, the impairments in the amount of euro 58 million related to the Refining & Marketing segment as described above.


11 Investments

Investments accounted for using the equity method
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, 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
Dec. 31, 2009
Investments in unconsolidated entities controlled by Eni		177		1		42		(4	)		(8	)		(3	)		12			217
Joint ventures		3,257		25		478		(81	)		(254	)		(54	)		(44	)		3,327
Associates		2,037		200		173		(156	)		(122	)		(31	)		183			2,284
		5,471		226		693		(241	)		(384	)		(88	)		151			5,828

Acquisitions and subscriptions in the amount of euro 226 million related to the increase in subscription of capital in the amount of euro 224 million, of which euro 181 million related to Angola LNG Ltd.

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, 2008		Dec. 31, 2009

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 %

Galp Energia SGPS SA		39		88		33.34		116		64		33.34
Unión Fenosa Gas SA		200		185		50.00		108		138		50.00
Artic Russia BV		29				60.00		103				60.00
Trans Austria Gasleitung GmbH		39		28		89.00		84		22		89.00
Eni BTC Ltd		16				100.00		35				100.00
Blue Stream Pipeline Co BV		34				50.00		33				50.00
United Gas Derivatives Co		107		127		33.33		24		40		24.55	(*)
EnBW Eni Verwaltungsgesellschaft mbH		40		22		50.00		15				50.00
Supermetanol CA		39		34		34.51		6		13		34.51
Other investments		218		231				169		107
		761		715				693		384

(*)		Equity ratio 33.33.

Share of loss of equity-accounted investments in the amount of euro 241 million primarily relates to Ceska Rafinerska AS (euro 140 million) as a result of an impairment test on the refinery, Transmediterranean Pipeline Co Ltd (euro 30 million) and Super Octanos CA (euro 21 million) following the impairment on the relevant CGU mainly due to the negative trends in exchange rates.

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Other changes in the amount of euro 151 million include the reclassification from receivables made for operating financing purposes associated with the contribution of the Venezuelan activities of Corocoro (euro 153 million) to PetroSucre SA. Also an increase was recorded upon reclassification from assets classified as held for sale of Fertilizantes Nitrogenados de Oriente (euro 68 million). A decrease was recorded as a capital reimbursement was made by the joint venture Artic Russia BV (euro 111 million) upon divestment of a 51% stake in the 60-40% owned joint-venture OOO SeverEnergia following the exercise of the call option by Gazprom on September 23, 2009. The transaction is worth U.S. $940 million net to Eni. Eni collected the first tranche of the price corresponding to approximately 25% of the whole amount for euro 155 million (or U.S. $230 million at the EUR/USD exchange rate of 1.48 as of the transaction date). A gain was recognized in the profit and loss on equity-accounted evaluation of the investments in Artic Russia BV in the amount of euro 103, of which euro 100 million related to the contractual remuneration at an annual rate of 9.4% accruing on the initial investment in the venture when it was acquired on April 4, 2007 in accordance with the arrangements between Eni and Gazprom.

The following table sets out the net carrying amount relating to equity-accounted:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

		Net carrying amount		Eni’s interest %		Net carrying amount		Eni’s interest %

Investments in unconsolidated entities controlled by Eni:
- Eni BTC Ltd		62		100.00		93		100.00
- Other investments (1)		115				124
		177				217
Joint ventures:
- Artic Russia BV		895		60.00		918		60.00
- Unión Fenosa Gas SA		499		50.00		473		50.00
- Blue Stream Pipeline Co BV		351		50.00		371		50.00
- EnBW Eni Verwaltungsgesellschaft mbH		268		50.00		284		50.00
- Azienda Energia e Servizi Torino SpA		166		49.00		170		49.00
- Eteria Parohis Aeriou Thessalonikis AE		158		49.00		161		49.00
- Toscana Energia SpA		136		49.38		143		49.38
- Raffineria di Milazzo ScpA		128		50.00		128		50.00
- Trans Austria Gasleitung GmbH		109		89.00		170		89.00
- Super Octanos CA		90		49.00		66		49.00
- Supermetanol CA		90		34.51		80		34.51
- Unimar Llc		65		50.00		72		50.00
- Eteria Parohis Aeriou Thessalias AE		42		49.00		43		49.00
- Starstroi Llc		19		50.00		31		50.00
- Transmediterranean Pipeline Co Ltd		40		50.00		8		50.00
- Transitgas AG		33		46.00		33		46.00
- Altergaz SA		25		38.91		28		41.62
- Other investments (1)		143				148
		3,257				3,327
Associates:
- Galp Energia SGPS SA		862		33.34		914		33.34
- Angola LNG Ltd		453		13.60		612		13.60
- Ceska Rafinerska AS		323		32.44		184		32.44
- PetroSucre SA		19		26.00		176		26.00
- United Gas Derivatives Co		128		33.33		84		24.55	(2)
- Fertilizantes Nitrogenados de Oriente CEC		68		20.00		68		20.00
- ACAM Gas SpA		46		49.00		47		49.00
- Distribuidora de Gas del Centro SA		32		31.35		29		31.35
- Other investments (1)		106				170
		2,037				2,284
		5,471				5,828

(1)		Each individual amount included herein did not exceed euro 25 million.
(2)		Equity ratio 33.33.

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The net carrying amount of investments in unconsolidated entities controlled by Eni, joint ventures and associates include the differences between the purchase price and Eni’s equity in investments in the amount of euro 521 million. Such differences primarily related to Unión Fenosa Gas SA (euro 195 million), EnBW - Eni Verwaltungsgesellschaft mbH (euro 181 million) and Galp Energia SGPS SA (euro 106 million).

The fair value of listed investments was as follows:

		Shares		Ownership (%)		Price per share (euro)		Fair value (euro million)

Galp Energia SGPS SA		276,472,161		33.34		12.08		3,340
Altergaz SA		1,123,954		41.62		29.80		33

The table below sets out the provisions for losses included in the provisions for contingencies in the amount of euro 170 million (euro 119 million as of December 31, 2008), which primarily relate to the following equity-accounted investments:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Industria Siciliana Acido Fosforico - ISAF SpA (under liquidation)		27		64
Cardon IV SA		11		32
Polimeri Europa Elastomeres France SA (under liquidation)		31		32
Charville - Consultores e Serviços Lda		33		21
Southern Gas Constructors Ltd		17		13
Other investments				8
		119		170

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, 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
Dec. 31, 2009
Investments in unconsolidated entities controlled by Eni		30				(1	)		15			44		55		11
Associates		4							4			8		8		0
Other investments		376		4		(7	)		(9	)		364		371		7
		410		4		(8	)		10			416		434		18

Investments in unconsolidated entities controlled by Eni and associates are stated at cost net of impairment losses. Other investments, for which fair value cannot be reliably determined, were recognized at cost and adjusted for impairment losses.

 

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The net carrying amount of other investments in the amount of euro 416 million (euro 410 million as of December 31, 2008) relates to the following entities:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

		Net carrying amount		Eni’s interest %		Net carrying amount		Eni’s interest %

Investments in unconsolidated entities controlled by Eni (*)		30				44
Associates		4				8
Other investments:
- Interconnector (UK) Ltd		135		16.06		134		16.06
- Nigeria LNG Ltd		85		10.40		82		10.40
- Darwin LNG Pty Ltd		83		10.99		78		10.99
- Other (*)		73				70
		376				364
		410				416

(*)		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 41 million (euro 44 million as of December 31, 2008) and were primarily in relation to the following entities:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Burren Energy Ship Management Ltd		17		25
Caspian Pipeline Consortium R - Closed Joint Stock Co		24		15
Other investments		3		1
		44		41

Other information about investments
The following table summarizes key financial data, net to Eni, as disclosed in the latest available financial statements of unconsolidated entities controlled by Eni, joint ventures and associates:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Unconsolidated entities controlled by Eni

Joint ventures

Associates

Unconsolidated entities controlled by Eni

Joint ventures

Associates

Total assets		1,361		7,761		4,020		2,215			6,981		4,218
Total liabilities		1,230		4,565		1,958		2,081			3,721		1,929
Net sales from operations		134		5,303		5,067		65			3,936		5,718
Operating profit		2		736		702		(48	)		564		141
Net profit		20		490		690		(9	)		474		101

The total assets and liabilities of unconsolidated controlled entities of euro 2,215 million and euro 2,081 million respectively (euro 1,361 million and euro 1,230 million as of December 31, 2008) concerned for euro 1,873 million and euro 1,860 million (euro 923 million and euro 923 million as of December 31, 2008) entities for which the consolidation does not produce significant effects. The residual amount referred to controlled entities which are not consolidated due to their immateriality based on the criteria of significance indicated in the "Basis of presentation".

 

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12 Other financial assets
Other financing receivables were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Receivables for financing operating activities		1,084		1,112
Securities held for operating purposes		50		36
		1,134		1,148

Financing receivables are presented net of the allowance for impairment losses in the amount of euro 29 million (euro 26 million as of December 31, 2008).

Operating financing receivables in the amount of euro 1,112 million (euro 1,084 million as of December 31, 2008) primarily consist of loans entered into by the Exploration & Production segment (euro 580 million), Gas & Power segment (euro 311 million) and Refining & Marketing segment (euro 111 million), as well as receivables for financial leasing of euro 97 million (euro 128 million as of December 31, 2008). Receivables for financial leasing related to the disposal of the Belgian gas network by Finpipe GIE, are included in the consolidation area after the acquisition of control by 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, interests 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		77		20		116
Interests		6		11		1		18
Undiscounted value of future lease payments		25		88		21		134

Receivables with a maturity date within one year are shown in current assets in the trade receivables for operating purposes - current portion of long-term receivables in Note 3 – Trade and other receivables.

Receivables in currencies other than euro amounted to euro 716 million (euro 827 million as of December 31, 2008).

Receivables due beyond five years amounted to euro 460 million (euro 617 million as of December 31, 2008).

Securities in the amount of euro 36 million (euro 50 million as of December 31, 2008), designated as held-to-maturity investments, are listed securities, issued by the Italian Government (euro 21 million) and by foreign governments (euro 15 million). The decrease of euro 14 million relates 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 1.0% to 4.5% (1.9% and 3.9% as of December 31, 2008). The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in Note 36 – Transactions with related parties.

 

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13 Deferred tax assets
Deferred tax assets were recognized net of deferred tax liabilities able to be offset in the amount of euro 3,764 million (euro 3,468 million as of December 31, 2008).

(euro million)

Value at Dec. 31, 2008

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2009

2,912

1,715

(1,078

)

(28

)

37

3,558

Deferred tax assets are described in Note 23 – Deferred tax liabilities.


14 Other non-current receivables
The following table provides an analysis of other non-current receivables:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Tax receivables from:
- income tax		24		18
- interest on tax credits		58		55
- Value Added Tax (VAT)		2
		84		73
- foreign tax authorities		28		39
		112		112
Other receivables:
- in relation to disposals		780		710
- other non-current receivables		268		215
		1,048		925
Fair value of non-hedging derivatives		480		339
Fair value of cash flow hedge derivative instruments		197		129
Other asset		44		433
		1,881		1,938

Other receivables related to disposals in the amount of euro 710 million relate to: (i) a receivable of euro 421 million recognized upon the agreement signed with the Republic of Venezuela whereby Eni will receive a cash compensation for the expropriated Dación assets, part of which was already collected. Eni is set to collect seven annual installments which yield interest income from the date of the agreement. The 2009 installment of euro 71 million ($104 million) was paid through an equivalent assignment of hydrocarbons (compensation in-kind); (ii) a receivable of euro 279 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 were effective starting from January 1, 2008.

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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, 2008		Dec. 31, 2009

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Interest Currency Swap		106		403		120		112		458		197
Currency swap		1		1		11		7		333		33
Other		29		13		48
		136		417		179		119		791		230
Non-hedging derivatives on interest rate
Interest rate swap		27		217		403		46		677		563
		27		217		403		46		677		563
Non-hedging derivatives on commodities
Over the counter		317		207		859		172		540		659
Other								2		37
		317		207		859		174		577		659
		480		841		1,441		339		2,045		1,452

The fair value of the derivative contracts is determined using market quotations provided by primary information providers, or in the absence of such market information, the appropriate valuation methods generally accepted in the marketplace.

Fair values of non-hedging derivatives in the amount of euro 339 million (euro 480 million as of December 31, 2008) consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.

Fair value of the cash flow hedge derivatives in the amount of euro 129 million refers to Distrigas NV. Further information on cash flow hedge derivatives is provided in Note 19 – Other current liabilities. Fair value related to the contracts expiring beyond 2010 is provided in Note 24 – Other non-current liabilities; fair value related to the contracts expiring in 2010 is provided in Note 7 – Other current assets and in Note 19 – Other current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and in Note 30 – Operating expenses.

The nominal value of cash flow hedge derivatives relating to purchase and sale commitments amounted to euro 29 million and euro 427 million, respectively.

Information on the hedged risks and the hedging policies is provided in Note 28 – Guarantees, commitments and risks.

Other asset in the amount of euro 433 million (euro 44 million as of December 31, 2008) included a deferred cost that relates to amounts of gas which were collected below minimum take quantities for the year provided by take-or-pay clauses contained in certain long-term gas purchase contracts. Those volumes were recorded to offset a trade payable for an amount of euro 255 million based on the contractual purchase price formula provided in the relevant contractual arrangements and the contractual percentage of advance, as aligned to their net realizable value as of year end. The Company expects to collect the underlying gas volumes over a period longer than the next twelve months.

 

 

 

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Current liabilities

15 Short-term debt
Short-term debt was as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Banks		2,411		683
Ordinary bonds		3,663		2,718
Other financial institutions		285		144
		6,359		3,545

Short-term debt decreased by euro 2,814 million primarily due to the balance of repayments and new proceeds (euro 2,889 million), partially offset by currency translation differences (euro 97 million). Debt comprised of commercial paper in the amount of euro 2,718 million (euro 3,663 million as of December 31, 2008) which was mainly issued by the financial company Eni Finance USA Inc (euro 2,020 million) and Eni Coordination Center SA (euro 698 million).

Short-term debt per currency is shown in the table below:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Euro		3,801		1,143
U.S. dollar		1,332		2,321
Other currencies		1,226		81
		6,359		3,545

In 2009, the weighted average interest rate on short-term debt was 0.8% (4.2% in 2008).

As of December 31, 2009, Eni had undrawn committed and uncommitted borrowing facilities available in the amount of euro 2,241 million and euro 9,533 million, respectively (euro 3,313 million and euro 7,696 million as of December 31, 2008). These facilities were under interest rates that reflected market conditions. Charges in unutilized facilities were not significant.


16 Trade and other payables
Trade and other payables were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Trade payables		12,590		10,078
Advances		2,916		3,230
Other payables:
- related to capital expenditures		1,716		1,541
- others		3,293		4,325
		5,009		5,866
		20,515		19,174

The decrease in trade payables in the amount of euro 2,512 million was primarily related to the Gas & Power segment (euro 1,640 million), the Engineering & Construction segment (euro 619 million), the Exploration & Production segment (euro 566 million) which was offset by an increase in the Refining & Marketing segment (euro 266 million).

Advances in the amount of euro 3,230 million (euro 2,916 million as of December 31, 2008) were related to advances on contract work in progress in the amount of euro 2,590 million (euro 2,516 million as of December 31, 2008) and other advances in the amount of euro 640 million (euro 400 million as of December 31, 2008).

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Advances on contract work in progress related to the Engineering & Construction segment.

Other payables were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Payables due to:
- joint venture operators in exploration and production activities		2,007		2,305
- suppliers in relation to investments		1,057		809
- non-financial government entities		441		661
- employees		400		451
- social security entities		284		292
		4,189		4,518
Other payables		820		1,348
		5,009		5,866

Payables with related parties are described in Note 36 – 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.


17 Income taxes payable
Income taxes payable were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Italian subsidiaries		808		363
Foreign subsidiaries		1,141		928
		1,949		1,291

Income taxes payable by Italian subsidiaries were affected by the fair value valuation of cash flow hedging derivatives (euro 137 million). Further information is provided in Note 19 – Other current liabilities.


18 Other taxes payable
Other taxes payable were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Excise and customs duties		920		832
Other taxes and duties		740		599
		1,660		1,431

 

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19 Other current liabilities
Other current liabilities were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Fair value of non-hedging derivatives		1,418		691
Fair value of cash flow hedge derivatives		452		680
Other liabilities		1,993		485
		3,863		1,856

Fair value of non-hedging derivative contracts was as follows:

		Dec. 31, 2008		Dec. 31, 2009

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Currency swap		211		1,234		2,379		113		3,044		2,487
Interest currency swap		78		694		60		8		113
Other		299		101		1,181		135		107		684
		588		2,029		3,620		256		3,264		3,171
Non-hedging derivatives on interest rate
Interest rate swap		5		500				15				816
		5		500				15				816
Non-hedging derivatives on commodities
Over the counter		769		2,528		191		415		1,244		549
Other		56		66		119		5		2		54
		825		2,594		310		420		1,246		603
		1,418		5,123		3,930		691		4,510		4,590

Fair value of derivative contracts was determined by using market quotations given by primary information providers, or, absent market information, on the basis of valuation models generally accepted in the marketplace.

Fair values of non-hedging derivatives in the amount of euro 691 million (euro 1,418 million as of December 31, 2008) consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.

The fair value of cash flow hedges amounted to euro 680 million (euro 452 million as of December 31, 2008) and related to Exploration & Production segment in the amount of euro 369 million and Distrigas NV in the amount of euro 311 million (euro 37 million and euro 415 million as of December 31, 2008, respectively). Fair value related to the Exploration & Production segment referred to the fair value of the future sale agreements of the proved oil reserves with deadlines in 2010. Those derivatives were entered into to hedge exposure to variability in future cash flows deriving from the sales during the 2008-2011 period of approximately 2% of Eni’s proved reserves as of December 31, 2006 corresponding to 125.7 mmBBL, decreasing to 37.5 mmBBL as of December 31, 2009 due to transactions settled in the past 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. The Distrigas NV derivatives were designated to hedge surpluses or deficits of gas to achieve a proper balance in the gas portfolio.

Fair value of contracts expiring by 2010 is provided in Note 7 – Other current assets; fair value of contracts expiring beyond 2010 is provided in Note 24 – Other non-current liabilities and in Note 14 – Other non-current assets. The effects of the evaluation at fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and in Note 30 – Operating expenses.

The nominal value of cash flow hedge derivatives relating to purchase and sale commitments amount to euro 1,882 million and euro 272 million, respectively (euro 989 million and euro 895 million as of December 31, 2008, respectively).

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Information on the hedged risks and the hedging policies is provided in Note 28 – Guarantees, commitments and risks.

The decrease of other liabilities in the amount of euro 1,508 million mainly relate to the extinction of the euro 1,495 million put option exercised by Publigaz. Eni granted the put option to Publigaz (the Distrigas minority shareholder) to divest its 31.25% stake in Distrigas NV to Eni on the same per-share price of the mandatory tender offer to minorities as part of the Distrigas NV acquisition. The relevant liability was recognized with a corresponding entry in a reserve within equity.


Non-current liabilities

20 Long-term debt and current maturities 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		2008		2009		Current maturity 2010		2011		2012		2013		2014		After		Total

Banks		2010-2029		7,003		9,056		2,028		1,106		3,559		323		1,122		918		7,028
Ordinary bonds		2010-2037		6,843		11,687		1,111		141		38		1,589		1,314		7,494		10,576
Other financial institutions		2010-2021		632		512		52		95		63		55		51		196		460
				14,478		21,255		3,191		1,342		3,660		1,967		2,487		8,608		18,064

Long-term debt, including the current portion of long-term debt, of euro 21,255 million (euro 14,478 million as of December 31, 2008) increased by euro 6,777 million. The increase mainly reflected the balance of payments and new proceeds of euro 6,730 million as well as translation differences arising on debt taken on by euro-reporting subsidiaries denominated in a foreign currency which are translated into euros at the year-end exchange rates (euro 100 million). These increases were offset by currency translation differences resulting from the translation of financial statements denominated in currencies other than euro (euro 74 million).

Debt from banks in the amount of euro 9,056 million mainly relate to committed and uncommitted borrowing facilities in the amount of euro 4,030 million.

Debt from other financial institutions in the amount of euro 512 million (euro 632 million as of December 31, 2008) included euro 24 million of finance lease transactions (euro 161 million as of December 31, 2008). The decrease of euro 137 million mainly referred to the exercise of the option to purchase a drilling rig by the Engineering & Construction segment.

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 the maintenance of a minimum level of rating. According to the agreements, in case the latter condition is impaired, the Company shall provide new guarantees which the European Investment Bank finds to be satisfactory. As of December 31, 2008 and 2009, the amount of short and long-term debt subject to restrictive covenants was euro 1,323 million and euro 1,508 million, respectively. Eni considers that non-compliance with the above mentioned covenants does not produce significant effects. Furthermore, Saipem SpA entered into certain borrowing facilities in the amount of euro 75 million (the same amount as of December 31, 2008) 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 in the amount of euro 11,687 million consisted of bonds issued through the Euro Medium Term Notes Program for a total of euro 9,419 million and other bonds for a total of euro 2,268 million.

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The following table analyzes bonds per issuing entity, maturity date, interest rate and currency as of December 31, 2009:

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		58			1,558		EUR				2016				5.000
- Eni SpA		1,500		44			1,544		EUR				2013				4.625
- Eni SpA		1,500		8			1,508		EUR				2019				4.125
- Eni SpA		1,250		66			1,316		EUR				2014				5.875
- Eni SpA		1,250		(4	)		1,246		EUR				2017				4.750
- Eni Coordination Center SA		733		6			739		GBP		2010		2019		4.875		6.125
- Eni SpA		500		17			517		EUR				2010				6.125
- Eni Coordination Center SA		350		10			360		EUR		2010		2028		2.876		5.600
- Eni Coordination Center SA		346		2			348		YEN		2012		2037		1.150		2.810
- Eni Coordination Center SA		176		4			180		USD		2013		2015		4.450		4.800
- Eni Coordination Center SA		41		(1	)		40		EUR		2011		2015				variable
- Eni Coordination Center SA		34					34		CHF				2010				2.043
- Eni Coordination Center SA		31		(2	)		29		USD				2013				variable
		9,211		208			9,419
Other bonds:
- Eni SpA		1,000		7			1,007		EUR				2015				4.000
- Eni SpA		1,000		(15	)		985		EUR				2015				variable
- Eni USA Inc		277		(3	)		274		USD				2027				7.300
- Eni UK Holding Plc		2					2		GBP				2013				variable
		2,279		(11	)		2,268
		11,490		197			11,687

As of December 31, 2009 bonds maturing within 18 months (euro 993 million) were issued by Eni Coordination Center SA in the amount of euro 476 million and by Eni SpA in the amount of euro 517 million. During 2009, Eni SpA issued bonds in the amount of euro 5,058 million.

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, 2008 (euro million)		Average rate (%)		Dec. 31, 2009 (euro million)		Average rate (%)

Euro		12,284		4.2		19,345		3.9
U.S. dollar		912		6.1		779		3.9
British pound		859		6.2		742		5.2
Japanese yen		367		2.0		348		2.0
Other currencies		56		3.8		41		3.0
		14,478				21,255

As of December 31, 2009 Eni had undrawn committed long-term borrowing facilities in the amount of euro 2,850 million (euro 1,850 million as of December 31, 2008). 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 22,320 million (euro 15,247 million as of December 31, 2008) and consisted of the following:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Ordinary bonds		7,505		12,618
Banks		7,056		9,152
Other financial institutions		686		550
		15,247		22,320

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Fair value was calculated by discounting the expected future cash flows at rates ranging from 1.0% to 4.5% (1.4% and 3.9% as of December 31, 2008).

As of December 31, 2009 Eni did not pledge restricted deposits as collateral against its borrowings (euro 151 million as of December 31, 2008).

Analysis of net borrowings, as defined in the "Item 5 – Operating and Financial Review and Prospects", was as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Current

Non-current

Total

Current

Non-current

Total

A. Cash and cash equivalents		1,939				1,939		1,608				1,608
B. Available-for-sale securities		185				185		64				64
C. Liquidity (A+B)		2,124				2,124		1,672				1,672
D. Financing receivables		337				337		73				73
E. Short-term debt towards banks		2,411				2,411		683				683
F. Long-term debt towards banks		147		6,856		7,003		2,028		7,028		9,056
G. Bonds		360		6,483		6,843		1,111		10,576		11,687
H. Short-term debt towards related parties		153				153		147				147
I. Long-term debt towards related parties				9		9
L. Other short-term debt		3,795				3,795		2,715				2,715
M. Other long-term debt		42		581		623		52		460		512
N. Total borrowings (E+F+G+H+I+L+M)		6,908		13,929		20,837		6,736		18,064		24,800
O. Net borrowings (N-C-D)		4,447		13,929		18,376		4,991		18,064		23,055

Available-for-sale securities in the amount of euro 64 million (euro 185 million as of December 31, 2008) 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 320 million (euro 360 million as of December 31, 2008), of which euro 284 million (euro 302 million as of December 31, 2008) were held to provide coverage of technical reserves for Eni’s insurance company, Eni Insurance Ltd.

Financing receivables in the amount of euro 73 million (euro 337 million as of December 31, 2008) were held for non-operating purposes.

Not included in the calculation above were financing receivables held for operating purposes amounting to euro 452 million (euro 487 million as of December 31, 2008), of which euro 245 million (euro 399 million as of December 31, 2008) were in respect of securities granted to unconsolidated subsidiaries, joint ventures and associates primarily in relation to the implementation of certain capital projects and a euro 179 million cash deposit (euro 47 million as of December 31, 2008) to provide coverage for Eni Insurance Ltd technical reserves. As of December 31, 2008, current financial receivables in the amount of euro 173 million referred to a restricted deposit held by Eni Lasmo Plc as a guarantee of a debenture.

 

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21 Provisions for contingencies
Provisions for contingencies were as follows:

(euro million)

Value at Dec. 31, 2008

Additions

Changes of estimated expenditures

Accretion discount

Reversal of utilized provisions

Reversal of unutilized provisions

Other changes

Value at Dec. 31, 2009

Provision for site restoration and abandonment		4,574				317		212			(191	)		(5	)		(110	)		4,797
Provision for environmental risks		1,980		280							(249	)		(22	)		(53	)		1,936
Provision for legal and other proceedings		812		372							(62	)		(39	)		85			1,168
Loss adjustments and actuarial provisions for Eni's insurance companies		404		135													(25	)		514
Provisions for the supply of goods		308		35				10												353
Provision for taxes		260		46										(1	)		(9	)		296
Provision for losses on investments		163		96										(39	)		(9	)		211
Provision for onerous contracts		4		115							(26	)					(3	)		90
Provision for OIL insurance		72		9							(1	)		(1	)					79
Other (*)		929		306		22		(4	)		(298	)		(72	)		(8	)		875
		9,506		1,394		339		218			(827	)		(179	)		(132	)		10,319

(*)		Each individual amount included herein does not exceed euro 50 million.

Provision for site restoration and abandonment in the amount of euro 4,797 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 4,500 million). The increase in the provision for the year amounted to euro 317 million and was primarily due to changes in the estimates of future costs made by Eni Petroleum Co Inc (euro 153 million), Eni UK Ltd (euro 76 million) and Eni SpA (euro 51 million). Also an amount of euro 212 million was recognized through profit and loss as the accretion charge for the period. The discount rates adopted ranged from 1.9% to 8.8% (from 3.3% to 6.2% for the year-ended December 31, 2008). Other changes in the amount of euro 110 million mainly related to the reclassification of the liabilities directly associated with assets held for sale (euro 188 million).

Offsetting this effect were negative currency translation differences which resulted from the translation of financial statements denominated in currencies other than euro (euro 70 million).

Provision for environmental risks in the amount of euro 1,936 million primarily related to the estimated future costs of remediation in accordance with existing laws and regulations and the estimated costs of reclamation and restoration sanctioned by the competent authorities. There provisions mainly relate to Syndial SpA (euro 1,412 million) and to the Refining & Marketing segment (euro 394 million). The increases in the provision in the amount of euro 280 million were primarily related to Syndial SpA (euro 186 million) and the Refining & Marketing segment (euro 68 million). Decreases in the amount of euro 249 million were related to the reversal of utilized provisions primarily by the Refining & Marketing segment (euro 125 million) and Syndial SpA (euro 97 million).

Provision for legal and other proceedings in the amount of euro 1,168 million primarily included charges expected for the 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 related to the Gas & Power segment (euro 476 million), Engineering & Construction segment (euro 278 million), Syndial SpA (euro 220 million), Eni Corporate (euro 79 million) and the Petrochemical segment (euro 34 million). The increases in the provision in the amount of euro 372 million includes the estimate of a non-recurring item represented by a charge amounting to euro 250 million that was estimated based on management’s best knowledge of the possible resolution of the TSKJ matter with U.S. Authorities. The matter is fully disclosed in Note 28 – Guarantees, commitments and risks – Legal Proceedings. The charge is recognized in the segment results of the Engineering & Construction business as it relates to a project that was executed in Nigeria by the TSKJ joint venture. At the time of the project, the venture was participated by Snamprogetti Netherlands BV that was controlled by Snamprogetti SpA that was subsequently divested by the parent company Eni SpA to the subsidiary Saipem. On the occasion of the divestiture, Eni agreed to indemnify Saipem of all possible claims that might arise in connection with Snamprogetti involvement in the TSKJ venture. As a result, the future monetary settlement of the provision will be incurred by Eni SpA and Saipem’s minorities will be left unaffected altogether.

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Loss adjustments and actuarial provisions for Eni’s insurance companies in the amount of euro 514 million represent the liabilities accrued for claims on insurance policies underwritten by Eni’s insurance company, Eni Insurance Ltd.

Provisions for the supply of goods in the amount of euro 353 million include the estimated costs of the supply contracts.

Provision for taxes in the amount of euro 296 million primarily included charges for unsettled tax claims in connection with uncertain applications of tax regulations for foreign subsidiaries of the Exploration & Production segment (euro 176 million) and the Engineering & Construction segment (euro 66 million).

Provision for losses on investments in the amount of euro 211 million was made with respect to losses from investments in entities incurred to date, where the losses exceed the carrying amount of the investments.

Provision for onerous contracts in the amount of euro 90 million relate to contracts for which the termination or execution costs exceed the relevant benefits.

Provision for OIL insurance cover in the amount of euro 79 million include a mutual insurance provision related to future increase of insurance charges, as a result of accidents that occurred in past periods that will be paid in the next 5 years by Eni for participating in the mutual insurance of Oil Insurance Ltd.


22 Provisions for employee benefits
Provisions for employee benefits were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

TFR		458		445
Foreign pension plans		223		204
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans		98		107
Other benefits		168		188
		947		944

Provisions for indemnities upon termination of employment primarily relate to the provisions accrued by Italian companies for employee termination indemnities ("TFR"), which are determined using actuarial techniques and is regulated by Article 2120 of the Italian Civil Code.

The indemnity is paid upon retirement as a lump sum payment in the amount which corresponds to the total provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in regime, starting from January 1, 2007 the amount already then accrued and future benefits will be put in pension funds or the treasury fund held by the Italian administration for post-retirement benefits (INPS). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, 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 of 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 consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to retirement.

Group companies provide healthcare benefits to retired managers. Liability for these plans (FISDE and other foreign healthcare 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 probability of the company reaching

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planned targets and employee reaching 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, consists of the following:

	Foreign pension plans

(euro million)

TFR

Gross liability

Plan assets

FISDE and other foreign medical plans

Other benefits

Total

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
2009
Current value of benefit liabilities and plan assets at beginning of year		443			802			(453	)		94			168			1,054
Current cost					27						2			45			74
Interest cost		26			22						6			6			60
Amendments					81						10						91
Expected return on plan assets								(16	)								(16	)
Employee contributions					1			(42	)								(41	)
Actuarial gains (losses)		18			301			(16	)		9			4			316
Benefits paid		(41	)		(45	)		22			(7	)		(39	)		(110	)
Curtailments and settlements					(15	)		14									(1	)
Currency translation differences and other changes		1			(28	)		(9	)		1			4			(31	)
Current value of benefit liabilities and plan assets at end of year		447			1,146			(500	)		115			188			1,396

The gross liability for foreign employee pension plans in the amount of euro 1,146 million (euro 802 million as of December 31, 2008) include the liabilities related to joint ventures operating in exploration and production activities in the amount of euro 77 million and euro 62 million as of December 31, 2008 and 2009, respectively. A receivable of an amount equivalent to such liability was recorded. Other benefits in the amount of euro 188 million (euro 168 million as of December 31, 2008) mainly relate to the deferred monetary incentive plan in the amount of euro 119 million (euro 107 million as of December 31, 2008) and Jubilee awards in the amount of euro 52 million (euro 47 million as of December 31, 2008).

 

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The reconciliation analysis of benefit obligations and plan assets was as follows:

		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

(euro million)

Dec. 31, 2008

Dec. 31, 2009

Dec. 31, 2008

Dec. 31, 2009

Dec. 31, 2008

Dec. 31, 2009

Dec. 31, 2008

Dec. 31, 2009

Present value of benefit obligations with plan assets							610			935
Present value of plan assets							(453	)		(500	)
Net present value of benefit obligations with plan assets							157			435
Present value of benefit obligations without plan assets		443		447			192			211			94		115			168		188
Actuarial gains (losses) not recognized		15		(2	)		(126	)		(442	)		4		(6	)
Past service cost not recognized															(2	)
Net liabilities recognized in provisions for employee benefits		458		445			223			204			98		107			168		188

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

2008
Current cost					21			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
2009
Current cost					27			2			45			74
Interest cost		26			22			6			6			60
Expected return on plan assets					(16	)								(16	)
Amortization of actuarial gains (losses)					10			7			4			21
Effect of curtailments and settlements					1						(3	)		(2	)
		26			44			15			52			137

The main actuarial assumptions used in the evaluation of post-retirement benefit obligations at year end and in the estimate of costs expected for 2010 were as follows:

(%)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

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
2009
Discount rate		5.0		2.7-11.0		5.0		2.0-5.0
Expected return rate on plan assets				4.0-13.0
Rate of compensation increase		3.0		2.7-14.0
Rate of price inflation		2.0		0.9-10.0		2.0		2.0

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With regards to Italian plans, demographic tables prepared by Ragioneria Generale dello Stato (RG48) were used. 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		10.0		6.0-7.5
Bonds		28.8		2.4-13.0
Real estate		1.6		6.0-7.5
Other		59.6		0.5-13.0
Total		100.0

The effective return of the plan assets amounted to zero (a cost in the amount of euro 77 million for the year ended December 31, 2008).

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		14		(12	)

The amount expected to be accrued for defined benefit plans in 2010 amounted to euro 88 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

2008
Impact on net benefit obligation		7			15			3		1
Impact on plan assets					(62	)
2009
Impact on net benefit obligation		(7	)		4			3		2
Impact on plan assets					(16	)

 

23 Deferred tax liabilities
Deferred tax liabilities were recognized net of offsettable deferred tax assets in the amount of euro 3,764 million (euro 3,468 million as of December 31, 2008).

(euro million)

Value at Dec. 31, 2008

Additions

Deductions

Changes in the scope of consolidation

Currency translation differences

Other changes

Value at Dec. 31, 2009

5,784

631

(1,434

)

3

(22

)

(55

)

4,907

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Deferred tax assets and liabilities consisted of the following:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Deferred tax liabilities		9,252			8,671
Deferred tax assets available for offset		(3,468	)		(3,764	)
		5,784			4,907
Deferred tax assets not available for offset		(2,912	)		(3,558	)
		2,872			1,349

The most significant temporary differences giving rise to net deferred tax liabilities were as follows:

(euro million)

Value at Dec. 31, 2008

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2009

Deferred tax liabilities:
- accelerated tax depreciation		5,366			238			(392	)		(6	)		(34	)		5,172
- site restoration and abandonment (tangible assets)		654			59			(132	)		27			(59	)		549
- capitalized interest expense		173			3			(15	)					(2	)		159
- application of the weighted average cost method in evaluation of inventories		79			31			(91	)					42			61
- other		2,980			300			(804	)		(43	)		297			2,730
		9,252			631			(1,434	)		(22	)		244			8,671
Deferred tax assets:
- site restoration and abandonment (provisions for contingencies)		(1,572	)		(84	)		100			(8	)		79			(1,485	)
- accruals for impairment losses and provisions for contingencies		(1,397	)		(334	)		309						32			(1,390	)
- depreciation and amortization		(910	)		(474	)		140			33			25			(1,186	)
- assets revaluation as per Laws No. 342/2000 and No. 448/2001		(735	)					58									(677	)
- carry-forward tax losses		(57	)		(150	)		40			(7	)					(174	)
- other		(1,709	)		(673	)		431			10			(469	)		(2,410	)
		(6,380	)		(1,715	)		1,078			28			(333	)		(7,322	)
Net deferred tax liabilities		2,872			(1,084	)		(356	)		6			(89	)		1,349

Deferred tax assets are recognized for deductible temporary differences to the extent that it is probable that sufficient taxable profit will be available against which part or all of the deductible temporary differences can be utilized. In the case where future taxable profit is no longer deemed to be sufficient to absorb all existing deferred tax assets, any surplus is written off.

No deferred tax liabilities were recognized on undistributed reserves of the shareholders’ equity considered to be reinvested indefinitely (approximately euro 41,000 million). The determination of the tax effect relating to such reinvested reserves is not praticable.

Other changes in the amount of euro 89 million includes the recognition of the deferred tax effect against equity on the fair value evaluation of derivatives designated as cash flow hedges in the amount of euro 65 million. Further information on cash flow hedge derivatives is provided in Note 19 – Other 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. Foreign taxation laws allow, on average, the carry-forward of tax losses over a period higher than the five subsequent years, and in many cases, indefinitely. The tax rate applied by the Italian subsidiaries to determine the portion of carry-forward tax losses to be utilized equaled 25.8%; this rate equaled on average to 28.2% for foreign entities.

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Carry-forward tax losses in the amount of euro 1,532 million can be used in the following periods:

(euro million)		Italian subsidiaries		Foreign subsidiaries

2010
2011				2
2012				1
2013		7
2014		107		43
Beyond 2014		64		19
Without limit		16		1,273
		194		1,338

Carry-forward tax losses in the amount of euro 634 million expected to be offset against future taxable profit and were in respect of Italian subsidiaries in the amount of euro 194 million and of foreign subsidiaries in the amount of euro 440 million. Deferred tax assets recognized on these losses amounted to euro 50 million and euro 124 million, respectively.


24 Other non-current liabilities
Other non-current liabilities were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Fair value of non-hedging derivatives		564		372
Fair value of cash flow hedge derivatives		499		436
Current income tax liabilities		254		52
Other payables		55		54
Other liabilities		1,730		1,566
		3,102		2,480

Fair value of derivative contracts was determined by using market quotations given by primary information providers, or, in lack of market information, on the basis of generally accepted methods for financial valuations.

Fair value of non-hedging derivatives was as follows:

		Dec. 31, 2008		Dec. 31, 2009

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Currency swap		82		694		100		10		296		94
Interest currency swap		4				40		23		394
Other		28		50		16
		114		744		156		33		690		94
Non-hedging derivatives on interest rate
Interest rate swap		129		141		3,002		137		41		4,030
		129		141		3,002		137		41		4,030
Non-hedging derivatives on commodities
Over the counter		321		769		197		199		850		219
Other								3		12		9
		321		769		197		202		862		228
		564		1,654		3,355		372		1,593		4,352

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Fair value of non-hedging derivatives in the amount of euro 372 million (euro 564 million as of December 31, 2008) referred to derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.

Fair value of cash flow hedge derivatives amounted to euro 436 million (euro 499 million as of December 31, 2008) related to Distrigas NV in the amount of euro 275 million (euro 235 million as of December 31, 2008) and the Exploration & Production segment in the amount of euro 161 million (euro 264 million as of December 31, 2008).

Further information on cash flow hedge derivatives is provided in Note 19 – Other current liabilities. Fair value of contracts expiring beyond 2010 is provided in Note 14 – Other non-current receivables; fair value of contracts expiring by 2010 is provided in Note 19 – Other current liabilities and Note 7 – Other current assets. The effects of the evaluation at the fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and Note 30 – Operating expenses.

The nominal value of the derivatives relating to purchase and sale commitments amounted to euro 1,544 million and euro 129 million, respectively (euro 1,878 million and 1,832 million as of December 31, 2008, respectively).

Information on the hedged risks and the hedging policies is shown in Note 28 – Guarantees, commitments and risks.

The group’s liability for current income taxes in the amount of euro 52 million (euro 254 million as of December 31, 2008) was due as a 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 in the amount of euro 1,566 million (euro 1,730 million as of December 31, 2008) included advances received by Suez following the long-term supply of natural gas and electricity in the amount of euro 1,455 million (euro 1,552 million as of December 31, 2008).


25 Assets held for sale and liabilities directly associated with assets held for sale
Non-current assets held for sale and liabilities directly associated with non-current assets held for sale amounted to euro 542 million and euro 276 million, respectively, which mainly relate to the divestment of certain mineral properties in Italy which were contributed in kind to two new entities, Società Padana Energia SpA and Società Adriatica Idrocarburi SpA, for the disposal of Gas Brasiliano Distribuidora SA, a company operating in the distribution and marketing of natural gas in an area of São Paulo state in Brazil, and Distri RE SA, a company acquired following the acquisition of Distrigas NV. The disposals to third parties are under negotiation.

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26 Shareholders’ equity

Minority interest
Profit attributable to minority interest and the minority interest in certain consolidated subsidiaries related to:

(euro million)		Net profit		Shareholders’ equity

		2008		2009		Dec. 31, 2008		Dec. 31, 2009

Saipem SpA		407			567		1,560		2,005
Snam Rete Gas SpA		254			369		948		1,568
Hindustan Oil Exploration Co Ltd		(1	)		1		128		123
Tigàz Tiszàntùli Gàzszolgàltatò Részvénytàrsasàg		(11	)		8		65		72
Distrigas NV		74					1,162
Others		10			5		211		210
		733			950		4,074		3,978

The increase in Snam Rete Gas SpA equity is due to the increase in the share capital for the minority shareholders’ contribution (euro 1,542 million) partially offset by the effect of acquisition from Eni of Italgas SpA and Stogit SpA (euro 1,086 million). The zero amount of the minority interests in Distrigas NV is due to the acquisition of the entire share capital of the company through the finalization of the mandatory tender offer on the minorities of Distrigas. Shareholders, including Publigaz with its entire interest (31.25%), tendered shares representing 41.617% of the share capital of Distrigas. The residual 1.14% of the share capital has been acquired by Eni through a squeeze-out.

Eni shareholders’ equity
Eni’s net equity as of December 31, 2008 and 2009 was as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Share capital		4,005			4,005
Legal reserve		959			959
Reserve for treasury shares		7,187			6,757
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect		(90	)		(439	)
Reserve related to the fair value of available-for-sale securities net of the tax effect		4			5
Other reserves		(1,054	)		1,492
Cumulative currency translation differences		(969	)		(1,665	)
Treasury shares		(6,757	)		(6,757	)
Retained earnings		34,685			39,160
Interim dividend		(2,359	)		(1,811	)
Net profit for the period		8,825			4,367
		44,436			46,073

Share capital
As of December 31, 2009 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 as of December 31, 2008).

On April 30, 2009 Eni’s Shareholders’ Meeting declared a dividend distribution of euro 0.65 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2008 dividend of euro 1.30 per share, of which euro 0.65 per share paid as interim dividend. The balance was payable on May 21, 2009 to shareholders on the register as of May 18, 2009.

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 destined to purchase Eni shares in accordance with the decisions reached at Eni’s Shareholders’ Meetings. The amount of euro 6,757 million (euro 7,187 million as of December 31, 2008) included treasury shares purchased. During the year 2009 the Company did not purchase its own shares and the term established by Eni’s Shareholders’ Meetings for the purchase has expired. The residual amount of euro 430 million was taken to Retained earnings (euro 429 million) and Other reserves (euro 1 million).

Reserve referring to the valuation at fair value of cash flow hedging derivatives and available-for-sale securities, net of the related tax
The valuation of the fair value of cash flow hedging derivatives and available-for-sale securities, net of the related tax, consisted of the following:

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	)
Changes of the year 2009		1					1		(636	)		246			(390	)		(635	)		246			(389	)
Foreign currency translation differences									3			(2	)		1			3			(2	)		1
Amount recognized in the profit and loss account									155			(44	)		111			155			(44	)		111
Reserve as of December 31, 2009		6		(1	)		5		(714	)		275			(439	)		(708	)		274			(434	)

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, 2008		Changes recognized in profit and loss account		Currency translation differences		Value at Dec. 31, 2009

(45

)

6

1

(38

)

Other reserves
Other reserves of negative amount were euro 1,492 million (as of December 31, 2008 other reserves of negative amount were euro 1,054 million) and included:

• a reserve in the amount of euro 1,086 million related to the increase of Eni’s shareholders’ equity as a control to minority interest following the sale by Eni SpA of Italgas SpA and Stogit SpA to Snam Rete Gas SpA;
• a reserve in the amount of euro 247 million related to the increase of Eni’s shareholders’ equity as a control to minority interest following the sale by Eni SpA of Snamprogetti SpA to Saipem Projects SpA, both merged in Saipem SpA (same amount as of December 31, 2008);
• a reserve in the amount of euro 157 million deriving from Eni SpA’s equity (euro 194 million as of December 31, 2008);
• a reserve in the amount of euro 2 million related to the share of "Other comprehensive income" on equity-accounted entities;

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• as of December 31, 2008 other reserves of negative amount mainly 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 mandatory tender offer to minorities (euro 1,495 million). Publigaz agreed to the mandatory tender offer and the related reserve has been set to zero.

Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

Treasury shares
A total of 382,952,240 ordinary shares (382,954,240 as of December 31, 2008) with a nominal value of euro 1 each, were held in treasury, for a total cost of euro 6,757 million (same amount as of December 31, 2008). During the year 2009, the company has not purchased its own shares and the term established by Eni’s Shareholders’ Meetings for the purchase has expired. 19,482,330 treasury shares (23,557,425 as of December 31, 2008) at a cost of euro 414 million (euro 505 million for the year-ended December 31, 2008) were available for 2002-2005 and 2006-2008 stock option plans.

The decrease of 4,075,095 shares consisted of the following:

		Stock option

Number of shares at December 31, 2008		23,557,425
Rights exercised		(2,000	)
Rights cancelled		(4,073,095	)
		(4,075,095	)
Number of shares at December 31, 2009		19,482,330

As of December 31, 2009, options outstanding were 19,482,330 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 229,900 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 3,281,500 shares with an exercise price of euro 22.512 per share, to the 2006 stock plan for 3,018,155 shares with an weighted average exercise price of euro 23.119 per share, to the 2007 stock plan for 5,144,050 with an weighted average exercise price of euro 27.451 per share and to the 2008 stock plan for 7,040,125 with an exercise price of euro 22.540 per share.

Information about commitments related to stock grant and stock option plans is included in Note 30 – Operating expenses.

Interim dividend
The interim dividend for the year ended December 31, 2009 amounted of euro 1,811 million corresponding to euro 0.50 per share, as decided by the Board of Directors on September 10, 2009 in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 24, 2009.

Distributable reserves
Undistributed reserves considered to be reinvested indefinitely amounted to approximately euro 41,000 million as of December 31, 2009. The determination of the tax effect relating to such reinvested reserves is not practicable.

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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)		2008		2009		Dec. 31, 2008		Dec. 31, 2009

As recorded in Eni SpA’s Financial Statements		6,745			5,061			30,049			32,144
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		4,140			158			18,999			17,464
Consolidation adjustments:
- difference between cost and underlying value of equity		(330	)		(213	)		5,161			5,068
- elimination of tax adjustments and compliance with accounting policies		(1,373	)		(113	)		(2,852	)		(1,062	)
- elimination of unrealized intercompany profits		216			117			(3,127	)		(4,582	)
- deferred taxation		159			378			(15	)		1,175
- other adjustments		1			(71	)		295			(156	)
		9,558			5,317			48,510			50,051
Minority interest		(733	)		(950	)		(4,074	)		(3,978	)
As recorded in Consolidated Financial Statements		8,825			4,367			44,436			46,073

 

27 Other information
On February 4, 2010 Eni formally presented to the Directorate General for Competition of the European Commission a set of structural remedies for the conclusion of a legal proceeding related to some international gas pipelines.

The legal proceeding concerns the Statement of Objections that Eni received from the European Commission on March 9, 2009 which, under Article No. 82 of the EC Treaty and Article No. 54 of the SEE agreement, alleged that during the period 2000-2005, Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas.

With prior agreement from its partners, Eni has committed to dispose of its interests in both the German Tenp gas pipeline and in Switzerland’s Transitgas pipeline which both transport gas from the sites in the North of Europe.

Given the strategic importance of the Austrian Tag pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake into an entity controlled by the Italian State. The remedies negotiated with the Commission do not affect Eni’s contractual gas transport rights.

The European Commission accepted commitments proposed by Eni and will implement a market test before adopting a decision under Article 9 of Regulation (EC) No. 1/2003.

Assets in hand refer to investments in Trans Austria Gasleitung GmbH (TAG), Trans Europa Naturgas Pipeline GmbH & Co KG (TENP) and Transitgas AG as well as assets and liabilities mainly referring to the marketing of the transportation capacity of the consolidated companies Eni Gas Transport Deutschland SpA and Eni Gas Transport International SA.

Considering the amounts as of December 31, 2009, the foreseen disposals concerns the investments accounted for using the equity method in the amount of euro 210 million, current assets in the amount of euro 258 million, liabilities in the amount of euro 98 million of which euro 8 million are non-current, and Group’s equity for a total amount of euro 160 million.

 

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Main acquisitions

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 March 19, 2009, Eni finalized the mandatory tender offer on the minorities of Distrigas. Shareholders, including Publigaz with its entire interest (31.25%), tendered shares representing 41.617% of the share capital of Distrigas. On May 4, 2009, the residual 1.14% of the share capital was acquired by Eni through a squeeze-out procedure. At December 31, 2009 Eni owns 100% of share capital of Distrigas NV with the exception of a share with special rights owned by the Belgian State.

Consideration for the acquisition of control amounted to euro 2,751 million, which includes euro 12 million related to additional costs directly attributable to the acquisition. The allocation of the cost, not including the minority interest, to assets and liabilities was made on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

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 amounted to euro 224 million which was allocated to assets and liabilities on a preliminary basis as of December 31, 2008 and on a definitive basis as of December 31, 2009.

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 amounted to euro 605 million, of which euro 5 million related to additional costs directly attributable to the acquisition. The allocation of the cost to assets and liabilities was made on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

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 tender offer was associated with Eni’s acquisition of 27.18% of HOEC as part of the Burren deal. Total consideration for this transaction in the amount of euro 107 million, not including the minority interest, has been allocated to assets and liabilities on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

The definitive allocation of the costs of the business combinations made during the year ended December 31, 2008 year consisted of the following:

(euro million)		Distrigas NV (a)		Eni Hewett Ltd		First Calgary Petroleums Ltd		Hindustan Oil Exploration Co Ltd

Preliminary allocation at Dec. 31, 2008

Definitive allocation

Preliminary allocation at Dec. 31, 2008

Definitive allocation

Preliminary allocation at Dec. 31, 2008

Definitive allocation

Preliminary allocation at Dec. 31, 2008

Definitive allocation

Current assets		3,375		3,375		19		20		148		148		115		115
Property, plant and equipment		30		30		118		118		757		855		199		201
Intangible assets		1,395		1,390		208		217
Goodwill		1,245		1,248		39		37		88		65
Investments		112		112										1		1
Other non-current assets		203		203
Assets acquired		6,360		6,358		384		392		993		1,068		315		317
Current liabilities		1,796		1,796		17		22		45		82		37		37
Deferred tax liabilities		504		502		91		94		108		147		31		33
Provisions for contingencies		80		80		52		52		6		5		3		3
Other non-current liabilities		88		88						229		229		17		17
Liabilities acquired		2,468		2,466		160		168		388		463		88		90
Minority interest		1,141		1,141										120		120
Eni's shareholders equity		2,751		2,751		224		224		605		605		107		107

(a)		It does not include the share of goodwill attributable to minorities whose equity interest has been acquired during 2009.

 

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28 Guarantees, commitments and risks

Guarantees
Guarantees were as follows:

		Dec. 31, 2008		Dec. 31, 2009

(euro million)

Unsecured guarantees

Other guarantees

Total

Unsecured guarantees

Other guarantees

Total

Consolidated subsidiaries				13,139		13,139				9,863		9,863
Unconsolidated entities controlled by Eni				151		151				146		146
Joint ventures and associates		6,027		1,075		7,102		6,060		1,251		7,311
Others		8		245		253		5		266		271
		6,035		14,610		20,645		6,065		11,526		17,591

Other guarantees issued on behalf of consolidated subsidiaries in the amount of euro 9,863 million (euro 13,139 million as of December 31, 2008) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds in the amount of euro 6,091 million (euro 7,004 million as of December 31, 2008), of which euro 4,936 million related to the Engineering & Construction segment (euro 5,965 million as of December 31, 2008); (ii) VAT recoverable from tax authorities in the amount of euro 1,171 million (euro 1,248 million as of December 31, 2008); (iii) insurance risk in the amount of euro 253 million reinsured by Eni (euro 257 million as of December 31, 2008). During 2009, guarantees for euro 2,739 million expired. These guarantees were issued on behalf of Eni Gas & Power Belgium SA related to the Share Purchase Agreement with Suez-Tractebel SA for the acquisition of 57.24% majority stake in Distrigas NV. As of December 31, 2009 the underlying commitment covered by such guarantees was euro 9,783 million (euro 10,202 million as of December 31, 2008).

Other guarantees issued on behalf of unconsolidated subsidiaries in the amount of euro 146 million (euro 151 million as of December 31, 2008) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds in the amount of euro 141 million (euro 146 million as of December 31, 2008). As of December 31, 2009, the underlying commitment covered by such guarantees was euro 64 million (euro 79 million as of December 31, 2008).

Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates in the amount of euro 7,311 million (euro 7,102 million as of December 31, 2008) primarily consisted of: (i) an unsecured guarantee in the amount of euro 6,037 million (euro 6,001 million as of December 31, 2008) 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 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 in the amount of euro 971 million (euro 871 million as of December 31, 2008), of which euro 692 million related to a contract released by Eni SpA on behalf of Blue Stream Pipeline Co BV (Eni 50%) to a consortium of international financial institutions (euro 716 million as of December 31, 2008); (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds in the amount of euro 126 million (euro 107 million as of December 31, 2008). As of December 31, 2009, the underlying commitment covered by such guarantees was euro 814 million (euro 983 million as of December 31, 2008).

Unsecured and other guarantees given on behalf of third parties in the amount of euro 271 million (euro 253 million as of December 31, 2008) 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 for fees in connection with the re-gasification activity. The expected commitment has been valued at euro 206 million (euro 223 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit in the amount of euro 23 million on behalf of minor investments or companies sold (euro 19 million as of December 31, 2008).

As of December 31, 2009 the underlying commitment covered by such guarantees was euro 266 million (euro 232 million as of December 31, 2008).

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Commitments and contingencies
Commitments and contingencies were as follows:

(euro million)		Dec. 31, 2008		Dec. 31, 2009

Commitments		13,382		16,668
Risks		1,660		1,277
		15,042		17,945

Other commitments in the amount of euro 16,668 million (euro 13,382 million as of December 31, 2008) mainly related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities that was quantified on the basis of the capital expenditures expected to be incurred which is euro 10,302 million (euro 10,585 million as of December 31, 2008); (ii) 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 (USA) that will come into force when the regasification service starts during the period between 2011-2032. The expected commitment has been valued at euro 3,941 million and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (iii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Gulf LNG Energy for the acquisition of regasification capacity of Pescagoula’s terminal (6 BCM/y) over a twenty-year period (2011-2031). The expected commitment has been valued at euro 1,151 million (euro 1,247 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (iv) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Cameron Llc for the acquisition of regasification capacity at the Cameron plant (USA) (5.7 BCM/y) over a twenty-year period (until 2029). The expected commitment has been valued at euro 990 million (euro 1,222 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (v) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 150 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 180 million as of December 31, 2008). The commitment is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (vi) a commitment entered into by Eni USA Gas Marketing Llc for the contract of gas transportation from the Cameron plant (USA) to the American network. The expected commitment has been valued at euro 110 million (euro 123 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk".

Risks in the amount of euro 1,277 million (euro 1,660 million as of December 31, 2008) primarily relate to potential risks associated with the value of assets of third parties under the custody of Eni in the amount of euro 899 million (euro 1,273 million as of December 31, 2008) and contractual assurances given to acquirers of certain investments and businesses of Eni in the amount of euro 378 million (euro 387 million as of December 31, 2008).

Non-quantifiable commitments
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 Consortium contains the same obligations and guarantees contained in the CEPAV Uno Agreement.

Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain of Eni’s assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity.

Risk factors

FOREWORD
The main risks that the Company is facing and actively monitoring and managing are the following: (i) market risk derived from exposure to fluctuations in interest rates, foreign currency exchange rates and commodity prices; (ii) credit risk derived from the possible default of a counterparty; (iii) liquidity risk derived from the risk that

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suitable sources of funding for the Group’s operations may not be available; (iv) country risk in the upstream business; (v) operational risk; (vi) the possible evolution of the Italian gas market; (vii) the specific risks derived 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 separate entities: the parent company’s (Eni SpA) finance department, Eni Coordination Center and Banque Eni which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk and Eni Trading & Shipping that has the mandate to manage and solely monitor commodity derivative contracts. In particular, Eni SpA and Eni Coordination Center manage subsidiaries’ financing requirements inside 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 into account the correlation that exists 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 Group companies minimize such market risks. With regard to commodity risk, Eni’s policies and guidelines define rules to manage this risk aiming at the optimization of core activities and the pursuit 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 transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro (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 the translation of foreign currency denominated profits or assets and liabilities of subsidiaries which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance departments which match opposite positions within Group companies, hedging the Group's 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

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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. Such derivatives are valued 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 valued 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 derived 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 2009 (compared with 2008) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section. VAR values are stated in U.S. dollars, the currency used in oil products markets.

(Interest and exchange rate - Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

		2008		2009

(euro million)

High

Low

Average

At year end

High

Low

Average

At year end

Interest rate		12.31		0.73		4.17		6.54		6.85		1.65		3.35		1.98
Exchange rate		1.48		0.09		0.48		0.47		1.22		0.07		0.35		0.31

(Commodity risk - Value at risk - historic simulation method; holding period: 1 day; confidence level: 95%)

		2008		2009

($ million)

High

Low

Average

At year end

High

Low

Average

At year end

Area oil, products		46.48		3.44		19.88		5.43		37.51		4.74		17.65		6.64
Area Gas & Power (*)		67.04		24.38		43.53		32.07		51.62		28.01		40.97		38.26

(*)		Amounts relating to the Gas & Power business also include the results of Distrigas NV starting from the acquisition date.

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 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

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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 and accordingly allocated to its proper risk category. The Group risk categories are comparable to those prepared by the main rating agencies in 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 Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies in 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 also been selected on more stringent criteria particularly in transactions on derivatives instruments and with maturity longer than a three-month period. See Note 3 for a disclosure of Eni’s allowance against doubtful accounts for year. As of December 31, 2009, Eni did non have a significant concentration 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 in the market place as to be unable to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. 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’s 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 issuance of commercial paper also targeting to increase the flexibility of funding facilities. In particular in 2009, Eni issued bonds addressed to institutional investors and to the retail market in the amount of euro 3 billion and euro 2 billion, respectively. The above mentioned actions aimed at ensuring availability of suitable sources of funding to fulfill short term commitments and obligations due while 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, 2009, Eni maintained short term committed and uncommitted unused borrowing facilities in the amount of euro 11,774 million, of which euro 2,241 million were committed, and long term committed unused borrowing facilities amounted to euro 2,850 million. These facilities were under interest rates that reflected market conditions. Fees charged for unused facilities were not significant.

Eni has a program in place for the issuance of Euro Medium Term Notes up to euro 15 billion, of which euro 9,211 million were drawn as of December 31, 2009.

The Group has debt ratings of AA- and A-1+ assigned by Standard & Poor’s and Aa2 and P-1 assigned by Moody’s respectively for long and short-term debt. The outlook is negative in both ratings.

The tables below summarize the maturities of the Group’s main contractual obligations for finance debt repayments, including expected payments for interest charges, and trade and other payables.

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Finance debt

		Maturity year

(euro million)		2010		2011		2012		2013		2014		2015 and thereafter		Total

Non current debt		3,191		1,342		3,660		1,967		2,487		8,608		21,255
Current financial liabilities		3,545												3,545
Fair value of derivative instruments		1,371		517		133		46		14		98		2,179
		8,107		1,859		3,793		2,013		2,501		8,706		26,979
Interest on finance debt		654		570		545		510		426		1,159		3,864
Guarantees to banks		377												377

Trade and other payables

		Maturity year

(euro million)		2010		2011-2014		2015 and thereafter		Total

Trade payables		10,078						10,078
Advances, other payables		9,096		31		23		9,150
		19,174		31		23		19,228

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 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's 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.

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Expected payments by period under contractual obligations and commercial commitments

		Maturity year

(euro million)		2010		2011		2012		2013		2014		2015 and thereafter		Total

Operating lease obligations (1)		886		889		561		470		415		1,034		4,255
Decommissioning liabilities (2)		79		55		112		161		1,640		9,280		11,327
Environmental liabilities		293		259		257		214		193		687		1,903
Purchase obligations (3)		14,845		14,151		13,923		14,634		14,651		175,888		248,092
Gas
- Natural gas to be purchased in connection with take-or-pay contracts (4)		13,986		13,365		13,123		13,827		13,838		169,268		237,407
- Natural gas to be transported in connection with ship-or-pay contracts (4)		546		538		545		559		567		3,658		6,413
Other take-or-pay and ship-or-pay obligations		162		154		139		133		131		1,068		1,787
Other purchase obligations (5)		151		94		116		115		115		1,894		2,485
Other obligations (6)		21		4		3		3		3		152		186
of which:
- Memorandum of intent relating Val d’Agri		21		4		3		3		3		152		186
		16,124		15,358		14,856		15,482		16,902		187,041		265,763

(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)		Such arrangements include non-cancellable, 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)		Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S.
(6)		In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans (see Note 22 to the Consolidated Financial Statements).

Over the next four-year period, Eni plans to invest euro 52.8 billion.

The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects as of December 31, 2009. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval and for which, usually, procurements have been arranged or set. Such costs are included in the amounts shown.

Capital expenditure commitments

		Maturity year

(euro million)		2010		2011		2012		2013		2014 and thereafter		Total

Committed on major projects		4,119		3,793		2,829		1,928		11,357		24,026
Other committed projects		9,330		5,284		3,467		3,640		7,489		29,210
		13,449		9,077		6,296		5,568		18,846		53,236

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 the EU or North American. As of December 31, 2009, approximately 80% 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 2009, approximately 60% of Eni’s domestic supply of natural gas came from such countries. Developments in the political framework, economic crisis, and 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 associated with

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activities in those 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 the value of Eni’s assets; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases; (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 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 in 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 regulations on safety and health in the workplace in Italy (Legislative Decree No. 81/2008 and Legislative Decree No. 106/2009) impose a new array of obligations to the Company's operations, particularly regarding contractors. New regulations 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 is performed through the adoption of procedures and effective pollution management systems tailored to the peculiarities of each business and industrial site and on steady enhancement of plants and process. Additionally, coding activities and procedures on operating phases allow to reduce the human component in plant risk management. Operating emergencies that may have an adverse impact on assets, people and the environment are managed by the business units for each site. These units manage the HSE risk in 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 a major crisis, Divisions/Entities are assisted by the Eni Unit of Crisis 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 Division and companies of the 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 (Deming cycle).

Eni is reaching the goal of total certification of its plants. Industrial and commercial sites of the R&M segment have been certified as ISO 14001, and six of them are EMAS certified; in the petrochemical segment facilities are certified under ISO 14001, EMAS and OHSAS 18001. EniPower power stations are EMAS certified, while in other segments facilities are mainly certified under ISO 14001 and OHSAS 18001.

The system for monitoring HSE operational risks is based on the monitoring of HSE indicators at quarterly intervals and on an audit plan addressed to three levels: HSE Corporate, HSE business unit and at site level consisting of:

• internal audits of management systems (performed by Eni employees or external consultants);

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• audits for the confirmation or renewal of certification of management systems performed annually by external certifying entities;
• control of compliance with existing HSE regulations;
• specific audits on relevant issues (e.g. following events/accidents/reported failures).

Eni provides a program of specific training and development to its HSE staff in order to:

• promote the execution of behaviors consistent with guidelines;
• drive people’s learning growth process by developing professionalism, management and corporate culture;
• support management knowledge and control of HSE risks.

Risk factors related to the natural gas market

Risks and uncertainties associated with the current outlook for gas demand and supply in Europe and Italy
In 2009 European gas demand was severely impacted by the economic downturn (down 7.4% from 2008, assuming normal average temperatures). As a result of that trend, both producing activities and request for electricity reduced. The Italian market was particularly hit by the downturn as demand fell by approximately 9 BCM from 2008, down 10%, and almost 10 BCM from the pre-crisis levels seen in 2007, down 12%, assuming normal average temperatures. In the meantime, new gas supplies entered the market as several operators, including Eni, completed plans to upgrade gas import pipelines from gas producing Countries or to build new facilities to import gas to Europe via LNG. Particularly, Eni has finalized plans to upgrade the import capacity of its two main pipelines from Russia and Algeria by 13 BCM/y (the gas pipelines TAG and TTPC), with new capacity entirely sold to third parties. A new LNG terminal with a capacity of 8 BCM/y commenced operations late in 2009, operated by a consortium of competitors. As a result, gas availability on the Italian market increased at a time when demand actually shrunk, resulting in a situation of oversupply. In this context, Eni’s results of the gas marketing business, sales volumes and average gas selling margins were driven down by rising competition and weak demand both in Italy and Europe. Large gas availability on European markets also prevented the Company from disposing of part of its gas availability by selling it on European markets. The outlook for gas supply and demand both in Europe and Italy is challenging as GDP growth in the 27 EU Countries will remain weak over the next few years and gas demand is expected to recover only gradually to precrisis levels. In addition, ongoing patterns towards energy preservation and rising competition from renewable or alternative sources of energy will further dampen recovery perspectives of gas demand. Specifically, at the March 2007 European Council, the European Heads of Government decided to adopt their Climate Action and Renewable Energy Package. This legislation was voted by the European Parliament in December 2008. The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as an improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020. To factor in those trends, management has revised down its long-term projections of European gas demand growth from a previous compound average growth rate (c.a.g.r.) of 2% till 2020 to a revised 1.5% c.a.g.r. These assumptions imply an overall consumption of approximately 600 BCM by 2020 compared to a previous forecast of 720 BCM. Management also expects the Italian market to grow less than anticipated at an annual rate that will be slightly lower than 2%, implying a level of consumption amounting to 94 BCM versus a previous forecast of 107 BCM at 2020. These demand trends of sluggish growth associated with ample gas availability on the marketplace might adversely affect the Company’s results of operations and cash flow in its gas marketing business over the next few years.

Current negative trends in gas demand and supply may impair the Company’s ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts
In order to secure long-term access to gas availability, particularly in view of supplying the Italian gas market, the Company has signed a number of long-term gas supply contracts with key producing Countries that supply European gas markets. These contracts will ensure approximately 62.4 BCM of gas availability in 2010 (excluding the contribution of other subsidiaries and associates) with a residual life of approximately 20 years, and provide take-or-pay clauses whereby the Company is required to collect minimum predetermined volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of it, of uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. Amounts of cash prepayments and time schedules for collecting pre-paid gas vary from contract to contract. Generally speaking, cash pre-payments are calculated on the basis of the energy prices current in the year of non-fulfillment with the balance due in the year when the gas is actually collected. Amounts of pre-payments range from 10 to 100 percent of the full price. The right to collect pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, rights to collect pre-paid gas in future years can be exercised provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity that can be collected in each contractual year. In this case, Eni will pay the residual price calculating it as the percentage

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that complements 100, based on the arithmetical average of monthly base prices in place in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations. Management believes that the current outlook for gas demand and large gas availability on the marketplace, as well as the possible evolution of sector-specific regulation, represent risks factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts. Under current contractual terms, in 2009 Eni collected lower volumes than its minimum take and recognized a trade payables corresponding to the amount of gas that the Company was contractually required to collect. Management believes that over the next three years the Company will experience failure to fulfill its take-or-pay obligations associated with significant volumes of gas, unless demand fundamentals improve substantially and a better balance between demand and supply is achieved on the marketplace. Currently, the Company is unable to forecast the timing of such a recovery. In addition, there also exist both a pricing risk as a portion of the gas purchase price is based on the prices of the energy parameters recorded in the year of non-fulfillment, and a volume risk in case the Company is actually unable to dispose of pre-paid volumes. In this context, the Company’s selling margins, results of operations and cash flow may be negatively affected. Based on management’s projections for sales volumes and prices for the four-year plan and subsequent years, volumes for which an obligation to pay cash advances might arise due to take or pay clauses will be off-taken within contractual terms, thus recovering cash advances. Even if financing associated with cash advances is factored in, the net present value associated with those long-term contracts discounted at the weighted average cost of capital for the Gas & Power segment still remains a positive and consequently those contracts do not fall within the category of the onerous contract provided by IAS 37. In the medium term Eni intends to preserve the profitability and cash flow generation of its gas marketing operations. A number of initiatives have been identified, including:

• maximization of gas sales volumes leveraging on the multiple presence in a number of markets; market knowledge, the integration with Distrigas commercial operations and supply portfolio (which is not expected to have take-or-pay obligations in future years) and marketing policies aimed at increasing Eni’s market share in Europe;
• renegotiations of the main long-term supply contracts through the exercise of the contractual right to amend terms and conditions of the contracts as provided by specific contractual clauses in case of significant changes in the market environment, as those that have been occurring from the second half of 2008. These renegotiations were finalized early in 2010 with a positive impact both on 2009 results and on future commercial plans giving Eni more flexibility in its marketing operations;
• launching of innovative pricing formulas and improving the quality of services on the core Italian market;
• reduction of the cost-to-serve; and
• monitoring and controlling working capital requirements.

Risks associated with sector-specific regulations in Italy
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 regulations are the regulated access to natural gas infrastructure (transport backbones, storage fields, distribution networks and LNG terminals), the provision that activities relating to infrastructures are mandatory charged to separate companies; 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 and other 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. Specifically, the Authority for Electricity and Gas holds a general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users consuming less than 200,000 CM/y (qualified as non eligible customers as of 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. 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 that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account a new indexation mechanism of the raw material cost component. This indexation mechanism has been recently updated based on Resolution No. 64/2009 of the Authority, which provides that changes in a preset basket of hydrocarbons are transferred to the cost of the supply to those customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. Also certain provisions of law may limit the Company’s 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 the higher income taxes incurred in connection with a supplemental tax rate of 6.5 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 this rule. The Authority

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has subsequently established with a set of deliberations that energy companies have to adopt effective operational and monitoring systems in order to prevent unlawful increases in final prices of gas. Other risk factors and uncertainties deriving from the regulatory framework are associated with the regulation of the access to the Italian gas transport network that is currently set by Decision No. 137/2002 of the Authority for Electricity and Gas. The decision is fully incorporated into the network code presently in force as prepared by the system’s operator. The decision sets priority criteria for transport capacity entitlements at points where the Italian transport network connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, operators that are holders of take-or-pay contracts, as in the case of Eni, are entitled to a priority in allocating available transport capacity within the limit of average daily contractual volumes. Gas volumes exceeding average daily contractual volumes are not entitled to any priority and, in case of congestion at any entry points, they are entitled available capacity on a proportionate basis together with all pending requests for capacity assignments. The ability of Eni to collect gas volumes exceeding average daily volumes as provided by its take-or-pay supply contracts represents an important operational flexibility that the Company uses to satisfy demand peaks. In planning its commercial flows, the Company normally assumes to make full use of its contractual flexibility and to obtain the necessary capacity entitlements at the entry points to the national transport network. Those assumptions may be inconsistent with rules set by Decision No. 137/2002 specifically with regard to priority criteria governing capacity entitlements. Eni considers Decision No. 137/2002 to be illegitimate as it is supposedly in contrast with the rationale of the European regulatory framework on the gas market as provided in European Directive 55/2003/CE. Based on that belief the Company has opened an administrative procedure to repeal Decision No. 137/2002 before an administrative court which recently confirmed in part Eni’s position. An upper grade court also confirmed the Company’s position. Specifically, the Court stated that the purchase of contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in the access to the network, also in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure such to impair Eni’s marketing plans. Further uncertainty factors related to the regulatory framework are the so called gas release measures that are intended to increase flexibility and liquidity in the gas market. This measure strongly affected Eni’s marketing activity in Italy. In 2004, based on certain agreements with the Antitrust Authority, Eni released in a four-year period a total amount of 9.2 BCM (2.3 BCM/y between October 1, 2004 and September 30, 2008) and the related transport capacity. In addition, in 2007 Eni agreed to adhere to a new gas release program involving 4 BCM which were disposed of at the virtual exchange point (PSV) in a two-year period (from October 1, 2007 and September 30, 2009). For thermal year 2009-2010 Italian Law No. 99/2009 introduced a new obligation for Eni to make additional sales at the virtual exchange point for a total of 5 BCM of gas in yearly and half-yearly amounts. Although the allotment procedure (bid) was based on a minimum price set by the Ministry for Economic Development as proposed by the Authority (Eni considering this point discriminatory, filed a claim to the competent authority), only a 1.1 BCM portion of the gas release was awarded out of the 5 BCM which had been planned. For the next few years, based on indications of the Authority (in a report to the Parliament on the situation of the gas and electricity market in Italy as provided in Resolution PAS 3/2010), Eni cannot exclude the possibility that new gas release programs will be imposed on it.

Specific risks associated with exploration and production of oil and natural gas
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 related 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 are located.

Risks associated with the cyclicality of the oil and gas sector
The global economic downturn and the associated reduction in industrial output recorded in 2008 and for most of 2009 triggered a sharp decline in worldwide demand for energy, resulting in significantly lower commodity prices.

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In spite of weak fundamentals (level of global demand and level of inventories), international oil prices have shown a steady upward trend since the second half of 2009 driven by expectations for a global economic recovery and OPEC production cuts, settling by year end in a range of 70-80 $/BBL.

Volatile oil prices pose a critical issue to the sustainability of capital plans of oil and gas companies, considering that they are engaged in long lead-time projects. Such projects normally require lengthy and complex activities for assessing all technical and commercial aspects and developing and marketing hydrocarbons. As a consequence, return rates of 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 made, resulting in lower rates of return. The Company, likewise other players in the industry, assesses its oil & gas projects based on long-term scenarios for oil prices, which reflect management’s best assumptions about the underlying fundamentals of global demand and offer. The adoption of long-term prices in assessing capital projects support the achievement of the planned rates of return.

Eni plans to invest euro 52.8 billion in the four-year period from 2010 through 2013, at the Company’s long-term price for Brent crude of 65 $/BBL (in real terms 2013). Of this, euro 37.7 billion, or 71%, will be dedicated to execute projects for exploring and developing oil and gas reserves. The plan shows an increase of 8% from the previous plan that was approved when the trading environment was particularly depressed. The main drivers which explain the increase are: (i) planned expenditures for developing new upstream projects, particularly those associated with reserves development in Iraq, Venezuela and certain fields offshore Angola; (ii) the circumstance that the Company is forecasting steady trends in costs for materials and sector specific services which have fallen far less than what management has anticipated due to the fast recovery in international oil prices, and the impact of the decision on part of most oil companies to maintain their spending patterns substantially unchanged. In the previous plan, management assumed a decline in those costs. These increasing trends will be partially offset by the impact of the U.S. dollar depreciation versus the euro.

Volatile oil prices also influence the reserve replacement ratio. Changes in oil prices normally trigger two opposite impacts in proved reserves revisions. On one side, a larger or smaller amount of reserves is booked in connection with production sharing agreements and similar contractual schemes. Under such contracts, the Company is entitled to receive a portion of the production, the sale of which should cover expenditures incurred and earn the Company a share of profit. Accordingly, the higher the reference prices for crude oil used to determine production and reserves entitlements, the lower the number of barrels to cover the same dollar amounts hence the amounts of booked reserves; and vice versa. On the other side, downward revisions of reserves occur for those marginal amounts of reserves that are no longer economically producible based on oil prices that are significantly lower than those at which they were originally assessed and sanctioned; and the opposite occurs in case of higher oil prices.

In the Gas & Power segment, Eni’s outlook for the year 2010 factors in a modest improvement in Italian and European gas demand, recovering from the sharp decline suffered in 2009.

Eni also expects that the gas market will be well supplied as new import capacity to Europe and Italy is available in light of recent facility start-ups and upgrades of the main importpipelines made by Eni and other operators. Those trends, together with the recently enacted gas release programs in Italy, represent risk factors to the Company’s ability to maintain its margins in the marketing business also taking into account the take or pay clauses of certain long-term supply contracts which require the Company to collect minimum predetermined volumes of gas or, in case of failure, to pay the price, or a portion of it, for uncollected volumes. Under take or pay clauses the Company is entitled to collect pre-paid volumes of gas in future years, assuming a stronger recovery in gas demand.

The Refining & Marketing and the Petrochemical segments are particularly exposed to the volatility of the economic cycle, as their respective industries continue to be plagued by excess capacity, intense competitive pressure, low entry barriers and commoditized products. These industries are also exposed to movements in oil prices and the speed at which the prices of refined products and petrochemicals products adjust to reflect change in the cost of oil-based feedstock. Normally, a time lag occurs between movements in oil prices and those of refined and petrochemical products. As a consequence, in a period of rapidly escalating feedstock costs, margins on refined and petrochemical products are negatively affected.

For 2010, Eni’s management does not expect any appreciable recovery in the main trends that negatively affected the performances of these businesses last year. In 2009 Eni’s realized refining margins were sharply lower mirroring the environment for Brent margins (down 50%), while margins on a mix of light and heavy crude were further lower, down by 60%, both under break-even. A number of negative factors contribute to the reduction. Firstly, significantly compressed light-heavy crude differentials due to a reduction in heavy crude availability on the market place negatively affected the profitability of Eni’s complex refineries. Secondly, the industry continued to be plagued by weak fundamentals due to excess capacity, high inventory levels and stagnant demand affecting end-

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prices, while feedstock costs have been on an upward trend since the beginning of the second half. Finally, middle-distillates prices plunged to historical lows in terms of spread versus the cost of oil. At the moment, management does not expect a reversal in those trends on the short-term.

In its Petrochemical segment, management has been pursuing a number of initiatives designed to reduce fixed operating expenses and to realign the industrial set-up of Eni’s petrochemical operations with a view of enhancing areas of competitive advantage. In spite of all this, the achievement of the operating break-even in this segment depends on a global recovery in the economy that is uncertain at least in the short term.

The Engineering & Construction segment followed a different trend, maintaining a steady order backlog and economic returns, thanks to a business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. The start of operations of new distinctive assets in 2010 and 2011 coupled with the size and quality of the backlog and the strong operating performance on projects, underpin expectations for a further significant strengthening of Saipem’s competitive position in the medium term.

Other information about financial instruments
The carrying amount of financial instruments and relevant economic effect as of and for the years ended December 31, 2008 and 2009 consisted of the following:

		2008		2009

		Finance income (expense) recognized in		Finance income (expense) recognized in

(euro million)

Carrying amount

Profit and loss account

Equity

Carrying amount

Profit and loss account

Equity

Held-for-trading financial instruments
Non-hedging derivatives (a)		(374	)		(558	)				(26	)		45
Held-to-maturity financial instruments
Securities (b)		50			2					36			1
Available-for-sale financial instruments
Securities (b)		495			19			3		348			13			1
Receivables and payables and other assets/liabilities valued at amortized cost
Trade and receivables and other (c)		22,446			(254	)				20,748			(361	)
Financing receivables (b)		1,908			117					1,637			72
Trade payables and other (d)		20,570			(53	)				19,228			(48	)
Financing payables (b)		20,837			(607	)				24,800			(508	)
Assets at fair value through profit or loss (fair value option)
Investments (b)		2,741			241								163
Net liabilities for hedging derivatives (e)		280			1,012			964		751			161			(636	)

(a)		In the profit and loss account, incomes were recognized within "Other operating income (loss)" for euro 49 million (expenses for euro 131 million at December 31, 2008) and within "Finance income (expense)" for euro 4 million (expenses for euro 427 million at December 31, 2008).
(b)		Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(c)		In the profit and loss account, essentially impairments were recognized within "Purchase, services and other" for euro 427 million (euro 385 million at December 31, 2008) while positive exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were recognized within "Finance income (expense)" for euro 66 million (euro 131 million at December 31, 2008).
(d)		In the profit and loss account, primarily exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were recognized within "Finance income (expense)".
(e)		Income or expense were recognized in the profit and loss account within "Net sales from operations" and "Purchase, services and other" for euro 155 million (euro 1,005 million at December 31, 2008) within "Finance income (expense)" for euro 6 million (euro 7 million at December 31, 2008) (time value component).

Fair value of financial instruments
Following the classification of financial assets and liabilities, measured at fair value in the balance sheet, is provided according to the fair value hierarchy defined on the basis of the relevance of the inputs used in the measurement process. In particular, on the basis of the features of the inputs used in making the measurements, the fair value hierarchy shall have the following levels:

(a)

Level 1: quoted prices (unadjusted) in active markets for identical financial assets or liabilities;

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(b)		Level 2: measurements based on the basis of inputs, other than quoted prices above, which, for assets and liabilities that have to be measured, can be observable directly (e.g. prices) or indirectly (e.g. deriving from prices);
(c)		Level 3: inputs not based on observable market data.

Financial instruments measured at fair value in the balance sheet as of December 31, 2009 were classified as follows: (i) level 1, "Other financial assets held for trading or available for sale"; (ii) level 2, derivative instruments included in "Other current assets", "Other non-current assets", "Other current liabilities" and "Other non-current liabilities". During 2009 no transfers were done between the different hierarchy levels of fair value. More information about the amount of financial instruments valued at fair value are provided in Note 2 – Other financial assets held for trading or available for sale, Note 7 – Other current assets, Note 14 – Other non-current assets, Note 19 – Other current liabilities and Note 24 – Other non-current liabilities.

 

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 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. At the end of the renewed preliminary investigations the Court of Ravenna requested the closing of the proceeding. According to press news a number of plaintiffs would file appeals against this decision.
(ii)		Alleged damage - Prosecuting body: Public Prosecutor of Gela. 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. A number of farmers of Gela area, who have been acting as plaintiffs in the first level hearing stage, filed an appeal against the acquittal sentence in the civil action. In the first hearing on December 17, 2009, the public prosecutor asked for the dismissal of the appeal confirming the motivations of the acquittal sentence in the first degree proceeding. The Court of Rome postponed the proceeding to the hearing of February 25, 2010. In February 25, 2010 the Court confirmed the acquittal sentence. The Court would file the grounds of the judgments within the next 60 days.

(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

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		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. In the first hearing the Court re-opened the examining phase, arranging a collegial appraiser. On December 10, 2009 the appraisers appointed by the Court filed their report. On January 21, 2010 the Court of Caltanissetta announced an acquittal sentence for all the defendants.
(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. The proceeding was subsequently assigned to a different judge and was disposed the renewal of the debate phase. In the said phase were examined indictment and defense witnesses. Subsequently it was examined the first technical appraiser of the defense. The proceeding continues with examination of another technical appraiser of the defense.
(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 the public prosecutor requested the opening of a proceeding against the mentioned managers for negligent behavior. The first hearing, in which the parties could present themselves as plaintiffs, was scheduled for February 26, 2010. On February 5, 2010, the Court of Siracusa following the exception of inadmissibility issued by the defendants, admitted as a plaintiff the only the Ministry for the Environment excluding all the other counterparts, including the Council of Ministers. The proceeding continues with the examination of three witnesses of the Public Prosecutor.

(vi)

Groundwater at the Priolo site - Prosecuting body: Public Prosecutor of Siracusa. The Public Prosecutor of Siracusa (Sicily) has started an investigation in order to ascertain the level of contamination of the groundwater at the Priolo site. The Company has been notified that a number of its executive officers 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 Eni SpA in the Refining & Marketing division), Syndial and Polimeri Europa. Probes on technical issues required by the Prosecutor were finalized on October 15, 2009. On February 25, 2010 the technical survey was filed. According to this report the ground and the groundwater at the Priolo site should be considered polluted according to Law Decree 152/2006. This contamination was caused by a spill over made in the period prior to 2001 and not subsequent to 2005; the equipments still operating on the site represent another source of risk, in particular the ones owned by another operator. According to the findings of this report the defense of Syndial, Polimeri Europa and Eni SpA (Refining & Marketing division) will file a defensive memorandum to request the dismissal of the proceeding.

 

SYNDIAL SPA
(vii)		Porto Torres - Prosecuting body: Public Prosecutor of Sassari. 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. In the preliminary hearing on July 17, 2009, the Province of Sassari, the Association Anpana (animal preservation) and the company Fratelli Polese Snc situated in the industrial site have been acting as plaintiffs. None of these parties claimed the identification of the civil responsible and the damage quantification that will be asked in a second step. The legal defense of Syndial requested further time for the recognition of the proceeding plaintiffs and the verification of their right to institute proceedings. The defense of Syndial filled a number of exceptions on the admissibility in acting as plaintiffs of the counterpart; the judge will resolve the question in the hearing which has been scheduled for February 19, 2010. In this hearing the judge, based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, excluded all the counterparts that have been acting as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the fishing talent of the industrial port of Porto Torres; the judge admitted as plaintiffs the Municipality of Sassari, the Environmental Association Anpana and the company Fratelli Polese Snc. The judge also requested that Syndial SpA, Polimeri Europa SpA, Ineos Vinylis and Sasol Italy SpA stand trial. The proceeding continues for the constitution as defendants of the said parts.

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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 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. Negotiations between the parts for the quantification of the environmental damage (relating only to 1990) are underway; the judgment has been postponed a number of times until the next hearing that has been scheduled for January 28, 2010. This hearing has been adjourned again to July 22, 2010 because negotiations between the parts are underway.
(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 (EVC Italia, then Ineos Vinyls SpA, actually Vinyls Italia SpA) was summoned before the Court of Venice by the Province of Venice. The province requested compensation for environmental damages that initially 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. Vinyls Italia SpA presented an action to be indemnified by Eni’s Group companies in case the alleged pollution is proved. The Province of Venice, in the preliminary stage of the proceeding, filed claims amounting to euro 287 million. Syndial submitted its written reply evidencing that the abovementioned damage quantification has been made lacking of probations for the damage and based on evidence that allowed the Court of First and Second Instance to disclaim EniChem of any responsibility through definitive sentence. In the hearing on October 16, 2009, scheduled to review the technical appraisal, the Court declared the interruption of the proceeding because Vinyls Italia had undergone a reorganization procedure. The proceeding is suspended until the eventual action as plaintiff of the Province of Venice.

(iii)

Claim of environmental damages, allegedly caused by industrial activities in the area of Crotone - Prosecuting Bodies: the Council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region. The council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region requested Syndial to appear before the Court of Milan in order Syndial is condemned to compensate for the environmental damage caused by the operations of Pertusola Sud SpA (merged in EniChem, now Syndial) in the Crotone site. This first degree proceeding was generated in January 2008 by the unification of two different actions, the first brought by Calabria Region in October 2004, the second one by the council of Ministers, the Ministry for the environment and the Delegated Commissioner for Environmental Emergency in the Calabria Region commenced in February 2006. The Calabria Region is claiming compensation amounting to euro 129 million for the site environmental remediation and clean-up on the basis of the cost estimation provided in the remediation plan submitted by the Delegated Commissioner, plus additional compensation amounting to a preliminary estimate of euro 800 million relating to environmental damage, estimated increases in the regional health expenditures and damage to the public image to be fairly determined during the civil proceeding. The council of Ministers, the Ministry for the Environment and the Delegated Commissioner is claiming compensation amounting to euro 129 million for the site environmental remediation and clean-up (this request is analogous to that of the Calabria Region) and eventual compensation for other environmental damage to be fairly determined during the civil proceeding. In February 2007 the Ministry for the Environment filed with the Court an independent appraiser’s report issued by APAT that estimated a refundable environmental damage amounting to euro 1,920 million, including the remediation and clean-up expenditures, increased by euro 1,620 million from the original amount of euro 129 million, and an estimation of environmental damage and other damage items amounting approximately to euro 300 million. The amounts estimated by the independent appraiser, added to the claim of the Calabria Region, generate a total of euro 2,720 million of potential compensation. In May and September 2007 Syndial presented its own technical advice that, based on what the Company believes to be well-founded circumstances, vigorously object the independent appraiser’s findings filed by the Ministry for the Environment on site contamination, the responsibility of Syndial in the contamination of the site, the criteria of estimate remediation costs, which according to the Company are erroneous, arbitrary and technically inadequate. On October 7, 2009 an independent appraiser report was filed that reviewed the environmental status of the site and estimated the remediation costs while the estimate of both the health damage caused by the pollution and the environmental damage would be issued in a further independent appraiser report. The findings of the independent appraisers are substantially in line with the issues expressed by Syndial on the measures for

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		the environmental remediation and clean-up, based on a risk analysis aimed to define effective and specific actions. The clean-up project, approved to a great extent by the ministry for the Environment and the Calabria Region, has been considered substantially adequate. The independent appraisers affirmed the necessity of clean-up measures that were not planned by Syndial on one of the external areas (the so-called archaeological area) and considered being unnecessary the dredging of sea sediments. The estimated clean-up costs are in line with the estimate made by Syndial. The independent appraiser report is less favorable to Syndial because it identifies as source of the contamination the production slag management, even recent. The independent appraiser report evaluated that the production technology was a BAT (best available technology), instead the slag treatment could be performed in a more respectful way for the environment and the products (the so-called Cubilot) lacked the physic-chemical characteristic of stability that would avoided the emission of polluting agents in the soil. As regards the quantification of the environmental damage different by the remediation, the independent report APAT provided by the Ministry of Environment quantified the damage for the lack of fruition of the site basing on the remediation costs that were significantly reduced by the independent appraiser report. In case the judge resolves on the responsibility of Syndial in the contamination of the site based on the conclusions of the independent appraiser report, the Company could be liable, for the environmental damage different from the goods fruition (damage to the community, increases in the regional health expenditures), at least in part and as far as the damage is actually probed. On November 14, 2009, Syndial filed its objections to the independent appraiser report, sharing the conceptual model adopted by the independent appraiser report but demonstrating that the site contamination should be charged mainly to past management of the pollution slag on part of other operators that operated the site until the '70s. On November 11, 2009 the Calabria Region filed its objection to the independent appraiser report affirming that the environmental damage to the surrounding areas of the site has not been assessed by the independent appraisers. The hearing for the review of the independent appraiser report and of the parts objections has yet to be held, as it has been assigned to another judge. In order to arrange for a possible resolution of all environmental claims, in 2007 Eni’s subsidiary Syndial took charge of the management of the clean-up activities and on December 5, 2008 presented a new clean-up project. As for the approval procedure of the abovementioned project all interested parties approved the removal of the dump from the seafront to another area, the construction of an hydraulic barrier and of the related treatment plant of the groundwater (providing that if the subsequent monitoring would demonstrate the efficiency of the plant, Eni’s subsidiary would build up a physical barrier in the seafront) and the start-up of the first lot of activities on the soil through in situ technologies on condition that all the waste present in the areas, recognized after a specific inspection. Initially, the environmental provision made by Syndial in its financial statements amounted to euro 103 million based on the cost estimation of the original clean-up project, as the Eni’s subsidiary believes to have no responsibility for the environmental damage considering the limited period during which it conducted industrial activities in the site and the Delegated Commissioner responsibility for not having properly managed the site cleanup activities. In the 2008 financial statements, Eni increased the environmental provision by euro 154 million bringing the total amount of the environmental provision related to the clean-up project to euro 257 million. The provision doesn’t cover the entire amount of clean-up project expenses (euro 300 million) considering the circumstance that it has been only partially approved. It must be noted that in 2003 the Delegated Commissioner for Environmental Emergency, Calabria Region and Province of Crotone presented a first claim for the payment of damages. 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 appeal against that decision is pending. The claims made in this first instance are substantially absorbed in the two subsequent proceedings.
(iv)		Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore - Prosecuting body: Ministry of the Environment. 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. On occasion of the 2008 consolidated financial statements, management confirmed its stance of making no loss provision for this proceeding on the basis of the abovementioned technical legal advice, in concert with external consultants on accounting principles. In July 2009, Eni’s subsidiary Syndial filed

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		an appeal against the abovementioned sentence, also requesting suspension of the sentence effectiveness. The Ministry of the Environment, in the appeal filed, requested to the Second Instance Court to adjust the first degree sentence condemning Syndial to the payment of euro 1,900 million or alternatively euro 1,300 million in addition to the amount assessed by the First Degree Court. In the hearing on December 11, 2009, the Second Instance Court considering the modification of Environmental Damage regulation introduced by the Article 5-bis of the Law Decree No. 135/2009 and following a request of the Board of State lawyers decided the postponement to May 28, 2010, pending the Decree of the Ministry of the Environment related to the determination of the quantification criteria for the monetary compensation of the environmental damage pursuant to the abovementioned Article 5 of the Law Decree 135/2009. The Board of State lawyers committed itself to not examine the sentence until the next hearing. 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 has been approved by all interested parties, including the Ministry and local municipalities pursuant to the statement on April 28, 2009, which included certain recommendations. Syndial appealed against this statement and the related Ministerial Decree of approval in order to avoid the case to give implicit consent to the request (appealed by the Company) of the Minister that claimed that Syndial is obliged to execute the clean-up. On the contrary, Syndial has agreed on the scope of the plan to ascertain the environmental status of the site, as it has been actually implementing it. Syndial also presented a clean-up project for the groundwater and the soil, that hasn’t been approved, as the abovementioned prescriptions that have been prescribed are the object of the Company opposition in the abovementioned proceeding. In case Syndial should be found guilty, it would incur remediation and cleanup expenses, actually not quantifiable, that would be offset against any compensation for the environmental damage that Eni’s subsidiary is condemned to pay with regard to civil proceeding pending before the second instance court of Turin.
(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 unavoidable environmental damage (amounting to euro 139 million), further damages of various types (e.g. damage to the natural beauty of this site) amounting to euro 80 million as well as damages relating to loss of profit and property amounting to approximately euro 16 million. This request is related to an accident that occurred in 1984, as a consequence of which EniChem Agricoltura SpA (later merged into Syndial SpA), at the time owner of the site, carried out safety and remediation works. The Ministry 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 charged 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 the Environment. Both plaintiffs filed an appeal against this decision in June 2008 confirming the requests issued in the first judgment degree and a total compensation of euro 189.8 million. Syndial filed in the appeal hearing, disputing the plaintiffs’ claims. The proceeding is underway without any further investigation. The hearing has been postponed to July 2010 for the filing of the pleadings.
(vi)		Ministry for the Environment Augusta harbor. The Italian Ministry for the Environment with various administrative acts prescribed companies running plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Polimeri Europa, Syndial and Eni R&M. Pollution has been detected in this area primarily due to a high mercury concentration which is allegedly attributed to the industrial activity of the Priolo petrochemical site. The abovementioned companies 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 the sentence No. 1254/2007 annulled the said decisions. The Ministry and the municipalities of Augusta and Melilli filed a claim for the revocation of the decision and requested the suspension of sentence effectiveness with the Administrative Council of the Sicily Region which accepted the claim. The recommendations which

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the Council’s decision related, have been restated by the Ministry for the Environment with further administrative resolutions that have been appealed by the Eni companies. Again the Regional Administrative Court of Catania reiterated its decision to suspend the effectiveness of the Ministry’s acts. In January 2008 the Regional Court of Catania accepted further claims on this matter. In June 2008 the Ministry for the Environment and the Municipalities of Melilli and Augusta filed an appeal against the decision of the Regional Court of Catania with the Administrative Council of the Sicily region, without a resolution of the issue of suspending the effectiveness of the Regional Court’s decisions. The hearing for the examination of both appeal pending with the Administrative Council of the Sicily Region that has been originally scheduled on December 11, 2008, has been postponed sine die due to preliminary issues pending with the Court of Justice of the European community. In April 2008, the Eni companies challenged certain administrative acts of December 20, 2007 related to the execution of further clean-up and remediation works of sediments in the Augusta harbor. In this proceeding the Regional Court of Catania has ordered an independent appraiser report, issued on February 20, 2009, that resulted favorable to the objections of the recurring companies. The proceeding is pending. In May 2008, the Eni companies also challenged with the Regional Court of Catania, requesting the suspension of administrative act effectiveness, certain decisions of an Administrative Body on March 6, 2008 (and other subsequent decisions). Those decisions were intended to enlarge the scope of the already approved project of environmental remediation and clean-up of the groundwater trough works of physic limitation and the new criteria used by the Administration Body in the restitution of the areas to their legitimate use. With regard to this last proceeding, basing on a request of the appealing companies, the Regional Court of Catania requested the decision of the Court of Justice of EU to decide on the correct application of the community principle, that represent the basis for the all appeals’ decision particularly the principles of the liability associated with the environmental damage, the proportionality in bearing the expenditures associated with environmental remediation and clean-up, as well as a criteria of reasonableness and diligent execution in remedying an environmental damage. On March 9, 2010 the European Court gave a sentence that basically represented a favorable outcome for Eni’s subsidiaries involved in the matter. Specifically, the European Court confirmed the community principle of the liability associated with the environmental damage, whereby central to its correct interpretation is the relation between cause and effect and the identification of the entity that is actually liable for polluting. It must be noted that the Public prosecutor of Siracusa commenced a criminal action against unknown in order to verify the effective contamination of the Augusta harbor and the connected risks on the execution on the clean-up project proposed by the Ministry. The technical assessment disposed by the Public Prosecutor generated the following outcomes: a) no public health risk in the Augusta harbor; b) absence of any involvement on part of Eni companies in the contamination; c) drainages dangerousness. Based on those findings, the Public Prosecutor decided to dismiss the proceeding.

 

ENI SPA
(vii)		Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe - Prosecuting body: Delegated Commissioner. In March 2009 Eni and its subsidiary Sofid (now Eni Adfin) were notified of a bankruptcy claw-back as part of a reorganization procedure filed by the airlines companies Volare Group, Volare Airlines and Air Europe which commenced under the provisions of Ministry of Production Activities, on November 30, 2004. The request regarded the override of all the payments made by those entities to Eni and Eni Adfin, as Eni agent for the receivables collection, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, for a total estimated amount of euro 46 million plus interest. Eni and Eni Adfin were admitted as defendants and the trial has been postponed to the hearing on May 5, 2010 for the related investigation. Eni accrued a risk provision with respect to this proceeding.

 

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. 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 and Terni Industrie Chimiche SpA (both merged into Syndial). Such receivables were transferred by Agricoltura and Terni Industrie Chimiche to Serfactoring, which appointed Agrifactoring as its agent to

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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, claiming for the reimbursement of the amount paid to Serfactoring and not liquidated to Agrifactoring by Federconsorzi. Syndial and Serfactoring filed 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 was subsequently reduced to euro 46 million following partial payment of the original receivables by the liquidator of Federconsorzi and various setoffs. These proceedings, which were unitized, were decided with a partial judgment, deposited on February 24, 2004; the request of Agrifactoring – that was reduced by an independent accounting consultant to the amount of euro 42.3 million – was rejected and the company was ordered to pay the sum requested by Serfactoring and Syndial to be determined following the decision. Agrifactoring appealed this decision and in 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 Agrifactoring the sum paid by the latter to the former and not refunded by Federconsorzi. The Court resolved to charge an independent accounting consultant with quantifying the total amount paid by Agrifactoring to Serfactoring and the amount paid by Federconsorzi to Agrifactoring in order to determine the sum to be reimbursed to Agrifactoring. The proceeding will continue with the recognition of the assessment made by the independent accounting consultant. Serfactoring and Syndial (as precautionary measure, since they have already filed a preliminary appeal) appealed the above mentioned partial sentence of 2008 of the second instance court of Rome with an upper degree Court. Agrifactoring in turn filed counterclaim, requesting the declaration of inadmissibility or the rejection of the appeal.. The judgment is still pending. Eni accrued a provision with respect to this proceeding.

 

SAIPEM SPA
(ii)		CEPAV Uno and CEPAV Due. Saipem 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 then increased to euro 1,770 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. The deadline for the submission of the arbitration determination has been scheduled for December 27, 2011. With regard to the project for the construction of a high-speed railway from Milan to Verona, on 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, commenced on December 28, 2000, requested by CEPAV Due against TAV for the recognition of costs incurred by the Consortium in the ten year period from 1991 through 2000 plus damages suffered, in January 2007, the arbitration committee determined the Consortium’s right to recover the costs incurred in connection with the design activities performed. The technical independent survey to assess the amount of compensation was submitted on October 19, 2009. The trial ended on February 23, 2010 with the resolution of the arbitration that condemned TAV to pay to CEPAV Due consortium an amount of euro 44,176,787 plus legal interest and compensation for inflation accrued from the submission of the arbitration until the date of effective damage payment; the court also condemned TAV to pay euro 1,115,000 plus interest and compensation for inflation accrued from October 30, 2000 until the date of effective damage payment. The resolution has been filed with relevant administrative authorities for its efficacy as per applicable regulations. TAV filed with the second instance court of Rome an appeal against the partial arbitration committee’s determination of January 2007. The hearing for the examination of the pleadings has been scheduled for January 28, 2011. In February 2007, the Consortium CEPAV Due notified to TAV a second request of arbitration following the 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. 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. The second arbitration proceeding, which continued in order to

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determinate the damages suffered by the Consortium even in the period prior to the revocation of the concession through an independent appraiser report. The deadline for the submission of the arbitration determination has been scheduled for December 31, 2010.

 

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)		European Commission’s investigations on players active in the natural gas sector. In the context of its initiatives aimed at verifying the level of competition in the natural gas sector within the European Union, the Commission adopted a decision – notified to Eni in May 2006 – whereby it ordered Eni and all companies solely or jointly controlled by the latter to submit to inspections pursuant to Article 20, paragraph 4 of the Council Regulation No. 1/2003. The inspections were intended to verify the possible existence of behaviors or commercial practices violating EC competition rules and aimed at limiting access to the Italian wholesale natural gas market or at sharing the market with other companies active in the sale or transport of natural gas. The Commission undertook similar initiatives with respect to the other largest European players in the natural gas sector in Germany, France, Austria and Belgium. On March 9, 2009, Eni received a statement of objections by the European Commission relating to a proceeding under Article 82 EC and Article 54 of the EEA Agreement and concerning an alleged unjustified refusal to grant access to the TAG (Austria), TENP/Transitgas (Germany/Switzerland) pipelines, connected with the Italian gas transport system. In particular, according to the Statement of Objections, the alleged refusal to grant access would have been carried out through "capacity hoarding, capacity degradation and strategic underinvestment" and would have had the effect of "hindering the development of effective competition in the downstream market and [...] harming consumers". In the Statement of Objections, the Commission envisages the possible imposition upon Eni of structural remedies and a fine, which, if imposed, could be significant. Eni after the completion of the assessment of the allegations set forth by the Commission in Statement of Objections with respect to both the existence of the alleged behaviors and whether they can be properly qualified as infringements of EC competition rules submitted its written reply that was exposed before the representatives of the Commission in November 27, 2009. On February 4, 2010 Eni, reaffirming the legitimacy of its activity, filed with the European Commission a number of structural remedies with a view to resolving the proceeding without the ascertainment of the illicit behavior and consequently without sanctions. Eni has committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. Given the strategic importance of the Austrian Tag pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake to an entity controlled by the Italian State. The European Commission has announced its intention to submit those remedies to a market test. According to the results of the market test, the Commission may issue a decision pursuant to Article 9 of Council Regulation No. 1/2003, making the remedies mandatory thus excluding the imposition of any fines upon Eni. In case the Commission, after the performance of the market test, resolves to reject Eni’s remedies, or the Company decides to withdraw those remedies for any reasons, the ordinary antitrust proceeding would resume and in this eventuality an adverse conclusion cannot be excluded, thus resulting in a sentence of conviction including a fine and possibly structural remedies during the course of 2010. Eni would in any event be entitled to file an appeal for the annulment of such a sentence before the EC Courts.
(iii)		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

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		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 partt 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.
(iv)		Italian Antitrust Authority’s inquiry in the distribution and selling of gas in the retail sector. On May 7, 2009, the Italian Antitrust Authority, based on complaints sent by the company Sorgenia, started a preliminary investigation against various operators engaging in the gas retail market in Italy by means of integrated operations in both gas distribution via local low-pressure network and gas marketing to retail customers in urban areas, among them the Company and its fully-owned subsidiary Italgas. 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 customers consuming less than 200,000 CM/y to change the supplier. According to the Italian Antitrust Authority, these commercial practices would enable selling companies that belong to integrated group companies to preserve their market shares in the areas operated by group’s distributors. The deadline for the finalization of the preliminary investigation against Eni and Italgas has been scheduled for June 30, 2010.

 

ENI SPA, POLIMERI EUROPA SPA AND SYNDIAL SPA
(v)		Inquiries in relation to alleged anti-competitive agreements in the area of elastomers - Prosecuting Body: European Commission. 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, a proceeding is still pending before the European Commission regarding the NBR product. 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 (BR and SBR) resulted in the ascertainment of Eni having infringed European competition laws. 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 hearings took place in October 2009 and the filing of the Court’s decisions is still pending. Pending the outcome, Polimeri Europa presented a bank guarantee for euro 200 million and paid the residual amount of the fine. In August 2007, with respect to the above mentioned decision of the European Commission, Eni submitted a request for a negative ascertainment with the Court of Milan aimed at proving the non-existence of alleged damages suffered by tire BR/SBR manufacturers. The Court of Milan declared the appeal inadmissible appealing against a sentence of the District Court of Milan; the related hearing has been scheduled for May 2010.

 

3.2 Regulation

(i)		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. During the hearing on 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 and the defendant in December 2009 filed an appeal against the said decision.
(ii)		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

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		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.
(iii)		Preliminary investigation of the Authority for Electricity and Gas on the application of the regulation on the issue of the transparency of invoices. On September 25, 2009 the Authority for Electricity and Gas sentenced (sentence VIS 93/2009) to commence a preliminary investigation against 5 marketing companies in the electricity sector, including Eni, to ascertain the eventual violation of the regulation on the issue of the transparency of the invoices (Resolutions 152/2006, 156/2007 and 272/2007) and to eventually inflict administrative monetary penalties.

 

4. Tax Proceedings

ITALY - ENI SPA
(i)		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 charged an independent consultant with assessing all the accounting/technical aspects of the matter. The independent consultant confirmed that Eni’s offshore installations lack any ground to be subject to the municipal tax that was claimed by the local Municipality. Those findings were accepted by the Regional Tax Commission with a ruling made on January 19, 2009, and filed on December 14, 2009. Also on December 28, 2005, also the Municipality of Pineto presented similar claims relating to the same Eni platforms for the years 1999 to 2004. The total amount requested was euro 24 million including interest and penalties. Eni filed a claim against this claim which was accepted by the first degree judge with a decision of December 4, 2007. Similar formal assessments related to Eni oil and gas offshore platforms were presented by the Municipalities of Falconara Marittima, Tortoreto, Pedaso, and also from 2009 the Gela Municipality. The total amounts of those claims were approximately euro 7.5 million. The company filed appeal against all those claims. With reference to the formel claims to Eni’s platforms presented by the Municipality of Tortoreto the first degree judge, with a decision of March 1, 2010, accepted the request of Eni.

 

OUTSIDE ITALY - AGIP KARACHAGANAK BV
(ii)		Claims concerning unpaid taxes and relevant payment of interest and penalties. In July 2004, relevant Kazakh Authorities informed Agip Karachaganak BV and Karachaganak Petroleum Operating 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 engage in International Arbitration proceedings with the Kazakh Authorities. In October 2009, Kazakh Tax Authorities conducted a complex tax audit of Agip Karachaganak BV Branch and Karachaganak Petroleum Operating Co BV Branch, for the period 2004-2007. In December 2009, the tax authorities issued Tax Audit Act and relevant Notification for the year 2004 but so far nothing has been finalized for the later years. The 2004 audit resulted in an assessment of $21.6 million relating to CIT and WHT ($0.3 million). These amounts are disputed and appeals have been submitted to the Higher Level Tax Authority. There is also a dispute in relation to certain unresolved items of expenditure incurred by the operating company Karachaganak Petroleum Operating

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BV which has led to the Kazakh Authorities making certain claims against the company on the base of audits performed relating to prior years 2003-2006. Parties are negotiating in order to settle the dispute.

(iii)

Tax proceeding Eni Angola Production BV. In the first months of 2009 the Ministry of the Finance of Angola, following a fiscal audit commenced at the end of 2007, filed a notice of tax assessment for fiscal years 2002 to 2007 in which it objected to the deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as co-operator of Cabinda concession. The company filed an appeal against this decision with the Provincial Court of Luanda for all the years of the claim. The Court of First Instance declared that it lacked competence in judging the matter. The judgment is still pending before the Supreme Court. Eni accrued a provision with respect to this proceeding.

 

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 (now Saipem SpA) (contractor of engineering and procurement services) with notices of process in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In 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 took the necessary steps in acting as plaintiff in the expected legal action in order to recover any damage that could have been caused to Eni by the illicit behavior of its suppliers and of their and Eni employees. In the meantime, preliminary investigations have found that both EniPower and Snamprogetti are not to be considered defendants in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the judge for the preliminary hearing requested all the parties that have not requested the plea-bargain to stand in trial, excluding Romeo Franco Musazzi and ABB Instrumentation SpA as a result of the statute of limitations. During the hearing on March 2, 2010 the Court confirmed the admission as plaintiffs of Eni SpA, EniPower SpA and Saipem SpA against the inquired parties under the provisions of Legislative Decree No. 231/2001. The trial continues.

(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 requests issued by the public prosecutor. Based on the decision of the judge for preliminary hearings the public prosecutor of Rome notified Eni, as injured party, the summon against two former managers of the company charged of aggravated fraud related to the relevant patrimonial damage caused to the injured party through the abuse of working relations and activities. The first hearing took place in March 30, 2010 and the Company established itself as plaintiff. The proceeding is still pending.

(iii)

TSKJ Consortium Investigations by U.S., Italian, and Other Authorities. Snamprogetti Netherlands BV has a 25% participation in the TSKJ Consortium companies. The remaining participations are held in equal shares of 25% by Halliburton/KBR, Technip, and JGC. Beginning in 1994 the TSKJ Consortium was involved in the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti SpA, the holding company of Snamprogetti Netherlands BV, was a wholly owned subsidiary of Eni until February 2006, when an agreement was entered into for the sale of Snamprogetti to Saipem SpA and Snamprogetti was merged into Saipem as of October 1, 2008. Eni holds a 43% participation in Saipem. In connection with the sale of Snamprogetti to Saipem, Eni agreed to indemnify Saipem for a variety of matters, including potential losses and charges resulting from the investigations into the TSKJ matter referred to below, even in relation to Snamprogetti subsidiaries. The

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U.S. Securities and Exchange Commission (SEC), the U.S. Department of Justice (DOJ), and other authorities, including the Public Prosecutor’s office of Milan, are investigating alleged improper payments made by the TSKJ Consortium to certain Nigerian public officials. The proceedings in the U.S.: beginning in June 2004, Eni and Saipem/Snamprogetti voluntarily provided information in response to requests by the SEC and the DOJ in connection with the investigations. In February 2009, KBR and its former parent company, Halliburton, announced that they had reached a settlement with the SEC and the DOJ with respect to the TSKJ matter as well as other unspecified matters. KBR/Halliburton pleaded guilty to Foreign Corrupt Practices Act (FCPA) charges, for the conduct stemming from their participation in TSKJ, and they have agreed to pay a criminal fine of $402 million to the DOJ and a civil penalty of $177 million to the SEC. In view of the agreements entered into by KBR/Halliburton with the DOJ and SEC, the TSKJ matter could result in legal liability on the part of individuals as well as the other members of the TSKJ Consortium Entities found in violation of the FCPA, and those entities could be subject to substantial fines and the imposition of ongoing measures by the U.S. government to prevent future violations, including potentially a monitor of internal controls, and debarment from government contracts. In a press release on February 12, 2010, the French company Technip announced, as a result of the circumstances that its discussions with U.S. authorities had intensified over the prior weeks, the recognition of a provision for an amount of euro 245 million reflecting the estimated cost of resolution with such authorities. As to Eni, discussions with the U.S. authorities have intensified recently. Based on the ongoing status of the discussions, the Company has estimated the cost of a global resolution of the matter with the U.S. authorities and recorded a provision of euro 250 million also considering the contractual obligations assumed by Eni to indemnify Saipem as part of the divestment of Snamprogetti. The proceedings in Italy: beginning in 2004, the TSKJ matter has prompted investigations by the Public Prosecutor’s office of Milan against unknown persons. Since March 10, 2009, the Company has received requests of exhibition of documents from the Public Prosecutor’s office of Milan. On July 17, 2009, the date on which a search and attachment warrant was served on Saipem/Snamprogetti, the Public Prosecutor’s office of Milan indicated to the company that it is investigating one or more people, including at least one former manager of Snamprogetti; previously, as far as the company knew, none of its employees or former employees was under formal investigation. The events under investigation cover the period since 1994 and also concern the period of time subsequent to the June 8, 2001 enactment of Italian Legislative Decree No. 231 concerning the liability of legal entities. A violation of Legislative Decree June 8, 2001, No. 231 can result in the confiscation of criminal profits in addition to administrative penalties. During the preliminary investigations, the preventive attachment of such profits and other precautionary measures are possible. On July 31, 2009, a decree issued by the Judge for Preliminary Investigation at the Court of Milan was served on Saipem SpA (as legal entity incorporating Snamprogetti SpA). The decree set for September 22, 2009 a hearing in Court in relation to a proceeding ex Legislative Decree No. 231 of June 8, 2001 whereby the Public prosecutor of Milan is investigating Eni SpA and Saipem SpA for liability of legal entities arising from offences involving international corruption charged to two former managers of Snamprogetti SpA. The Public Prosecutor of Milan requested Eni SpA and Saipem SpA to be debarred from activities involving – directly or indirectly – any agreement with the Nigerian National Petroleum Corporation and its subsidiaries. The above mentioned hearing allowed Eni and Saipem to their own defenses before any decision was made on the requested disqualification. The events referred to the request of precautionary measures of the Public Prosecutor of Milan cover TSKJ Consortium practices during the period from 1995 to 2004. In this regard, the Public Prosecutor claims the inadequacy and violation of the organizational, management and control Model adopted to prevent those offences charged to people subject to direction and supervision. At the time of the events under investigation, the Company had adopted a code of practice and internal procedures with reference to the best practices at the time. Subsequently, such code and internal procedures have been improved aiming at the continuous improvement of internal controls. Furthermore, on March 14, 2008 Eni approved a new Code of Ethics and a new Model 231 reaffirming that 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 behaviors that conflict with the principles and contents of the Code. Since April 23, 2009, with regard to investigations on the TSKJ matter the Company’s Board of Directors has timely recalled the analysis of the existing internal procedures against corruption, in order to implement any upgrading to be possibly needed, and to continue the cooperation with the relevant authorities and also resolved to promote all legal measures for protecting the Company’s interests and reputation, in the event the responsibility of its employees or collaborators is verified. The jury room of September 22, 2009 was postponed to the hearing of October 21, 2009 when the judge for the preliminary investigation rejected the request of precautionary measures of disqualification filed by the Public Prosecutor of Milan against Eni and Saipem. The Public Prosecutor of Milan appealed the decision of the Judge for Preliminary Investigation. The hearing for the review of the appeal, scheduled initially for January 20, 2010 was moved up, through a measure communicated to the defense on January 12, 2010, on January

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		19, 2010 when the Judge of Re-examination dismissed as unfounded the appeal of the Public Prosecutor. In February 19, 2010 the Public Prosecutor of Milan filed an appeal with the Third Instance Court, asking for the cancellation of the abovementioned decision of the Judge of Re-examination. At the same time on February 11, 2010 the Public Prosecutor of Milan requested, according to Article 248 of Penal Code the collection of documentation and information related to companies participated by Eni SpA and Saipem SpA (former Snamprogetti SpA) involved in the Bonny Island project.
(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, inter alia, the offense contemplated by Legislative Decree of June 8, 2001, No. 231, which establishes the liability of the legal entity for crimes committed by its employee in the interests of such legal entity, or to its advantage. Accordingly, notice of the commencement of investigations was served upon Eni Group companies (Eni, Snam Rete Gas and Italgas) as well as third party companies. On November 26, 2009 a notice of conclusion of the preliminary investigation was served to Eni’s Group companies whereby 14 Eni employees, also including former employees, are under investigation. The exceptions filed in the notice include: (i) violations pertaining to recognition and payment of certain amounts of the excise on natural gas; (ii) violations or failure in submitting the annual statement of gas consumption and/or in the annual declarations to be filed with the Duty Authority or the Authority for Electricity and Gas; and (iii) a related obstacle which has been allegedly posed to the monitoring functions performed by the Authority for Electricity and Gas. Based on information reported by the press on March 9, 2010, it has been disseminated that the Public Prosecutor of Milan requested that a number of investigated Eni’s employees and former employees would stand trial. On February 23, 2010 Eni, Snam Rete Gas and Italgas received a notification requesting the collection of documents related to procedures of constitution, definition, update and implementation of Model 231 in the period from 2003 to 2008. 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.
(vi)		Kazakhstan. On October 1, 2009 the Public Prosecutor of Milan requested a number of documents pursuant to Article 248 of the Penal code. Through this decision, part of a criminal proceeding against unknown parties, Eni SpA was requested to transmit – in relation to the alleged international corruption, embezzling pillage, and other crimes – audit reports and other documentation related to anomalies and critical issues on the management of: the Karachaganak plant; and the Kashagan project. The crime of "international corruption" mentioned in the said request of transmission of documents is sanctioned, in addition to the Italian criminal code, by Legislative Decree June 8, 2001 No. 231 which establishes the administrative responsibility of companies for crimes committed by their employees on their behalf. Eni commenced the collection of the documentation in order to rapidly fulfill the requests of the Public Prosecutor. The company has deposited in different phases the documents collected. The Company continues to fully collaborate with the Public Prosecutor providing also further documentation when available.

 

6. Settled Proceedings

(i)

Preliminary investigation of the Authority for Electricity and Gas about application of the "K" conversion factors for volumes adjustments. In May 2009 the Authority for Electricity and Gas, based on evidence collected during certain inspections and subsequent requests of information, communicated to the Company the results of an inquiry that stated that the company improperly applied the conversion factor "K" for natural gas volumes accounting at a number of Eni’s delivery points. The company filed its conclusions in a defensive memorandum, objecting to the Authority’s findings. On the basis of a comparative evaluation of the sanctions imposed at the end of analogous inquiries commenced against other gas companies, Eni accrued a risk provision with respect to this proceeding. On October 5, 2009 the Authority for Electricity and Gas with sentence VIS 94/2009 upheld partially Eni’s objections and recognized that the obligation to apply the "K" conversion index for marketing companies as determined by the distribution companies was effective from 2004 as opposed to the year 2001 as initially stated by the Authority for Electricity and Gas. This decision determined in one case the ceasing of the

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		infringement as well as the reduction of the liability and associated duration in all the other cases. The Authority for Electricity and Gas imposed a fine amounting to euro 1,023,000 on Eni that was fully covered by the accrued risk provision. Eni paid the sanction even if the Company considers its motivations to be well grounded in the appeal proposed against the Authority for Electricity and Gas findings before the Administrative Court in December 2009.
(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 an 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. In 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 paid the fine which was fully covered by the accrued risk provision, filing however for recourse against this decision.

(iii)

Alleged unauthorized waste management activities - EniPower. 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. In the hearing on April 6, 2009 the judge dismissed the accusation as a result of the statute of limitations.

 

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 exploration and development activities and it is entitled to the productions realized. In Production Sharing Agreement and in buy-back contracts, realized productions are defined on the basis of contractual agreements drawn up with State oil companies which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (cost oil) and give entitlement to the retained 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 twenty years 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 expiration 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". In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding

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the environmental risk, management does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remedial actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of the ongoing surveys and the other possible effects of statements required by 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 Resolution 20/2008 defining emission permits for the 2008-2012 period.

Eni was assigned permits corresponding to 126.4 mmtonnes of carbon dioxide (of which, 25.8 in 2008, 25.8 in 2009, 25.1 in 2010, 25.0 in 2011, 24.7 in 2012) and in addition to approximately 8.6 million 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 2009. Against emissions of carbon dioxide amounting to approximately 24.8 mmtonnes, emission permits amounting to 25.9 mmtonnes were assigned, determining a 1.1 mmtonnes surplus. In addition to such surplus, a 0.3 mmtonnes of permits (an increase in the availability of Eni) are to be included following the contract of Virtual Power Plan GDF Suez Energia Italia, primarily assigned to cover the emissions of the EniPower plants. For this reason, the total surplus amounted to about 1.4 mmtonnes.


29 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)		2007		2008		2009

Net sales from operations		87,051			107,777			83,519
Change in contract work in progress		153			305			(292	)
		87,204			108,082			83,227

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Net sales from operations were net of the following items:

(euro million)		2007		2008		2009

Excise taxes		13,292		13,142		12,122
Exchanges of oil sales (excluding excise taxes)		2,728		2,694		1,680
Services billed to joint venture partners		1,554		2,081		2,435
Sales to service station managers for sales billed to holders of credit cards		1,480		1,700		1,531
Exchanges of other products		121		83		55
		19,175		19,700		17,823

Net sales from operations by business segment and geographic area of destination are presented in Note 35 – Information by business segment and geographic financial information.

Other income and revenues
Other income and revenues were as follows:

(euro million)		2007		2008		2009

Gains from sale of assets		66			48			306
Lease and rental income		95			98			100
Compensation for damages		87			15			54
Contract penalties and other trade revenues		181			23			31
Gains on price adjustments under overlifting/underlifting transactions		79			180			148
Other proceeds (*)		325			364			479
		833			728			1,118

(*)		Each individual amount included herein does not exceed euro 50 million.

Gains from sale of assets amounted to euro 306 million of which euro 283 million related to the Exploration & Production segment.


30 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".

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Purchase, services and other
Purchase, services and other included the following:

(euro million)		2007		2008		2009

Production costs - raw, ancillary and consumable materials and goods		44,850			58,662			40,311
Production costs - services		10,828			13,355			13,520
Operating leases and other		2,276			2,558			2,567
Net provisions for contingencies		573			884			1,055
Other expenses		1,101			1,660			1,527
		59,628			77,119			58,980
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(1,357	)		(680	)		(576	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(138	)		(89	)		(53	)
		58,133			76,350			58,351

Production costs-services included brokerage fees related to Engineering & Construction segment in the amount of euro 79 million (euro 37 million and euro 155 million for the years ended December 31, 2007 and 2008, respectively).

Costs incurred in connection with research and development activity recognized in the profit and loss account amounted to euro 207 million (euro 189 million and euro 216 million for the years ended December 31, 2007 and 2008, respectively) as they do not meet the requirements to be capitalized.

The item "Operating leases and other" included operating leases in the amount of euro 1,220 million (euro 1,081 million and euro 957 million for the years ended December 31, 2007 and 2008, respectively) and royalties on hydrocarbons extracted in the amount of euro 641 million (euro 772 million and euro 871 million for the years ended December 31, 2007 and 2008, respectively). Future minimum lease payments expected to be paid under non-cancellable operating leases were as follows:

(euro million)		2007		2008		2009

To be paid within 1 year		588			618			886
Between 2 and 5 years		1,401			2,585			2,335
Beyond 5 years		942			1,084			1,034
		2,931			4,287			4,255

Operating leases primarily relate to 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 1,055 million (euro 573 million and euro 884 million for the years ended December 31, 2007 and 2008, respectively) and mainly related to legal or other proceedings in the amount of euro 333 million (euro 79 million and euro 55 million for the years ended December 31, 2007 and 2008, respectively) and environmental risks in the amount of euro 258 million (euro 327 million and euro 360 million for the years ended December 31, 2007 and 2008, respectively). More information is included in Note 21 – Provisions for contingencies.

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Payroll and related costs
Payroll and related costs were as follows:

(euro million)		2007		2008		2009

Wages and salaries		2,906			3,204			3,330
Social security contributions		690			694			706
Cost related to defined benefits plans and defined contributions plans		161			107			137
Other costs		275			282			342
		4,032			4,287			4,515
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(184	)		(235	)		(280	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(48	)		(48	)		(54	)
		3,800			4,004			4,181

Average number of employees
The average number and break-down of employees by category of Eni’s subsidiaries were as follows:

(euro million)		2007		2008		2009

Senior managers		1,594			1,621			1,653
Junior managers		11,816			12,597			13,255
Employees		35,725			36,766			37,207
Workers		25,582			26,387			26,533
		74,717			77,371			78,648

The average number of employees was calculated as the average between the number of employees at the beginning and end of the respective period. The average number of senior managers include managers employed and operating in foreign countries, whose position is comparable to that of a senior manager.

 

Stock-based compensation

Stock option
In 2009, Eni suspended the incentive plan based on the stock option assignment to managers of Eni and its subsidiaries as defined in Article 2359. The following is the information about the residual plans of past periods.

As of December 31, 2009 19,482,330 options were outstanding for the purchase of 19,482,330 Eni ordinary shares (nominal value euro 1 each). The break-down of outstanding options are as follows:

		Rights outstanding as of Dec. 31, 2009		Average strike price (euro)

Stock option plan 2002		97,000		15.216
Stock option plan 2003		229,900		13.743
Stock option plan 2004		671,600		16.576
Stock option plan 2005		3,281,500		22.512
Stock option plan 2006		3,018,155		23.119
Stock option plan 2007		5,144,050		27.451
Stock option plan 2008		7,040,125		22.540
		19,482,330

As of December 31, 2009 the weighted-average remaining contractual life of the plans at December 2002, 2003, 2004, 2005, 2006, 2007 and 2008 plans were 7 months, 1 years and 7 months, 2 years and 7 months, 3 years and 7 months, 2 years and 7 months, 3 years and 7 months and 4 years and 7 months, respectively.

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The 2006-2008 stock option plans have 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 after three years from the assignment (vesting period) and for a minimum period of three years. The strike price is calculated as an arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the assignment.

In 2009, changes of stock option plans consisted of the carry-over of the previous plans. The following table summarizes these changes:

		2007		2008		2009

Number of shares

Average strike price (euro)

Market price (a) (euro)

Number of shares

Average strike price (euro)

Market price (a) (euro)

Number of shares

Average strike price (euro)

Market price (a) (euro)

Rights outstanding as of January 1		15,290,400			21.022		25.520		17,699,625			23.822		25.120		23,557,425			23.540		16.556
New rights granted		6,128,500			27.451		27.447		7,415,000			22.540		22.538
Rights exercised in the period		(3,028,200	)		16.906		25.338		(582,100	)		17.054		24.328		(2,000	)		13.743		16.207
Rights cancelled in the period		(691,075	)		24.346		24.790		(975,100	)		24.931		19.942		(4,073,095	)		13.374		14.866
Rights outstanding as of December 31		17,699,625			23.822		25.120		23,557,425			23.540		16.556		19,482,330			23.576		17.811
of which exercisable at December 31		2,292,125			18.440		25.120		5,184,250			21.263		16.556		7,298,155			21.843		17.811

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 option plans amounted to euro 12 million (euro 27 million and euro 25 million for the years ended December 31, 2007 and 2008, respectively).

 

 

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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) in office for the years ended December 31, 2007, 2008 and 2009 amounted to euro 25 million, euro 25 million and euro 35 million, respectively, and consisted of the following:

(euro million)		2007		2008		2009 (*)

Wages and salaries		17			17			20
Post-employment benefits		1			1			1
Other long-term benefits		3			3			10
Stock grant/option		4			4			4
		25			25			35

(*)		Comparing with the previous years, the increase is attributable to a different composition of key managers and to the introduction, as substitution of stock options, of deferred bonus. The fair value of such bonus is recognized in the year while the fair value of stock options was recognized pro-quota along the duration of the plan.

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 8.9 million, euro 6.4 million and euro 9.9 million for the years ended December 31, 2007, 2008 and 2009, respectively. Compensation of Statutory Auditors amounted to euro 0.678, euro 0.634 million and euro 0.475 million for the years ended December 31, 2007, 2008 and 2009, 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.

Other operating income (loss)
Other operating income (loss) related to the recognition in the profit and loss account the effects related to the valuation of fair value, including the effects deriving from the settlement, of those derivatives on commodities which cannot be recognized according to the hedge accounting under IFRS. Net gain on commodity derivatives in the amount of euro 55 million (euro 129 and euro 124 million for the years ended December 31, 2007 and 2008, respectively) included euro 6 million related to the ineffective portion of the negative change in the fair value of cash flow hedging derivatives (time value component) entered into by the Exploration & Production segment (a loss of euro 52 million and a gain of euro 7 million for the years ended December 31, 2007 and 2008, respectively).

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Depreciation, depletion, amortization and impairments
Depreciation, depletion, amortization and impairments charges consisted of the following:

(euro million)		2007		2008		2009

Depreciation, depletion and amortization:
- tangible assets		4,935			5,994			6,658
- intangible assets		2,096			2,436			2,110
		7,031			8,430			8,768
Impairments:
- tangible assets		145			1,343			990
- intangible assets		62			53			62
		207			1,396			1,052
less:
- reversal of impairments - tangible assets					(2	)		(1	)
- reversal of impairment - intangible assets					(1	)
- capitalized direct costs associated with self-constructed assets - tangible assets		(2	)		(6	)		(4	)
- capitalized direct costs associated with self-constructed assets - intangible assets					(2	)		(2	)
		7,236			9,815			9,813

 

31 Finance income (expense)
Finance income (expense) consisted of the following:

(euro million)		2007		2008		2009

Finance income (expense)
Finance income		4,445			7,985			5,950
Finance expense		(4,554	)		(8,198	)		(6,497	)
		(109	)		(213	)		(547	)
Gain (loss) on derivative financial instruments		155			(427	)		(4	)
		46			(640	)		(551	)

 

 

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Net finance income (expense) consisted of the following:

(euro million)		2007		2008		2009

Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(258	)		(248	)		(423	)
Interest due to banks and other financial institutions		(445	)		(745	)		(330	)
Interest from banks		236			87			33
Interest and other income on financing receivables and securities held for non-operating purposes		55			82			47
		(412	)		(824	)		(673	)
Exchange differences
Positive exchange differences		2,877			7,339			5,572
Negative exchange differences		(2,928	)		(7,133	)		(5,678	)
		(51	)		206			(106	)
Other finance income (expense)
Capitalized finance expense		180			236			223
Income from equity instruments		188			241			163
Interest and other income on financing receivables and securities held for operating purposes		96			62			39
Interest on tax credits		31			37			4
Finance expense due to passage of time (accretion discount) (a)		(186	)		(249	)		(218	)
Other finance income		45			78			21
		354			405			232
		(109	)		(213	)		(547	)

Income from equity instruments in the amount of euro 163 million (euro 188 million and euro 241 million for the years ended December 31, 2007 and 2008, respectively) related to the contractual remuneration of 9.4% on the 20% interest in OAO Gazprom Neft according to the contractual arrangements between Eni and Gazprom. Income has been recognized up to the date of the payment from Gazprom of the strike price on the call option, including the recovery of any additional costs, on April 24, 2009 (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)		2007		2008		2009

Derivatives on exchange rate		120			(300	)		40
Derivatives on interest rate		35			(127	)		(52	)
Derivatives on commodities								8
		155			(427	)		(4	)

Net loss from derivatives in the amount of euro 4 million (euro 155 million of net gain for the year ended December 31, 2007 and euro 427 million of net loss for the year ended December 31, 2008) was primarily due to the recognition in the profit and loss account of the change in the fair value of those derivatives which cannot be recognized according to the hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. The lack of these formal requirements to qualify these derivatives as hedging instruments under IFRS also included the recognition in the profit and loss account the negative impact from currency translation differences on assets and liabilities denominated in currencies other than the functional currency, as this effect cannot be offset by changes in the fair value of the related instruments.

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32 Income (expense) from investments

Share of profit (loss) of equity-accounted investments
Share of profit (loss) of equity-accounted investments consisted of the following:

(euro million)		2007		2008		2009

Share of profit of equity-accounted investments		906			761			693
Share of loss of equity-accounted investments		(135	)		(105	)		(241	)
Decreases (increases) in the provision for losses on investments		2			(16	)		(59	)
		773			640			393

More information is provided in Note 11 – Investments.

Other gain (loss) from investments
Other gain (loss) from investments consisted of the following:

(euro million)		2007		2008		2009

Dividends		170			510			164
Gains on disposals		301			218			16
Losses on disposals		(1	)		(1	)
Other income (expense), net					6			(4	)
		470			733			176

Dividends in the amount of euro 164 million mainly relate to Nigeria LNG (euro 101 million).

Gains on disposals in 2009 amounted to euro 16 million and primarily related to a price revision for the sale of Gaztransport et Technigaz SAS (euro 10 million), which occurred in 2008. Gains on disposals in 2008 amounted to euro 218 million and 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 in 2007 amounted to euro 301 million and primarily related to the sale of Haldor Topsøe AS (euro 265 million) and Camom SA (euro 25 million).


33 Income tax expense
Income tax expense consisted of the following:

(euro million)		2007		2008		2009

Current taxes:
- Italian subsidiaries		2,380			1,916			1,724
- foreign subsidiaries of the Exploration & Production segment		6,695			9,744			5,989
- foreign subsidiaries		482			426			483
		9,557			12,086			8,196
Net deferred taxes:
- Italian subsidiaries		(582	)		(1,603	)		(534	)
- foreign subsidiaries of the Exploration & Production segment		246			(827	)		(733	)
- foreign subsidiaries		(2	)		36			(173	)
		(338	)		(2,394	)		(1,440	)
		9,219			9,692			6,756

Current income taxes in the amount of euro 1,724 million consist of IRES (euro 1,485 million) and IRAP (euro 219 million) for Italian subsidiaries and foreign taxes (euro 20 million).

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The effective tax rate was 56.0% (46.0% and 50.3% for the years ended December 31, 2007 and 2008, respectively) compared with a statutory tax rate of 40.1% (37.9% and 38.2% for the years ended December 31, 2007 and 2008, respectively) and calculated by applying a 34.0%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:

(%)		2007		2008		2009

Statutory tax rate		37.9			38.2			40.1
Items increasing (decreasing) statutory tax rate:
- higher foreign subsidiaries tax rate		10.2			15.2			13.3
- 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	)		2.4
- permanent differences and other adjustments		(0,1	)		0.7			0.2
		8.1			12.1			15.9
		46.0			50.3			56.0

The increase in the tax rate of foreign subsidiaries primarily related to a 16.1 percentage points increase in the Exploration & Production segment (15.0% and 17.1% for the years ended December 31, 2007 and 2008, 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 consisted of the following: in the 2009 (i) the equalization in Libya of the 2008 income taxes in the amount of euro 230 million following adjustments to the valorization criteria of revenues; (ii) a reduced deductibility in Italy of cost of goods sold following the reduction in the gas volumes of inventories in the amount of euro 64 million; in the 2008 (iii) the utilization of deferred tax liabilities recognized on higher carrying amounts of year-end inventories of oil, gas and refined products stated at 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 were 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, the profit and loss account 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 the 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; (iv) 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 applying a special rate of 6% (positive impact on the profit and loss account in the amount of euro 370 million; euro 290 million net of the special tax); (v) 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 in the amount of euro 173 million; (vi) 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. 112/2008 instead of the previously applicable statutory tax rate (IRES) of 27.5% (euro 94 million).

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 and the subsequent modification introduced by the Law Decree No. 112/2008. 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).

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In 2009, permanent differences and other adjustments for 0.2 percentage points included: (i) as an increase, a non-recurring item represented by a charge amounting to euro 250 million that was estimated on the base of the management’s best knowledge of the possible resolution of the TSKJ matter with U.S. Authorities. More information is provided in Note 28 – Guarantees, commitments and risks; and (ii) as a decrease, deferred tax assets accounted for following an adjustment of the fiscal value to the carrying amount of oil & gas properties related to a reorganization of the Italian activities by paying a special tax and the partial deductibility of IRAP of income taxes from previous years (euro 222 million).


34 Earnings per share
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 as of December 31, 2007, 2008 and 2009, was 3,668,305,807, 3,638,835,896 and 3,622,405,852, 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 fully-diluted shares which includes issued and outstanding shares during the year, excluding treasury shares and including the number of shares that could potentially be issued in connection with stock-based compensation plans. As of December 31, 2008 and 2009, the number of shares that could potentially be issued were related to stock options plans. As of December 31, 2007, the number of shares that could potentially be issued were related to stock options and stock grant plans.

The average number of shares fully diluted used in the calculation of diluted earnings was 3,669,172,762, 3,638,854,276 and 3,622,438,937 for the years ended December 31, 2007, 2008 and 2009, respectively.

Reconciliation of the average number of shares used for the calculation for both basic and diluted earnings per share was as follows:

		2007		2008		2009

Average number of shares used for the calculation of the basic earnings per share				3,668,305,807		3,638,835,896		3,622,405,852
Number of potential shares following stock grant plans				302,092
Number of potential shares following stock options plans				564,863		18,380		33,085
Average number of shares used for the calculation of the diluted earnings per share				3,669,172,762		3,638,854,276		3,622,438,937
Eni’s net profit		(euro million)		10,011		8,825		4,367
Basic earning per share		(euro per share)		2.73		2.43		1.21
Diluted earning per share		(euro per share)		2.73		2.43		1.21

 

 

 

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35 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

2007
Net sales from operations (a)		26,920			27,793			36,349			6,934			8,678			205			1,313
Less: intersegment sales		(16,280	)		(757	)		(1,276	)		(363	)		(1,182	)		(31	)		(1,099	)
Net sales to customers		10,640			27,036			35,073			6,571			7,496			174			214						87,204
Operating profit		13,433			4,465			686			100			837			(444	)		(312	)		(26	)		18,739
Provisions for contingencies		7			35			238			15			11			264			3						573
Depreciation, amortization and writedowns		5,574			739			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)		32,382			25,583			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)		10,955			5,915			5,420			939			4,349			1,827			1,380						30,785
Unallocated liabilities																										27,808
Capital expenditures		6,480			1,511			979			145			1,410			59			108			(99	)		10,593
2008
Net sales from operations (a)		33,042			37,062			45,017			6,303			9,176			185			1,331			75
Less: intersegment sales		(18,917	)		(873	)		(1,496	)		(398	)		(1,219	)		(29	)		(1,177	)
Net sales to customers		14,125			36,189			43,521			5,905			7,957			156			154			75			108,082
Operating profit		16,239			4,030			(988	)		(845	)		1,045			(346	)		(743	)		125			18,517
Provisions for contingencies		154			238			190			2			36			99			165						884
Depreciation, amortization and writedowns		7,488			798			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)		40,815			33,151			11,081			2,629			10,630			362			789			(641	)		98,816
Unallocated assets																										17,857
Equity-accounted investments		1,787			2,249			1,227			25			130			53									5,471
Identifiable liabilities (c)		10,481			11,802			4,481			664			6,177			1,638			1,780			(75	)		36,948
Unallocated liabilities																										31,215
Capital expenditures		9,281			2,058			965			212			2,027			52			95			(128	)		14,562
2009
Net sales from operations (a)		23,801			30,447			31,769			4,203			9,664			88			1,280			(66	)
Less: intersegment sales		(13,630	)		(635	)		(965	)		(238	)		(1,315	)		(24	)		(1,152	)
Net sales to customers		10,171			29,812			30,804			3,965			8,349			64			128			(66	)		83,227
Operating profit		9,120			3,687			(102	)		(675	)		881			(382	)		(474	)					12,055
Provisions for contingencies		(2	)		277			154			1			311			139			175						1,055
Depreciation, amortization and writedowns		7,365			981			754			204			435			8			83			(17	)		9,813
Share of profit (loss) of equity-accounted investments		142			310			(70	)					50			(39	)								393
Identifiable assets (b)		42,729			32,135			12,244			2,583			11,611			355			1,031			(553	)		102,135
Unallocated assets																										15,394
Equity-accounted investments		1,989			2,044			1,494			37			213			51									5,828
Identifiable liabilities (c)		10,918			9,161			4,684			742			5,967			1,639			1,690			(8	)		34,793
Unallocated liabilities																										32,685
Capital expenditures		9,486			1,686			635			145			1,630			44			57			12			13,695

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Intersegment revenues are conducted at an arm’s length basis.

Geographic financial information

Identifiable assets and investments by geographic area of origin

(euro million)

Italy

Other European Union

Rest of Europe

America

Asia

Africa

Other areas

Total

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		15,071		3,561		6,224		10,563		22,044		921		98,816
Capital expenditures		3,674		1,660		582		1,240		1,777		5,153		476		14,562
2009
Identifiable assets (a)		40,861		15,571		3,520		6,337		11,187		23,397		1,262		102,135
Capital expenditures		3,198		1,454		574		1,207		2,033		4,645		584		13,695

Sales from operations by geographic area of destination

(euro million)		2007		2008		2009

Italy		37,294			42,843			27,950
Other European Union		23,074			29,341			24,331
Rest of Europe		5,507			7,125			5,213
America		6,447			7,218			7,080
Asia		5,840			8,916			8,208
Africa		8,010			12,331			10,174
Other areas		1,032			308			271
		87,204			108,082			83,227

36 Transactions with related parties
In the ordinary course of business Eni enters into transactions relating to:

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 Cosmi Holding Group, which is related to Eni through a member of the Board of Directors, for certain acquisition of engineering, construction and maintenance services. Relevant transactions which were executed at an arm’s length basis amounted to approximately euro 18 million, euro 13 million and euro 21 million in 2007, 2008 and 2009, respectively. As of December 31, 2009, there were outstanding receivables in the amount of euro 4 million and payables in the amount euro 9 million (euro 4 million and euro 8 million as of December 31, 2008, respectively);
d)		contributions to entities, controlled by Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment as well as research and development. Transactions with Eni Foundation related to contributions for the year ended December 31, 2008 in the amount of euro 200 million to the solidarity fund pursuant to Italian Law Decree No. 112/2008 and the payable as of December 31, 2008 and 2009 in the amount of euro 100 million related to the portion of the contribution that had not yet been paid. Transactions in the periods preceding 2008 were not material; (ii) Enrico Mattei Foundation established by

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Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Transactions with Enrico Mattei Foundation were not material.

Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities with the aim to develop solidarity, culture and research initiatives, at 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 years ended December 31, 2007, 2008 and 2009, respectively, consisted of the following:

(euro million)		Dec. 31, 2007		2007

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Goods

Services

Other operating (charge) income

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 Gilg & 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		122		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		10
Terna SpA		19		69				106		105				31
Other (*)		45		79				19		89		75		3
		576		219				364		476		2,202		450		10
		1,335		1,082		6,321		799		2,978		3,218		980		10

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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

Other operating (charge) income

Joint ventures and associates
Agiba Petroleum Co				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 Petròleo Lda								94				10
Gasversorgung Süddeutschland GmbH		64												337		18
Gruppo Distribuzione Petroli Srl		20												111
InAgip doo		24		45						116				3		35
Karachaganak Petroleum 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
		665		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
Gruppo Alitalia		4												417		2
Gruppo Enel		153		12				13		223				941		380
Gruppo Ferrovie dello Stato		19		7						27		1		57
GSE - Gestore Servizi Elettrici		92		63				315				79		347		16		6		58
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		58
		1,160		1,202		6,403		1,850		3,989		246		3,508		1,540		39		58

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(euro million)		Dec. 31, 2009		2009

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Other operating (charge) income

Joint ventures and associates
Agiba Petroleum Co				5						64
Altergaz SA		50												142
ASG Scarl				10		54				25
Azienda Energia e Servizi Torino SpA		1		30						62						1
Bayernoil Raffineriegesellschaft mbH				31		1		15		77				2
Blue Stream Pipeline Co BV		17		15		34				163
Bronberger & Kessler und Gilg & Schweiger GmbH		16												95
CEPAV (Consorzio Eni per l'Alta Velocità) Uno		38		12		6,037				5						84
CEPAV (Consorzio Eni per l'Alta Velocità) Due		6		1		76				1						2
Fox Energy SpA		44						1						241
Gasversorgung Süddeutschland GmbH		17												196		8
Gruppo Distribuzione Petroli Srl		15												71
InAgip doo		44		23						86						71
Karachaganak Petroleum Operating BV		61		196				588		344		27		9		10
Kwanda Suporto Logistico Lda		72														20
Mellitah Oil & Gas BV		30		190						306				2		31
Petrobel Belayim Petroleum Co		4		12						205						4		2
Raffineria di Milazzo ScpA		14		8						242				98		5
Saipon Snc		8		2		61										45
Super Octanos CA				24				133
Trans Austria Gasleitung GmbH		4		71				36		157						40
Transitgas AG										1		61
Unión Fenosa Gas SA		8				62		12						53				1
Other (*)		143		58		15		62		188		41		117		125		10
		592		688		6,340		847		1,926		129		1,026		446		13
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		194		224				1		914		7		15		466		7
Eni BTC Ltd						141										1
Other (*)		29		23		4		1		52		4		14		6		1
		223		247		145		2		966		11		29		473		8
		815		935		6,485		849		2,892		140		1,055		919		21
Entities owned or controlled by the Government
Gruppo Enel		96		32				9		286		77		342		428		1
Gruppo Finmeccanica		33		37				16		56				21		7
GSE - Gestore Servizi Elettrici		83		74				373				79		342		15				19
Terna SpA		7		37				52		52		19		7		86		4		25
Other (*)		78		71				1		71		6		62		16
		297		251				451		465		181		774		552		5		44
		1,112		1,186		6,485		1,300		3,357		321		1,829		1,471		26		44

The most significant transactions with joint ventures, associates and non-consolidated subsidiaries consisted of the following:

• 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;
• transportation and distribution activity with Azienda Energia e Servizi Torino SpA;
• acquisition of refining services from Bayernoil Raffineriegesellschaft mbH and Raffineria di Milazzo ScpA in relation to incurred costs;
• supply of oil products to Bronberger & Kessler und Gilg & Schweiger GmbH, Fox Energy SpA, Gruppo Distribuzione Petroli Srl and Raffineria di Milazzo ScpA on the basis of prices related to the quotations on international markets of the main oil products, as they would be conducted at an arm’s length basis;
• acquisition of natural gas transport services outside Italy from Blue Stream Pipeline Co BV, Trans Austria Gasleitung GmbH and Transitgas AG and the issuing of guarantees on behalf of Blue Stream Pipeline Co BV;

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• guarantees issued on behalf of CEPAV (Consorzio Eni per l’Alta Velocità) Due and Saipon Snc 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, 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 costs incurred;
• logistic support by Kwanda Suporto Logistico Lda;
• sale of natural gas to Altergaz SA and Gasversorgung Süddeutschland GmbH;
• acquisition of petrochemical products from Super Octanos CA on the basis of prices related 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.

The most significant transactions with entities owned or controlled by the Government consisted of the following:

• 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;
• a long term contract for the maintenance of the newly combined cycle power plants with Gruppo Finmeccanica;
• sale and purchase of electricity, green certificates and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with GSE - Gestore Servizi Elettrici;
• sale and purchase of electricity, the acquisition of domestic electricity transmission service and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with 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 for the years ended December 31, 2007, 2008 and 2009, respectively, consisted of the following:

(euro million)		Dec. 31, 2007		2007

Name		Receivables		Payables		Guarantees		Charges		Gains

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
		384		147		824		20		49

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(euro million)		Dec. 31, 2008		2008

Name		Receivables		Payables		Guarantees		Charges		Gains

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
		811		162		850		17		42

 

(euro million)		Dec. 31, 2009		2009

Name		Receivables		Payables		Guarantees		Charges		Gains

Joint ventures and associates
Artic Russia BV		70		1		170				1
Bayernoil Raffineriegesellschaft mbH		133
Blue Stream Pipeline Co BV						692				12
Raffineria di Milazzo ScpA						85
Trans Austria Gasleitung GmbH		171								5
Transmediterranean Pipeline Co Ltd		149								3
Other (*)		125		112		24		2		3
		648		113		971		2		24
Unconsolidated entities controlled by Eni
Other (*)		78		34		1		2		3
		78		34		1		2		3
		726		147		972		4		27

The most significant transactions with joint ventures, associates and non-consolidated subsidiaries consisted of the following:

• bank debt guarantee issued on behalf of Artic Russia BV, Blue Stream Pipeline Co BV and Raffineria di Milazzo ScpA, and, exclusively with Artic Russia BV, financing loans and cash deposit at Eni’s financial companies;
• financing loan to Bayernoil Raffineriegesellschaft mbH;
• 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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Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows
The impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows consisted of the following:

		Dec. 31, 2007		Dec. 31, 2008		Dec. 31, 2009

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Trade and other receivables		20,676			1,616			7.82		22,222			1,539			6.93		20,348			1,355			6.66
Other current assets		790								1,870			59			3.16		1,307			9			0.69
Other non-current financial assets		923			87			9.43		1,134			356			31.39		1,148			438			38.15
Other non-current assets		1,400			16			1.14		1,881			21			1.12		1,938			40			2.06
Current financial liabilities		7,763			131			1.69		6,359			153			2.41		3,545			147			4.15
Trade and other payables		17,116			1,021			5.97		20,515			1,253			6.11		19,174			1,241			6.47
Other liabilities		1,523			4			0.26		3,863			4			0.10		1,856			5			0.27
Long-term debt and current portion of long-term debt		12,067			16			0.13		14,478			9			0.06		21,255
Other non-current liabilities		2,117			57			2.69		3,102			53			1.71		2,480			49			1.98

The impact of transactions with related parties on the profit and loss account consisted of the following:

		2007		2008		2009

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Net sales from operations		87,204			4,198			4.81		108,082			5,048			4.67		83,227			3,300			3.97
Other income and revenues		833						..		728			39			5.36		1,118			26			2.33
Purchases, services and other		58,133			3,777			6.50		76,350			6,298			8.25		58,351			4,999			8.57
Other operating income (expense)		(129	)		10			..		(124	)		58			..		55			44			80.00
Financial income		4,445			49			1.10		7,985			42			0.53		5,950			27			0.45
Financial expense		(4,554	)		(20	)		0.44		(8,198	)		(17	)		0.21		(6,497	)		(4	)		0.06

Transactions with related parties during the ordinary course of Eni’s business were mainly conducted at an arm’s length basis.

Main cash flows with related parties were as follows:

(euro million)		2007		2008		2009

Revenues and other income		4,198			5,087			3,326
Costs and other expenses		(3,777	)		(6,298	)		(4,999	)
Other operating income (loss)		10			58			44
Net change in trade and other receivables and liabilities		(492	)		351			34
Dividends and net interests		610			740			407
Net cash provided from operating activities		549			(62	)		(1,188	)
Capital expenditures in tangible and intangible assets		(779	)		(2,022	)		(1,364	)
Investments		8
Change in accounts payable in relation to investments		(8	)		27			19
Change in financial receivables		(43	)		397			83
Net cash used in investing activities		(822	)		(1,598	)		(1,262	)
Change in financial liabilities		20			14			(14	)
Net cash used in financing activities		20			14			(14	)
Total financial flows to related parties		(253	)		(1,646	)		(2,464	)

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The impact on the statement of cash flows with related parties consisted of the following:

		2007		2008		2009

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Cash provided from operating activities		15,517			549			3.54		21,801			(62	)		..		11,136			(1,188	)		..
Cash used in investing activities		(20,097	)		(822	)		4.09		(16,958	)		(1,598	)		9.42		(10,254	)		(1,262	)		12.31
Cash used in financing activities		2,909			20			0.69		(5,025	)		14			..		(1,183	)		(14	)		1.18

37 Significant non-recurring events and operations
Non-recurring income (charges) consisted of the following:

(euro million)		2007		2008		2009

Estimate of the charge from the possible resolution of the TSKJ matter								250
Curtailment of post-retirement benefits for Italian employees		83
Risk provisions for proceedings against Antitrust authorities		(130	)		21
Risk provisions for proceedings against the Italian Authority for Electricity and Gas		39
		(8	)		21			250

The estimate of the charge related to the TSKJ matter represents a charge in the amount of euro 250 million that was estimated based on management’s best estimate of the cost of the resolution of the TSKJ matter with U.S. Authorities. The matter is fully disclosed in Note 28 – Guarantees, commitments and risks – Legal Proceedings. The charge is recognized in the results of the Engineering & Construction segment as it relates to a project that was executed in Nigeria by the TSKJ joint venture. However, the charge will be incurred by Eni due to the contractual obligations assumed by Eni related to the indemnification of Saipem as part of the divestment of Snamprogetti. At the time of the project, the TSKJ venture was participated by Snamprogetti Netherlands BV which was controlled by Snamprogetti. As a result, the future monetary settlement of the provision will be incurred by Eni SpA and Saipem’s minorities will be left unaffected.

Non-recurring income consists of a gain resulting 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 consist of risk provisions related to ongoing antitrust proceedings against the European Antitrust authorities (euro 130 million).


38 Positions or transactions deriving from atypical and/or unusual operations
There were no positions or transactions deriving from atypical and/or unusual operations for the years ended December 31, 2007, 2008 and 2009.

Recent developments
On February 4, 2010, Eni formally presented to the European Commission a set of structural remedies relating certain international gas pipelines. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test, Eni will be in the position to resolve an inquiry started in May 2006 for alleged infringements of the European antitrust regulations in the gas sector, which involved the main players in European gas market. Eni

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received a statement of objections from the European Commission which alleged that during the 2000-2005 period Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas, thus restricting gas availability in Italy. Given the strategic importance of the Austrian TAG pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake to an entity controlled by the Italian State. In case they are implemented, the remedies negotiated with the Commission will not affect Eni’s contractual gas transport rights. Management expects that a possible divestiture will occur as early as at the beginning of 2011 and as such the profit and loss for the year 2010 will report the full-year results of Eni’s share of profit in those entities. For further details on the matter see "Item 8 – Legal Proceedings".

Management intends to divest a stake in its fully-consolidated subsidiary GreenStream where the Company currently owns a 75% stake. Following the intended divestment, the Company expects to account for the entity in accordance with the equity-method of accounting. At December 31, 2009, included as part of total assets and total liabilities in the Consolidated Financial Statements in respect to the Company’s investment in GreenStream are euro 673 million and euro 525 million, respectively.

The Company’s Annual General Shareholders Meeting scheduled on April 29, 2010, is due to approve the full year dividend proposal. Eni expects to pay the balance of the dividend for fiscal year 2009 amounting to euro 0.50 per share in May. Total cash out is estimated at euro 1.81 billion.

 

Supplemental oil and gas information (unaudited)
The following information pursuant to "International Financial Reporting Standards" (IFRS) is presented in accordance with SFAB Extractive Activities - Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs
Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

December 31, 2008
Proved mineral interests		10,772			7,852			10,116			11,368			1,663			3,939			4,737			392			50,839			813
Unproved mineral interests		32			316			638			2,267			37			1,461			2,418			43			7,212			928
Support equipment and facilities		283			24			1,205			520			51			16			43			4			2,146			14
Incomplete wells and other		1,374			249			1,006			1,443			2,631			713			632			362			8,410			267
Gross Capitalized Costs		12,461			8,441			12,965			15,598			4,382			6,129			7,830			801			68,607			2,022
Accumulated depreciation, depletion and amortization		(7,943	)		(5,327	)		(6,318	)		(7,027	)		(560	)		(3,224	)		(3,638	)		(173	)		(34,210	)		(441	)
Net Capitalized Costs (a) (b)		4,518			3,114			6,647			8,571			3,822			2,905			4,192			628			34,397			1,581
December 31, 2009
Proved mineral interests		10,079			9,472			11,122			14,011			1,723			4,566			5,750			1,338			58,061			791
Unproved mineral interests		33			305			580			1,854			36			1,518			2,144			38			6,508			443
Support equipment and facilities		273			31			1,287			585			57			17			45			4			2,299			13
Incomplete wells and other		1,028			329			1,228			934			3,481			316			600			14			7,930			358
Gross Capitalized Costs		11,413			10,137			14,217			17,384			5,297			6,417			8,539			1,394			74,798			1,605
Accumulated depreciation, depletion and amortization		(7,557	)		(6,824	)		(7,044	)		(8,424	)		(620	)		(3,679	)		(4,673	)		(379	)		(39,200	)		(485	)
Net Capitalized Costs (a) (b) (c)		3,856			3,313			7,173			8,960			4,677			2,738			3,866			1,015			35,598			1,120

(1)		Eni's capitalized costs of the Kashagan field are determined based on Eni share of 16.81%.
(2)		The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)		The amounts include net capitalized financial charges totaling euro 537 million in 2008 and euro 570 million in 2009.
(b)		The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The "Successful Effort Method" application would have led to an increase in net capitalized costs of in euro 3,308 million in 2008 and euro 3,690 million in 2009 for the consolidated companies and of euro 48 million in 2008 and euro 76 million in 2009 for joint ventures affiliates.
(c)		Amounts of 2009 do not include the capitalized costs related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

 

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Cost incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

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		195		373		305		36		162		980		37		2,192		42
Development (a) (b)		320		557		1,047		1,425		744		247		734		165		5,239		156
Total costs incurred		424		752		1,431		2,691		780		409		4,526		202		11,215		1,471
2008
Proved property acquisitions (b)						626		413				256						1,295
Unproved property acquisitions (b)				33		384		655				647						1,719
Exploration (b)		135		227		403		600		16		345		440		48		2,214		48
Development (a) (b)		644		957		1,388		1,884		1,023		598		748		325		7,567		163
Total costs incurred		779		1,217		2,801		3,552		1,039		1,846		1,188		373		12,795		211
2009
Proved property acquisitions						298		27				11		131				467
Unproved property acquisitions						54		42				83		43				222
Exploration		40		114		317		284		20		159		242		52		1,228		41
Development (a)		742		727		1,401		2,121		1,086		423		858		462		7,820		206
Total costs incurred		782		841		2,070		2,474		1,106		676		1,274		514		9,737		247

(1)		Eni's incurred costs of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)		The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)		Includes the abandonment costs of the assets for euro 173 million in 2007, euro 628 million in 2008 and euro 301 million in 2009.
(b)		Of which business combination:

 

Results of operations from oil and gas producing activities
Results of operations from oil and gas producing activities, represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state-owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA-related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.

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Results of operations from oil and gas producing activities by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

Total consolidated subsidiaries, joint ventures and affiliates

Revenues
Sales to consolidated entities		3,171			3,273			3,000			4,439			296			44			229			91			14,543						14,543
Sales to third parties		163			755			4,793			693			833			961			1,112			187			9,497			176			9,673
Total revenues		3,334			4,028			7,793			5,132			1,129			1,005			1,341			278			24,040			176			24,216
Operations costs		(248	)		(584	)		(542	)		(499	)		(142	)		(39	)		(177	)		(50	)		(2,281	)		(27	)		(2,308	)
Production taxes		(188	)					(91	)		(473	)					(28	)								(780	)		(6	)		(786	)
Exploration expenses		(108	)		(196	)		(379	)		(297	)		(36	)		(168	)		(566	)		(27	)		(1,777	)		(42	)		(1,819	)
D.D. & A. and Provision for abandonment (a)		(499	)		(766	)		(768	)		(685	)		(76	)		(422	)		(511	)		(19	)		(3,746	)		(51	)		(3,797	)
Other income and (expenses)		(283	)		(83	)		(627	)		(285	)		(72	)		(134	)		(18	)		(65	)		(1,567	)		(18	)		(1,585	)
Pretax income from producing activities		2,008			2,399			5,386			2,893			803			214			69			117			13,889			32			13,921
Income taxes		(746	)		(1,447	)		(3,102	)		(1,820	)		(284	)		(93	)		(110	)		(10	)		(7,612	)		(49	)		(7,661	)
Results of operations from E&P activities (b)		1,262			952			2,284			1,073			519			121			(41	)		107			6,277			(17	)		6,260
2008
Revenues
Sales to consolidated entities		3,956			3,892			2,622			5,013			360			39			323			66			16,271						16,271
Sales to third parties		126			160			7,286			1,471			1,025			1,335			1,599			218			13,220			265			13,485
Total revenues		4,082			4,052			9,908			6,484			1,385			1,374			1,922			284			29,491			265			29,756
Operations costs		(260	)		(521	)		(528	)		(609	)		(157	)		(68	)		(233	)		(35	)		(2,411	)		(34	)		(2,445	)
Production taxes		(195	)					(32	)		(616	)					(35	)								(878	)		(53	)		(931	)
Exploration expenses		(135	)		(228	)		(406	)		(548	)		(16	)		(232	)		(435	)		(58	)		(2,058	)		(48	)		(2,106	)
D.D. & A. and Provision for abandonment (a)		(551	)		(829	)		(1,120	)		(1,115	)		(79	)		(823	)		(837	)		(35	)		(5,389	)		(84	)		(5,473	)
Other income and (expenses)		(420	)		(56	)		(934	)		(268	)		(270	)		(259	)		(6	)		(41	)		(2,254	)		(15	)		(2,269	)
Pretax income from producing activities		2,521			2,418			6,888			3,328			863			(43	)		411			115			16,501			31			16,532
Income taxes		(924	)		(1,623	)		(4,170	)		(2,262	)		(302	)		(122	)		(214	)		(70	)		(9,687	)		(49	)		(9,736	)
Total results of operations from E&P activities (b)		1,597			795			2,718			1,066			561			(165	)		197			45			6,814			(18	)		6,796
2009
Revenues
Sales to consolidated entities		2,274			2,583			1,738			4,386			245			41			808			29			12,104						12,104
Sales to third parties					540			5,037			586			739			1,208			639			181			8,930			232			9,162
Total revenues		2,274			3,123			6,775			4,972			984			1,249			1,447			210			21,034			232			21,266
Operations costs		(271	)		(517	)		(553	)		(749	)		(153	)		(78	)		(273	)		(41	)		(2,635	)		(34	)		(2,669	)
Production taxes		(148	)					(20	)		(445	)					(34	)								(647	)		(44	)		(691	)
Exploration expenses		(40	)		(114	)		(319	)		(451	)		(20	)		(204	)		(341	)		(62	)		(1,551	)		(41	)		(1,592	)
D.D. & A. and Provision for abandonment (a)		(463	)		(921	)		(956	)		(1,502	)		(78	)		(535	)		(1,108	)		(186	)		(5,749	)		(76	)		(5,825	)
Other income and (expenses)		(125	)		(134	)		(471	)		(467	)		(186	)		(17	)		170			(47	)		(1,277	)		(41	)		(1,318	)
Pretax income from producing activities		1,227			1,437			4,456			1,358			547			381			(105	)		(126	)		9,175			(4	)		9,171
Income taxes		(467	)		(833	)		(3,010	)		(1,042	)		(180	)		(67	)		(2	)		23			(5,578	)		(40	)		(5,618	)
Results of operations from E&P activities (b) (c)		760			604			1,446			316			367			314			(107	)		(103	)		3,597			(44	)		3,553

(1)		Eni's results of operations of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)		The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)		Includes asset impairments amounting to euro 91 million in 2007, euro 770 million in 2008 and euro 576 million in 2009.
(b)		The "Successful Effort Method" application would have led to an increase of result of operations of euro 438 million in 2007, euro 408 million in 2008 and euro 320 million in 2009 for the consolidated companies and of euro 26 million in 2007 and any variation in 2008 and euro 26 million in 2009 for joint ventures and affiliates.
(c)		Amounts of 2009 do not include results of operation related to the Italian gas storage activities, following the restructuring of Eni's regulated gas businesses in Italy now reported in the Gas & Power segment.

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Average sale prices and production costs per unit of production

($)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total

2007
Oil and condensate, per BBL		62.47		70.84		67.86		69.77		59.34		64.73		66.37		71.23		67.70
Natural gas, per KCF		8.58		6.71		4.60		1.21		0.41		4.34		6.69		5.94		5.42
Average production cost, per BOE		7.89		8.35		4.22		11.53		4.90		3.13		7.17		10.35		6.90
2008
Oil and condensate, per BBL		84.87		71.90		84.71		91.58		79.06		75.08		88.69		82.80		84.05
Natural gas, per KCF		13.06		10.55		7.14		1.50		0.53		5.50		8.81		9.59		8.01
Average production cost, per BOE		9.40		8.67		3.66		15.25		5.86		3.69		10.27		8.50		7.77
2009
Oil and condensate, per BBL		56.02		56.46		55.97		59.75		52.34		55.23		55.74		50.40		56.95
Natural gas, per KCF		9.01		7.06		5.78		1.66		0.45		4.30		4.05		8.14		5.62
Average production cost, per BOE		9.69		8.28		4.05		13.15		5.20		3.49		8.25		9.56		7.49

Oil and natural gas reserves
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price¹⁶ shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Net proved reserves exclude interests and royalties owned by others.

Proved reserves are classified as either developed or undeveloped.

Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Since 1991 Eni has requested qualified independent oil engineering companies to carry out an independent evaluation¹⁷ of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report¹⁸.

In the preparation of their reports, independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies; technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs.

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In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.

In 2009 Ryder Scott Company and DeGolyer and MacNaughton¹⁹ provided an independent evaluation of almost 28% of Eni's total proved reserves as of December 31, 2009²⁰ confirming, as in previous years, the reasonableness of Eni's internal evaluations.

In the three year period from 2007 to 2009, 86% of Eni's total proved reserves were subject to independent evaluation.

As of December 31, 2009 among the most important Eni properties, the only one which was not subject to an independent review was Barbara (Italy).

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 46%, 54% and 57% of total proved reserves as of December 31, 2007, 2008 and 2009, respectively, on an oil-equivalent basis.

Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 1%, 2% and 2% of total proved reserves on an oil-equivalent basis as of December 31, 2007, 2008 and 2009, respectively.

Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 1.8%, 0.1% and 0.3% of total proved reserves as of December 31, 2007, 2008 and 2009, respectively, on an oil-equivalent basis; (ii) volumes of natural gas used for own consumption, (iii) the quantities of natural gas produced to feed the Angola LNG plant; and (iv) volumes of natural gas held in certain Eni 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 from 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, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.

 

 

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The following tables present yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2007, 2008 and 2009.

Crude oil (including condensate and natural gas liquids)

(mmBBL)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

Total consolidated subsidiaries, joint ventures and affiliates

Reserves at December 31, 2006		215			386			982			786			893			62			98			35			3,457			24			3,481
of which: developed		136			329			713			546			262			53			54			33			2,126			18			2,144
undeveloped		79			57			269			240			631			9			44			2			1,331			6			1,337
Purchase of Minerals in Place											32									54						86			101			187
Revisions of Previous Estimates		28			14			(35	)		(26	)		(114	)		(6	)		(23	)		(2	)		(164	)		20			(144	)
Improved Recovery					1			9			12															22			1			23
Extensions and Discoveries					1			43			22									28			1			95			1			96
Production		(28	)		(57	)		(121	)		(101	)		(26	)		(12	)		(19	)		(5	)		(369	)		(5	)		(374	)
Reserves at December 31, 2007		215			345			878			725			753			44			138			29			3,127			142			3,269
of which: developed		133			299			649			511			219			35			81			26			1,953			26			1,979
undeveloped		82			46			229			214			534			9			57			3			1,174			116			1,290
Purchase of Minerals in Place											32						36									68						68
Revisions of Previous Estimates		(8	)		(30	)		56			80			239			42			11			1			391			4			395
Improved Recovery								7			25															32			1			33
Extensions and Discoveries		4			13			4			26						2			3						52						52
Production		(25	)		(51	)		(122	)		(105	)		(25	)		(18	)		(21	)		(4	)		(371	)		(5	)		(376	)
Sales of Minerals in Place														(56	)											(56	)					(56
Reserves at December 31, 2008		186			277			823			783			911			106			131			26			3,243			142			3,385
of which: developed		111			222			613			576			298			92			74			23			2,009			33			2,042
undeveloped		75			55			210			207			613			14			57			3			1,234			109			1,343
Purchase of Minerals in Place											2															2						2
Revisions of Previous Estimates		57			40			129			78			(36	)		(35	)		36			1			270						270
Improved Recovery					8			10			15															33						33
Extensions and Discoveries		10			74			38			5						44			12			8			191			1			192
Production		(20	)		(48	)		(105	)		(113	)		(26	)		(21	)		(26	)		(3	)		(362	)		(6	)		(368	)
Sales of Minerals in Place																													(51	)		(51	)
Reserves at December 31, 2009		233			351			895			770			849			94			153			32			3,377			86			3,463
of which: developed		141			218			659			544			291			45			80			23			2,001			34			2,035
undeveloped		92			133			236			226			558			49			73			9			1,376			52			1,428

(1)		Eni's proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)		The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).

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Natural gas

(BCF)

Italy (a)

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

Total consolidated subsidiaries, joint ventures and affiliates

Reserves at December 31, 2006		3,391			1,836			5,946			1,927			1,874			991			299			633			16,897			68			16,965
of which: developed		2,449			1,480			3,042			1,447			1,511			614			159			247			10,949			48			10,997
undeveloped		942			356			2,904			480			363			377			140			386			5,948			20			5,968
Purchase of Minerals in Place											5									395						400			2,963			3,363
Revisions of Previous Estimates		(53	)		66			250			74			(222	)		23			4			(20	)		122			5			127
Improved Recovery					3																					3						3
Extensions and Discoveries		4			6			89			213			205			4			86						607						607
Production		(285	)		(236	)		(534	)		(97	)		(87	)		(138	)		(88	)		(15	)		(1,480	)		(14	)		(1,494	)
Reserves at December 31, 2007		3,057			1,675			5,751			2,122			1,770			880			696			598			16,549			3,022			19,571
of which: developed		2,304			1,364			3,065			1,469			1,580			530			442			213			10,967			428			11,395
undeveloped		753			311			2,686			653			190			350			254			385			5,582			2,594			8,176
Purchase of Minerals in Place					8						6						114									128						128
Revisions of Previous Estimates		56			(58	)		1,163			45			772			52			(13	)		24			2,041			6			2,047
Improved Recovery											4															4						4
Extensions and Discoveries		5			25			38			2						11			31						112						112
Production		(274	)		(229	)		(641	)		(95	)		(89	)		(146	)		(114	)		(16	)		(1,604	)		(13	)		(1,617	)
Sales of Minerals in Place														(16	)											(16	)					(16	)
Reserves at December 31, 2008		2,844			1,421			6,311			2,084			2,437			911			600			606			17,214			3,015			20,229
of which: developed		2,031			1,122			3,537			1,443			2,005			439			340			221			11,138			420			11,558
undeveloped		813			299			2,774			641			432			472			260			385			6,076			2,595			8,671
Purchase of Minerals in Place											1									136						137						137
Revisions of Previous Estimates		97			149			(309	)		142			(204	)		52			43			(17	)		(47	)		18			(29	)
Improved Recovery					25																					25						25
Extensions and Discoveries		1			26			479									2			7			4			519			80			599
Production		(238	)		(239	)		(587	)		(100	)		(94	)		(151	)		(155	)		(18	)		(1,582	)		(14	)		(1,596	)
Sales of Minerals in Place					(2	)														(2	)					(4	)		(1,511	)		(1,515	)
Reserves at December 31, 2009		2,704			1,380			5,894			2,127			2,139			814			629			575			16,262			1,588			17,850
of which: developed		2,001			1,231			3,486			1,463			1,859			539			506			565			11,650			234			11,884
undeveloped		703			149			2,408			664			280			275			123			10			4,612			1,354			5,966

(1)		Eni's proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)		The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)		Including approximately, 754, 749, 746 and 769 BCF of natural gas held in storage at December 31, 2006, 2007, 2008 and 2009, respectively.

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 for the years ended December 31, 2007 and 2008 and the average prices during the year ended December 31, 2009 to 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.

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Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates.

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

The standardized measure of discounted future net cash flows by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

Total consolidated subsidiaries, joint ventures and affiliates

At December 31, 2007
Future cash inflows		47,243			30,390			73,456			48,283			42,710			4,855			11,180			3,544			261,661			7,135			268,796
Future production costs		(5,926	)		(6,759	)		(11,754	)		(9,875	)		(4,997	)		(476	)		(1,758	)		(459	)		(42,004	)		(1,249	)		(43,253	)
Future development and abandonment costs		(7,218	)		(2,653	)		(4,643	)		(3,013	)		(3,374	)		(306	)		(1,533	)		(428	)		(23,168	)		(1,721	)		(24,889	)
Future net inflow before income tax		34,099			20,978			57,059			35,395			34,339			4,073			7,889			2,657			196,489			4,165			200,654
Future income tax		(10,778	)		(14,388	)		(29,083	)		(23,083	)		(9,977	)		(1,109	)		(3,272	)		(1,003	)		(92,693	)		(2,009	)		(94,702	)
Future net cash flows		23,321			6,590			27,976			12,312			24,362			2,964			4,617			1,654			103,796			2,156			105,952
10% discount factor		(13,262	)		(1,757	)		(11,143	)		(3,953	)		(17,480	)		(718	)		(1,568	)		(913	)		(50,794	)		(1,265	)		(52,059	)
Standardized measure of discounted future net cash flows		10,059			4,833			16,833			8,359			6,882			2,246			3,049			741			53,002			891			53,893
At December 31, 2008
Future cash inflows		46,458			16,963			62,785			22,344			21,648			5,072			5,257			2,937			183,464			4,782			188,246
Future production costs		(5,019	)		(3,467	)		(10,673	)		(6,715	)		(6,273	)		(707	)		(1,657	)		(405	)		(34,916	)		(1,104	)		(36,020	)
Future development and abandonment costs		(6,805	)		(2,317	)		(6,153	)		(3,868	)		(4,842	)		(738	)		(1,022	)		(258	)		(26,003	)		(1,845	)		(27,848	)
Future net inflow before income tax		34,634			11,179			45,959			11,761			10,533			3,627			2,578			2,274			122,545			1,833			124,378
Future income tax		(11,329	)		(7,697	)		(27,800	)		(5,599	)		(2,745	)		(768	)		(232	)		(861	)		(57,031	)		(1,032	)		(58,063	)
Future net cash flows		23,305			3,482			18,159			6,162			7,788			2,859			2,346			1,413			65,514			801			66,315
10% discount factor		(13,884	)		(1,042	)		(8,639	)		(2,155	)		(6,230	)		(672	)		(672	)		(768	)		(34,062	)		(763	)		(34,825	)
Standardized measure of discounted future net cash flows		9,421			2,440			9,520			4,007			1,558			2,187			1,674			645			31,452			38			31,490
At December 31, 2009
Future cash inflows		26,243			22,057			59,413			33,676			30,273			5,680			7,088			2,973			187,403			3,718			191,121
Future production costs		(4,732	)		(6,215	)		(7,771	)		(9,737	)		(6,545	)		(1,427	)		(1,797	)		(529	)		(38,753	)		(1,251	)		(40,004	)
Future development and abandonment costs		(5,143	)		(5,375	)		(8,618	)		(5,134	)		(4,345	)		(1,409	)		(1,897	)		(214	)		(32,135	)		(1,168	)		(33,303	)
Future net inflow before income tax		16,368			10,467			43,024			18,805			19,383			2,844			3,394			2,230			116,515			1,299			117,814
Future income tax		(5,263	)		(6,621	)		(24,230	)		(9,894	)		(4,827	)		(636	)		(694	)		(563	)		(52,728	)		(432	)		(53,160	)
Future net cash flows		11,105			3,846			18,794			8,911			14,556			2,208			2,700			1,667			63,787			867			64,654
10% discount factor		(5,868	)		(1,455	)		(9,160	)		(3,102	)		(10,249	)		(520	)		(1,162	)		(771	)		(32,287	)		(610	)		(32,897	)
Standardized measure of discounted future net cash flows (a)		5,237			2,391			9,634			5,809			4,307			1,688			1,538			896			31,500			257			31,757

(1)		Eni's standardized measure of discounted future of net cash flows of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)		The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)		Amounts of 2009 do not include standardized measure of discounted future net cash flows related to the Italian gas storage activities, following the restructuring of Eni's regulated gas businesses in Italy now reported in the Gas & Power segment.

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Changes in standardized measure of discounted future net cash flows
Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2007, 2008 and 2009, are as follows:

(euro million)		Total consolidated subsidiaries		Total joint ventures and affiliates		Total consolidated subsidiaries, joint ventures and affiliates

Value at December 31, 2006		43,227			354			43,581
Increase (Decrease):
- sales, net of production costs		(20,979	)		(143	)		(21,122	)
- net changes in sales and transfer prices, net of production costs		34,999			153			35,152
- extensions, discoveries and improved recovery, net of future production and development costs		3,982			46			4,028
- changes in estimated future development and abandonment costs		(4,000	)		(73	)		(4,073	)
- development costs incurred during the period that reduced future development costs		4,682			56			4,738
- revisions of quantity estimates		(2,995	)		527			(2,468	)
- accretion of discount		7,968			50			8,018
- net change in income taxes		(17,916	)		(1,027	)		(18,943	)
- purchase of reserves in-place		3,521			929			4,450
- changes in production rates (timing) and other		513			19			532
Net increase (decrease)		9,775			537			10,312
Value at December 31, 2007		53,002			891			53,893
Increase (Decrease):
- sales, net of production costs		(26,202	)		(178	)		(26,380	)
- net changes in sales and transfer prices, net of production costs		(39,699	)		(1,254	)		(40,953	)
- extensions, discoveries and improved recovery, net of future production and development costs		1,110			10			1,120
- changes in estimated future development and abandonment costs		(6,222	)		(129	)		(6,351	)
- development costs incurred during the period that reduced future development costs		6,584			145			6,729
- revisions of quantity estimates		5,835			(61	)		5,774
- accretion of discount		10,538			201			10,739
- net change in income taxes		21,359			657			22,016
- purchase of reserves in-place		476						476
- sale of reserves in-place		25						25
- changes in production rates (timing) and other		4,646			(244	)		4,402
Net increase (decrease)		(21,550	)		(853	)		(22,403	)
Value at December 31, 2008		31,452			38			31,490
Increase (Decrease):
- sales, net of production costs		(17,752	)		(154	)		(17,906	)
- net changes in sales and transfer prices, net of production costs		4,515			286			4,801
- extensions, discoveries and improved recovery, net of future production and development costs		3,587			22			3,609
- changes in estimated future development and abandonment costs		(9,915	)		(157	)		(10,072	)
- development costs incurred during the period that reduced future development costs		7,401			208			7,609
- revisions of quantity estimates		4,686			(113	)		4,573
- accretion of discount		6,112			29			6,141
- net change in income taxes		674			(67	)		607
- purchase of reserves in-place		161						161
- sale of reserves in-place		(7	)		81			74
- changes in production rates (timing) and other		586			84			670
Net increase (decrease)		48			219			267
Value at December 31, 2009		31,500			257			31,757

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SIGNATURES

The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: April 26, 2010

 

 

 

 

 

 

 

 

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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 2009

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 Medio Oriente SpA		Italy		100.00
Eni Mediterranea Idrocarburi SpA		Italy		100.00
Eni Timor Leste SpA		Italy		100.00
Ieoc SpA		Italy		100.00
Società Adriatica Idrocarburi SpA		Italy		100.00
Società Ionica Gas SpA		Italy		100.00
Società Oleodotti Meridionali - SOM SpA		Italy		70.00
Società Padana Energia SpA		Italy		100.00
Società Petrolifera Italiana SpA		Italy		99.96
Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA		Italy		100.00
Agip Caspian Sea BV		Netherlands		100.00
Agip Energy and Natural Resources (Nigeria) Ltd		Nigeria		100.00
Agip Karachaganak BV		Netherlands		100.00
Agip Oil Ecuador BV		Netherlands		100.00
Burren Energy (Bermuda) Ltd		Bermuda		100.00
Burren Energy Congo Ltd		British Virgin Islands		100.00
Burren Energy (Egypt) Ltd		UK		100.00
Burren Energy India Ltd		UK		100.00
Burren Energy Ltd		Cyprus		100.00
Burren Energy Plc		UK		100.00
Burren Energy (Services) 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 CBM Ltd		UK		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 Gabon SA		Gabon		99.96
Eni Ganal Ltd		UK		100.00
Eni Gas & Power LNG Australia BV		Netherlands		100.00
Eni Ghana Exploration and Production Ltd		Ghana		100.00

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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 Iraq 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 TNS Ltd		UK		100.00
Eni Transportation 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
Eni Yemen Ltd (ex Burren Energy (Yemen) 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		31.98
Compagnia Napoletana di Illuminazione e Scaldamento col Gas SpA		Italy		55.40
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
GNL Italia SpA		Italy		55.57
LNG Shipping SpA		Italy		100.00
Seacom SpA		Italy		100.00
Snam Rete Gas SpA		Italy		55.57
Società EniPower Ferrara Srl		Italy		51.00
Società Italiana per il Gas pA		Italy		55.57
Stoccaggi Gas Italia SpA - Stogit SpA		Italy		55.57
Toscana Energia Clienti SpA		Italy		100.00
Travagliato Energia Srl		Italy		100.00
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana		Slovenia		51.00
Distribuidora de Gas Cuyana SA		Argentina		45.60
Distrigas NV		Belgium		100.00
Distri RE SA		Luxembourg		100.00
Eni Gas & Power Belgium SA		Belgium		100.00
Eni Gas & Power GmbH		Germany		100.00
Eni Gas Transport 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		63.33
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		100.00
Société de Service du Gazoduc Transtunisien SA - Sergaz SA		Tunisia		66.67
Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA		Tunisia		100.00
Tigáz-Dso Földgázelosztó kft		Hungary		50.08
Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság		Hungary		50.08
Transfin SA		Belgium		100.00
Trans Tunisian Pipeline Co Ltd		Channel Islands		100.00
REFINING & MARKETING
Costiero Gas Livorno SpA		Italy		65.00
Ecofuel SpA		Italy		100.00
Eni Fuel Nord SpA (ex AgipFuel Nord SpA)		Italy		100.00
Eni Rete oil&nonoil SpA (ex Agip Rete 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 Ceská Republika Sro		Czech Republic		100.00
Agip Deutschland GmbH		Germany		100.00
Agip Lubricantes SA		Argentina		100.00
Agip Romania Srl		Romania		100.00
Agip Schmiertechnik GmbH		Germany		100.00
Agip Slovenija doo		Slovenia		100.00
American Agip Co Inc		USA		100.00

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Eni Benelux BV (ex Agip Benelux BV)		Netherlands		100.00
Eni Ecuador SA (ex Agip Ecuador SA)		Ecuador		100.00
Eni France Sàrl (ex Agip France Sàrl)		France		100.00
Eni Hungaria Zrt (ex Agip Hungaria Zrt)		Hungary		100.00
Eni Iberia SLU (ex Agip Iberia SLU)		Spain		100.00
Eni Oil Ceská Republika Sro (ex Agip Oil Ceská Republika Sro)		Czech Republic		100.00
Eni Oil Slovensko Spol Sro (ex Agip Oil Slovensko Spol Sro)		Slovakia		100.00
Eni Slovensko Spol Sro (ex Agip Slovensko Spol Sro)		Slovakia		100.00
Eni Suisse SA (ex Agip Suisse SA)		Switzerland		100.00
Eni Trading & Shipping 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		43.48
Saipem Energy Services SpA		Italy		43.48
Saipem SpA		Italy		43.48
Servizi Energia Italia SpA (ex Saipem Energy Italia SpA)		Italy		43.48
Snamprogetti Chiyoda SAS di Saipem SpA		Italy		43.44
Andromeda Consultoria Tecnica e Representações Ltda		Brazil		43.48
BOSCONGO SA		Congo		43.48
BOS Investment Ltd		UK		43.48
BOS - UIE Ltd		UK		43.48
Entreprise Nouvelle Marcellin SA		France		43.48
ER SAI Caspian Contractor Llc		Kazakhstan		21.74
ERS - Equipment Rental & Services BV		Netherlands		43.48
European Marine Contractors Ltd (in liquidation)		UK		43.48
European Marine Investments Ltd (in liquidation)		UK		43.48
European Maritime Commerce BV		Netherlands		43.48
Global Petroprojects Services AG		Switzerland		43.48
Katran-K Llc		Russia		43.48
Moss Maritime AS		Norway		43.48
Moss Maritime Inc		USA		43.48
Moss Offshore AS		Norway		43.48
North Caspian Service Co		Kazakhstan		43.48
Petrex SA		Peru		43.48
Petromar Lda		Angola		30.44
PT Saipem Indonesia		Indonesia		43.48
Saigut SA De Cv		Mexico		43.48
Saimexicana SA De Cv		Mexico		43.48
Saipem America Inc		USA		43.48
Saipem Asia Sdn Bhd		Malaysia		43.48
Saipem (Beijing) Technical Services Co Ltd		China		43.48
Saipem Contracting Algerie SpA		Algeria		43.48
Saipem Contracting (Nigeria) Ltd		Nigeria		42.59
Saipem Discoverer Invest Sàrl (ex Frigstad Discoverer Invest Ltd)		Luxembourg		43.48
Saipem do Brasil Serviçõs de Petroleo Ltda		Brazil		43.48
Saipem Drilling Co Private Ltd (ex Saipem Aban Drilling Co Private Ltd)		India		43.48
Saipem Holding France SAS		France		43.48
Saipem India Projects Ltd		India		43.48
Saipem International BV		Netherlands		43.48

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Saipem Luxembourg SA		Luxembourg		43.48
Saipem (Malaysia) Sdn Bhd		Malaysia		17.99
Saipem Maritime Asset Management Luxembourg Sàrl		Luxembourg		43.48
Saipem Mediteran Usluge doo		Croatia		43.48
Saipem Misr for Petroleum Services SAE		Egypt		43.48
Saipem (Nigeria) Ltd		Nigeria		38.88
Saipem Perfurações e Construções Petrolíferas Unipessoal Lda		Portugal		43.48
Saipem (Portugal) Comércio Marítimo. Sociedade Unipessoal Lda		Portugal		43.48
Saipem (Portugal) - Gestão de Participações SGPS Sociedade Unipessoal SA		Portugal		43.48
Saipem SA		France		43.48
Saipem Services México SA De Cv		Mexico		43.48
Saipem Services SA		Belgium		43.48
Saipem Singapore Pte Ltd		Singapore		43.48
Saipem UK Ltd		UK		43.48
Saipem Ukraine Llc		Ukraine		43.48
SAS Port de Tanger		France		43.48
Saudi Arabian Saipem Ltd		Saudi Arabia		26.09
Sigurd Rück AG		Switzerland		43.48
Snamprogetti Canada Inc		Canada		43.48
Snamprogetti Engineering BV		Netherlands		43.48
Snamprogetti France Sàrl		France		43.48
Snamprogetti Ltd		UK		43.48
Snamprogetti Lummus Gas Ltd		Malta		43.05
Snamprogetti Netherlands BV		Netherlands		43.48
Snamprogetti Romania Srl		Romania		43.48
Snamprogetti Saudi Arabia Co Ltd Llc		Saudi Arabia		43.48
Société de Construction d'Oleoducs Snc		France		43.48
Sofresid Engineering SA		France		43.48
Sofresid SA		France		43.48
Sonsub AS		Norway		43.48
Sonsub International Pty Ltd		Australia		43.48
Sonsub Ltd (in liquidation)		UK		43.48
Star Gulf FZ Co		United Arab Emirates		43.48
Varisal - Serviços de Consultadoria e Marketing Unipessoal Lda
(ex Varisal - Serviços de Consultadoria e Marketing Lda)		Portugal		43.48
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 Administration & Financial Service SpA
(ex Società Finanziamenti Idrocarburi - Sofid - SpA)		Italy		99.62
Eni Corporate University SpA		Italy		100.00
EniServizi SpA		Italy		100.00
Serfactoring SpA		Italy		48.81
Servizi Aerei SpA		Italy		100.00
Banque Eni SA		Belgium		100.00
Eni Coordination Center SA		Belgium		100.00
Eni Finance USA Inc		USA		100.00
Eni Insurance Ltd		Ireland		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: April 26, 2010

 

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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: April 26, 2010

 

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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, 2009 (the "Report") fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 26, 2010

 

 

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, 2009 (the "Report") fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 26, 2010

 

 

The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act.

 

 

 

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EXHIBIT 15.a(i)

 

 

DeGolyer And MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

 

 

March 18, 2010

 

 

 

Eni S.p.A.
E&P Division
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

 

 

We hereby consent to references to DeGolyer and MacNaughton in the sections entitled "Part I - Item 4 Business Overview-Exploration and Production" and "Part III - Item 18 Financial Statement-Supplemental Oil and Gas Information" within the Annual Report on Form 20-F for the year ended December 31, 2009, of Eni S.p.A. (the Form 20-F) and to the inclusion of our letter dated November 6, 2009, regarding our statements pertaining to internal reserves guidelines of Eni S.p.A. and our third-party letter report dated February 26, 2010, concerning properties in Algeria, Angola, Congo, Egypt, and the United Kingdom, relating to our evaluation of certain oil and gas properties of Eni S.p.A., which are included as exhibits in the Form 20-F.

 

	Very truly yours,
	/s/ DEGOLYER AND MACNAUGHTON
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

 

 

 

 

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EXHIBIT 15.a(ii)

 

 

 

March 8, 2010

 

Eni S.p.A
E&P Division
Ms. Manuela Feudaroli
Vice President Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Dear Ms. Feudaroli:

Ryder Scott Company, L.P. confirms its independence with respect to Eni S.p.A. and hereby consents to the references to Ryder Scott Company, L.P. and the inclusion of its report dated February 23, 2010 and information thereof in Eni S.p.A's annual report on Form 20-F for the year ended December 31, 2009 and other filings as required to fulfill Italian and U.S.A. obligations.

 

	Very truly yours,
	RYDER SCOTT COMPANY, L. P.
	TBPE Firm Registration No. F-1580
	/s/ HERMAN G. ACUÑA
	Herman G. Acuña, P.E.
	TBPE License No. 92254
	Managing Senior Vice President-International

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EXHIBIT 15.a(iii)

 

 

DeGolyer And MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

 

 

 

 

 

 

This is a digital representation of a DeGolyer and MacNaughton report.

 

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

 

 

 

 

 

 

 

 

 

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DeGolyer And MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

 

February 26, 2010

 

 

 

 

 

 

Eni S.p.A.
E&P Division
Ms. Manuela Feudaroli
Vice President, Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

 

Dear Ms. Feudaroli:

 

Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved crude oil, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2009, of certain properties in Algeria, Angola, Congo, Egypt, and the United Kingdom owned by Eni S.p.A. (Eni). Eni has represented that these properties account for 21 percent, on a net equivalent barrel basis, of Eni's net proved reserves as of December 31, 2009, and that Eni's net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Eni that it represents to be Eni's estimates of the net reserves, as of December 31, 2009, for the same properties as those which we have independently evaluated.

Reserves included herein are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Eni after deducting interests owned by others.

Estimates of oil, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is

 

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currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Eni personnel, Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

 

Methodology and Procedures

Our estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

 

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For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate.

 

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Reserves classifications used for our estimates of proved reserves are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. Eni has represented that its estimates of proved reserves are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered

 

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by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a)

 

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Definitions], or by other evidence using reliable technology establishing reasonable certainty.

 

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil and NGL Prices

Eni has represented that the oil and NGL prices were based on a 12-month average price (reference price), calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Eni supplied appropriate differentials by field to the relevant reference prices and the prices were held constant thereafter.

Natural Gas Prices

Eni has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Eni supplied appropriate differentials by field to the relevant reference prices and the prices were held constant thereafter.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Eni, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

 

 

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While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2009, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Algeria, Angola, Congo, Egypt, and the United Kingdom are based on the definitions of proved reserves of the SEC. Eni represents that its estimates of the net proved reserves attributable to these properties, which represent 21 percent of Eni's reserves on a net equivalent basis, are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

 

In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us, with tolerance of 5 percent or less.

 

 

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni and should not be used for purposes other than those for which it is intended. DeGolyer and MacNaughton has used all procedures and methods that it considers necessary to prepare this report.

 

	Submitted,
	/s/ DEGOLYER AND MACNAUGHTON
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

	/s/ LLOYD W. CADE, P.E.
	Lloyd W. Cade, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

 

 

 

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CERTIFICATE of QUALIFICATION

I, Lloyd W. Cade Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.		That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Eni dated February 26, 2010, and that I, as Senior Vice President, was responsible for the preparation of this report.
2.		That I attended Kansas State University, and that I graduated with a Bachelor of Science degree in Mechanical Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have approximately twenty-seven (27) years of experience in oil and gas reservoir studies and reserves evaluations.

 

 

 

SIGNED: February 26, 2010

 

 

 

	/s/ LLOYD W. CADE, P.E.
	Lloyd W. Cade, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

 

 

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EXHIBIT 15.a(iv)

 

Eni S.p.A.

 

 

 

Estimated

Future Reserves

Attributable to Certain Interests

 

 

 

 

SEC Parameters

 

As of

December 31, 2009

/s/HERMAN G. ACUÑA, P.E.

Herman G. Acuña, P.E.
TBPE License No. 92254
Managing Senior vice President-International

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580

 

 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

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February 23, 2010

 

Eni S.p.A.
E&P Division
Ms. Manuela Feudaroli
Vice President Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

Dear Ms. Feudaroli:

At your request, Ryder Scott Company has prepared an estimate of the proved reserves, future production and income attributable to certain properties of ENI S.p.A., as of December 31, 2009. The subject properties are located in the countries of:

The reserves and income data were estimated based on the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The conclusions of our third party study, completed on January 25, 2010, are discussed herein.

The conclusions discussed in this report, as of December 31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, the conclusions of our third party study may differ significantly from the discussion below.

ENI S.p.A. has elected to represent that Ryder Scott Company conducted these 3^rd party independent estimations; accordingly, Ryder Scott Company has prepared this report for inclusion as an exhibit to the relevant registration statement or other Commission filings by ENI S.p.A.

 

Scope of 3^rd Party Independent Audit

At the request of ENI S.p.A., Ryder Scott Company conducted an independent estimation of the reserves, future production and income associated with certain assets in which ENI S.p.A. owns an interest. Ryder Scott Company was provided with both interpreted and uninterpreted data. Based on this information, Ryder Scott Company conducted the necessary studies to estimate and audit the proved reserves to render the opinions expressed herein conforming with our understanding of the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions is included as an attachment to this report. Furthermore, ENI S.p.A. has requested that we

 

 

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February 23, 2010
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compare the proved reserves independently evaluated by us to the reserves prepared by ENI S.p.A. according to the SEC regulations to fulfill the scope of the audit.

During our investigations, no attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. ENI S.p.A. includes fuel gas in their estimation of net reserves, therefore, our conclusion herein are inclusive of these volumes.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. However, most of the parameters that define the reserves of a reservoir cannot be measured directly, and must be estimated indirectly through geologic and reservoir engineering analysis and interpretations. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts.

The conclusion reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to ENI S.p.A. for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with ENI S.p.A. the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information or our acceptance of ENI S.p.A.'s representations regarding such contractual information should be construed as a legal or accounting opinion on this matter.

Ryder Scott did not evaluate country and geopolitical risks in the countries where ENI S.p.A. operates or has interests. ENI S.p.A.'s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The conclusions presented herein were based upon a detailed study of the properties in which ENI S.p.A. owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

 

 

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The properties reviewed by Ryder Scott Company are located in the following countries and do not represent the entire asset portfolio from ENI S.p.A.

ENI S.p.A. has indicated that the proved net reserves attributable to the properties that we reviewed account for 6.5 percent of their total proved net remaining hydrocarbon reserves.

 

Data, Methods and Procedures

In performing our estimates, we have relied upon data furnished by ENI S.p.A. with respect to property interests owned, production and well tests from examined wells, historical costs of operation and development, product prices, geological structural and isochore maps. well logs, core analyses, and pressure measurements, etc. In general, the reserve estimates for the properties that we reviewed are based on data available through December 31, 2009.

These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information a reserves audit is defined as "the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities."

The reserves included herein were estimated using generally accepted petroleum engineering and evaluation principles for the estimation of future reserves. In general, these reserves were estimated by performance methods, volumetric or material balance methods; however, other methods were used in certain cases where characteristics of the data, in our opinion, indicated such other methods were more appropriate.

Our forecasts of future production rates are based on historical performance from wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by ENI S.p.A. The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates.

To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly,

 

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economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the report.

As previously stated, the hydrocarbon prices used herein are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

ENI S.p.A. has informed us that the operating costs for the assets in this report are based on the operating expense reports of ENI S.p.A. and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the assets. When applicable for operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets. Development costs were furnished to us by ENI S.p.A. and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage was significant. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by ENI S.p.A.

 

Summary of Ryder Scott Company Conclusions

In our opinion, ENI S.p.A.'s estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves and we found no bias in the utilization and analysis of data in estimates for these properties.

In our opinion, the information relating to estimated proved reserves prepared by ENI S.p.A.'s have been prepared in accordance with Extractive Industries, Oil and Gas (Topic 932) of the Financial Accounting Standards Boards and Rules 4-10(a) of regulation S-X and rules 302(b) and 1201, 1202, 1203(a) of regulation S-K of the SEC.

Ryder Scott found both positive and negative differences between the proved reserves estimated by us and by ENI S.p.A. The overall proved reserves for the reviewed properties as estimated by ENI S.p.A. are, in the aggregate, not materially different than those prepared by Ryder Scott Company with a tolerance equal or less than five percent (5%).

 

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a

 

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Eni S.p.A.
February 23, 2010
Page 5

 

material portion of our annual revenue. We do not serve as officers or directors of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to ENI S.p.A. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing this project, are included as an attachment to this letter.

 

Terms of Usage

This report was prepared for the exclusive use and sole benefit of ENI S.p.A. Company and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

 

	Very truly yours,
	RYDER SCOTT COMPANY, L. P.
	TBPE Firm Registration No. F-1580
	/s/ HERMAN G. ACUÑA
	Herman G. Acuña, P.E.
	TBPE License No. 92254
	Managing Senior Vice President-International

 

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Professional Qualifications
Herman G. Acuña

The conclusions presented in the report issued on February 23, 2010 for Eni S.p.A. are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the independent estimation of the reserves, future production and income to render the audit conclusions of that report.

Mr. Acuña, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1997, is a Managing Senior International Vice President and serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña's geographic and job specific experience, please refer to the Ryder Scott Company website at
www. ryderscott. com/Experience/Employees.

Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas, a member of the Association of International Petroleum Negotiators (Al PN) and the Society of Petroleum Engineers (SPE).

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. As part of his 2009 continuing education hours, Mr. Acuña attended over 34 hours of formalized training and conferences including 10 hours dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. In 2009, Mr. Acuña taught various company reserves evaluation schools in Argentina, Bolivia, China, Spain, U.S.A. and Venezuela. Mr. Acuña has participated in various capacities in reserves conferences such as being a panelist a the 2008 Trinidad and Tobago's Petroleum Conference, delivering the reserves evaluation seminar during IAPG convention in Mendoza, Argentina in 2006 and chairing the first Reserves Evaluation Conference in the Middle East in Dubai, U.A.E. in 2006.

Based on his educational background, professional training and 20 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

 

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission ("the Commission") published the "Modernization of Oil and Gas Reporting; Final Rule" in the Federal Register of National Archives and Records Administration (NARA). The "Modernization of Oil and Gas Reporting; Final Rule" includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The "Modernization of Oil and Gas Reporting; Final Rule", including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the "SEC Regulations". The SEC Regulations take effect with all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10 (a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.102 (5).

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

 

 

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RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a) (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

 

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

 

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based: and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.
Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17) (iv) and (a)(17) (vi) of this section.

 

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (17) defines possible oil and gas reserves as follows:

 

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Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identity directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore. and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

 

 

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

 

 

Reserves status categories define the development and producing status of wells and reservoirs.

 

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well:
and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

 

 

 

 

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Shut-In
Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing;
(2) wells which were shut-in for market conditions or pipeline connections; or
(3) wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

In all cases. production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

 

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances. justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a) (2) of this section. or by other evidence using reliable technology establishing reasonable certainty.

 

 

 

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EXHIBIT 15.a(v)

 

DeGolyer And MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

 

November 6, 2009

 

 

Mr. Lorenzo Acquati
Reserves Guidelines Coordinator
Eni E&P Division
Via Emilia, 1
20097 San Donato Milanese (MI)
ITALY

Dear Mr. Acquati:

Pursuant to your request, DeGolyer and MacNaughton has reviewed the document entitled "Eni S.p.A. Exploration and Production Division: Division Directive for Evaluation, Classification, and Reporting of Petroleum Reserves and Contingent Resources; November 4, 2009." The document was provided electronically to DeGolyer and MacNaughton on November 5, 2009.

The document is represented as being based on research of the requirements (2008 Release) of the United States Securities and Exchange Commission (SEC) and the Petroleum Resources Management System (PRMS) approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers, as they apply to reserves and contingent resources classification, categorization, estimating, and reporting. It is observed that, throughout the document, language directly from SEC regulations, as well as PRMS, has been used. Where specific language from SEC rules or PRMS did not apply, typical industry standards have been utilized. It should be noted that the SEC has not commented on the PRMS and has not endorsed any specific methodology for determining reserves, nor has the SEC made any references to estimating contingent resources.

In our opinion, the referenced document presents guidelines for preparing estimates of proved, probable, and possible reserves that, if followed, would result in reporting reserves as specified in Rules 4-10(a)(1)-(32) of Regulation S-X and Rule 302(b) of Regulation S-K of the SEC and paragraphs 10-13 and 15 of the Statement of Financial Accounting Standards No. 69 (November 1982) of the

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Financial Accounting Standards Board (FASB). This opinion is based on our review of the document and our understanding of how the guidelines will be applied from discussions with Eni. The document addresses situations where SEC rules are less specific in a reasonable manner and provides guidance that is aligned with SEC standards and general industry practice.

Due to the recent implementation of the 2008 release of the SEC rules, there are a number of issues that are due for additional commentary and clarification by the SEC and its staff. However, that additional information is not yet available and may not be until well into the next calendar year. As such, the comments herein regarding compliance are applicable to prevailing conditions, interpretations, and public commentary at the date of this document. Thus, any such interpretations and implementation opinions are, particularly at this juncture in the application of the new SEC rules, subject to review and reconsideration pending any future public comments from the SEC staff.

It is also our opinion, that the referenced document presents guidelines for preparing estimates of contingent resources that, if followed, would result in volumes in accordance with the PRMS published and approved in 2007. This opinion is based on our review of the document and our understanding of how the guidelines will be applied from discussions with Eni.

To the extent that the document requires determinations of an accounting or legal nature, DeGolyer and MacNaughton is necessarily unable to express an opinion.

 

 

	Submitted,
	/s/ DEGOLYER AND MACNAUGHTON
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

 

 

 

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EXHIBIT 16.f

 

 

April 26, 2010

Securities and Exchange Commission
100 F Street, N.E.
Washington, DC 20549

Ladies and Gentlemen:

We have read the statements made by Eni SpA (copy attached), pursuant to Item 16F(a) of Form 20-F, as part of the Annual Report on Form 20-F of the Company for the year ended December 31, 2009, which we understand will be filed by the Company with the Securities and Exchange Commission. We agree with such statements.

Very truly yours,

/s/ PricewaterhouseCoopers SpA

 

 

 

 

 

 

 

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